|
| | | | | | | | | | | | | | | | |
2016 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | (In Millions) |
Assets: | | | | | | | | |
Temporary cash investments | |
| $5.0 |
| |
| $— |
| |
| $— |
| |
| $5.0 |
|
Securitization recovery trust account | | 37.5 |
| | — |
| | — |
| | 37.5 |
|
Financial transmission rights | | — |
| | — |
| | 3.1 |
| | 3.1 |
|
| |
| $42.5 |
| |
| $— |
| |
| $3.1 |
| |
| $45.6 |
|
System Energy
|
| | | | | | | | | | | | | | | | |
2017 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | (In Millions) |
Assets: | | | | | | | | |
Temporary cash investments | |
| $287.1 |
| |
| $— |
| |
| $— |
| |
| $287.1 |
|
Decommissioning trust funds (a): | | | | | | | | |
Equity securities | | 3.1 |
| | — |
| | — |
| | 3.1 |
|
Debt securities | | 187.2 |
| | 143.3 |
| | — |
| | 330.5 |
|
Common trusts (b) | | | | | | | | 572.1 |
|
| |
| $477.4 |
| |
| $143.3 |
| |
| $— |
| |
| $1,192.8 |
|
|
| | | | | | | | | | | | | | | | |
2016 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | (In Millions) |
Assets: | | | | | | | | |
Temporary cash investments | |
| $245.1 |
| |
| $— |
| |
| $— |
| |
| $245.1 |
|
Decommissioning trust funds (a): | | | | | | | | |
Equity securities | | 0.3 |
| | — |
| | — |
| | 0.3 |
|
Debt securities | | 248.3 |
| | 58.3 |
| | — |
| | 306.6 |
|
Common trusts (b) | | | | | | | | 473.6 |
|
| |
| $493.7 |
| |
| $58.3 |
| |
| $— |
| |
| $1,025.6 |
|
| |
(a) | The decommissioning trust funds hold equity and fixed income securities. Equity securities are invested to approximate the returns of major market indices. Fixed income securities are held in various governmental and corporate securities. See Note 9 to the financial statements for additional information on the investment portfolios. |
| |
(b) | Common trust funds are not publicly quoted, and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. The fund administrator of these investments allows daily trading at the net asset value and trades settle at a later date. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
System Energy
| | | | | | | | | | | | | | | | | | | | | | | | | | |
2020 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | (In Millions) |
Assets: | | | | | | | | |
Temporary cash investments | | $216.4 | | | $0 | | | $0 | | | $216.4 | |
Decommissioning trust funds (a): | | | | | | | | |
Equity securities | | 3.8 | | | 0 | | | 0 | | | 3.8 | |
Debt securities | | 177.3 | | | 250.4 | | | 0 | | | 427.7 | |
Common trusts (b) | | | | | | | | 784.4 | |
| | $397.5 | | | $250.4 | | | $0 | | | $1,432.3 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
2019 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | (In Millions) |
Assets: | | | | | | | | |
Temporary cash investments | | $68.4 | | | $0 | | | $0 | | | $68.4 | |
Decommissioning trust funds (a): | | | | | | | | |
Equity securities | | 13.3 | | | 0 | | | 0 | | | 13.3 | |
Debt securities | | 176.3 | | | 209.9 | | | 0 | | | 386.2 | |
Common trusts (b) | | | | | | | | 654.6 | |
| | $258.0 | | | $209.9 | | | $0 | | | $1,122.5 | |
(a)The decommissioning trust funds hold equity and fixed income securities. Equity securities are invested to approximate the returns of major market indices. Fixed income securities are held in various governmental and corporate securities. See Note 16 to the financial statements herein for additional information on the investment portfolios.
(b)Common trust funds are not publicly quoted and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. The fund administrator of these investments allows daily trading at the net asset value and trades settle at a later date.
The following table sets forth a reconciliation of changes in the net assets for the fair value of derivatives classified as Level 3 in the fair value hierarchy for the year ended December 31, 2020.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| (In Millions) |
| | | | | | | | | |
Balance as of January 1, 2020 | $3.3 | | | $4.5 | | | $0.8 | | | $0.3 | | | $0.9 | |
Issuances of financial transmission rights | 6.5 | | | 13.2 | | | 1.4 | | | (0.1) | | | 2.4 | |
Gains (losses) included as a regulatory liability/asset | 19.6 | | | 6.1 | | | 1.4 | | | 1.3 | | | 38.7 | |
Settlements | (26.7) | | | (19.6) | | | (3.0) | | | (1.4) | | | (40.4) | |
Balance as of December 31, 2020 | $2.7 | | | $4.2 | | | $0.6 | | | $0.1 | | | $1.6 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The following table sets forth a reconciliation of changes in the net assets (liabilities) for the fair value of derivatives classified as Level 3 in the fair value hierarchy for the year ended December 31, 2017.2019.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| (In Millions) |
| | | | | | | | | |
Balance as of January 1, 2019 | $3.4 | | | $8.3 | | | $2.2 | | | $1.3 | | | ($0.5) | |
Issuances of financial transmission rights | 9.6 | | | 18.7 | | | 3.9 | | | 2.7 | | | 0.1 | |
Gains (losses) included as a regulatory liability/asset | 12.6 | | | 24.2 | | | 1.5 | | | (1.0) | | | 17.0 | |
Settlements | (22.3) | | | (46.7) | | | (6.8) | | | (2.7) | | | (15.7) | |
Balance as of December 31, 2019 | $3.3 | | | $4.5 | | | $0.8 | | | $0.3 | | | $0.9 | |
|
| | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana |
| Entergy Mississippi |
| Entergy New Orleans |
| Entergy Texas |
| (In Millions) |
| | |
|
|
|
|
|
|
|
|
|
|
|
Balance as of January 1, |
| $5.4 |
| |
| $8.5 |
| |
| $3.2 |
| |
| $1.1 |
| |
| $3.1 |
|
Issuances of financial transmission rights | 8.9 |
| | 31.0 |
| | 9.6 |
| | 5.0 |
| | 7.1 |
|
Gains (losses) included as a regulatory liability/asset | 30.4 |
| | 16.5 |
| | 8.2 |
| | 5.2 |
| | 15.5 |
|
Settlements | (41.7 | ) | | (45.8 | ) | | (18.9 | ) | | (9.1 | ) | | (22.3 | ) |
Balance as of December 31, |
| $3.0 |
| |
| $10.2 |
| |
| $2.1 |
| |
| $2.2 |
| |
| $3.4 |
|
The following table sets forth a reconciliation of changes in the net assets (liabilities) for the fair value of derivatives classified as Level 3 in the fair value hierarchy for the year ended December 31, 2016.
|
| | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| (In Millions) |
| | | | | | | | | |
Balance as of January 1, |
| $7.9 |
| |
| $8.5 |
| |
| $2.4 |
| |
| $1.5 |
| |
| $2.2 |
|
Issuances of financial transmission rights | 18.8 |
| | 18.1 |
| | 5.9 |
| | 2.8 |
| | 9.3 |
|
Gains included as a regulatory liability/asset | 1.9 |
| | 51.6 |
| | 11.5 |
| | 0.9 |
| | 1.8 |
|
Settlements | (23.2 | ) | | (69.7 | ) | | (16.6 | ) | | (4.1 | ) | | (10.2 | ) |
Balance as of December 31, |
| $5.4 |
| |
| $8.5 |
| |
| $3.2 |
| |
| $1.1 |
| |
| $3.1 |
|
NOTE 16. DECOMMISSIONING TRUST FUNDS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)
Entergy holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The NRC requires Entergy subsidiaries to maintain nuclear decommissioning trusts to fund the costs of decommissioning ANO 1, ANO 2, River Bend, Waterford 3, Grand Gulf, Pilgrim, Indian Point 1, Indian Point 2, Indian Point 3, Vermont Yankee, and Palisades. TheEntergy’s nuclear decommissioning trust funds are invested primarilyinvest in equity securities, fixed-rate debt securities, and cash and cash equivalents.
For the Indian Point 3 and FitzPatrick plants purchased in 2000 from NYPA, NYPA retained the decommissioning trust funds and the decommissioning liabilities. NYPA and Entergy subsidiaries executed decommissioning agreements, which specified their decommissioning obligations. At the time of the acquisition of the plants Entergy recorded a contract asset that represented an estimate of the present value of the difference between the stipulated contract amount for decommissioning the plants less the decommissioning costs estimated in independent decommissioning cost studies.
In August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy. The transaction
Entergy Corporation and Subsidiaries
Notes to Financial Statements
was contingent upon receiving approval from the NRC, which was received in January 2017. As a result of the agreement with NYPA, in the third quarter 2016, Entergy removed the contract asset from its balance sheet, and recorded receivables for the beneficial interests in the decommissioning trust funds and recorded asset retirement obligations for the decommissioning liabilities. At December 31, 2016, the fair values of the decommissioning trust funds held by NYPA were $719 million for the Indian Point 3 plant and $785 million for the FitzPatrick plant. The fair values were based on the trust statements received from NYPA and were valued by the fund administrator using net asset value as a practical expedient. Accordingly, these funds were not assigned a level in the fair value hierarchy. For Indian Point 3, the receivable for the beneficial interest in the decommissioning trust fund was recorded in other deferred debits on the consolidated balance sheet as of December 31, 2016. For FitzPatrick, the receivable for the beneficial interest in the decommissioning trust fund was classified as held for sale within other deferred debits on the consolidated balance sheet as of December 31, 2016. In January 2017, NYPA transferred to Entergy the Indian Point 3 decommissioning trust funds with a fair value of $726 million and the FitzPatrick decommissioning trust fund with a fair value of $793 million. In March 2017, Entergy closed on the sale of the FitzPatrick plant to Exelon. As part of the transaction, Entergy transferred the FitzPatrick decommissioning trust fund to Exelon. The FitzPatrick decommissioning trust fund had a disposition-date fair value of $805 million. See Note 9 to the financial statements for further discussion of the decommissioning agreements with NYPA and see Note 14 to the financial statements for further discussion of the sale of FitzPatrick.
Entergy records decommissioning trust funds on the balance sheet at their fair value. Because of the ability of the Registrant Subsidiaries to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, the Registrant Subsidiaries have recorded an offsetting amount of unrealized gains/(losses) on investment securities in other regulatory liabilities/assets. For the 30% interest in River Bend formerly owned by Cajun, Entergy Louisiana records an offsetting amount in other deferred credits for the excessunrealized trust earnings not currently expected to be needed to decommission the plant. Decommissioning trust funds for Pilgrim, Indian Point 1, Indian Point 2, Indian Point 3, Vermont Yankee, and Palisadesthe Entergy Wholesale Commodities nuclear plants do not meet the criteria for regulatory accounting treatment. Accordingly, unrealized gains/(losses) recorded on the equity securities in the trust funds are recognized in earnings. Unrealized gains recorded on the assetsavailable-for-sale debt securities in thesethe trust funds are recognized in the accumulated other comprehensive income component of shareholders’ equity because these assets are classified as available for sale.equity. Unrealized losses (where cost exceeds fair market value) on the assetsavailable-for-sale debt securities in thesethe trust funds are also recorded in the accumulated other comprehensive income component of shareholders’ equity unless the unrealized loss is other than temporary and therefore recorded in earnings. A portion of Entergy’s decommissioning trust funds were held in a wholly-owned registered investment company, and unrealized gains and losses on both the equity and debt securities held in the registered investment company were recognized in earnings. In December 2020, Entergy liquidated its interest in the registered investment company. Generally, Entergy records realized gains and losses on its debt and equity securities using the specific identification method to determine the cost basis of its securities.
The unrealized gains/(losses) recognized during the year ended December 31, 2020 on equity securities still held as of December 31, 2017 and 2016 are summarized as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | 2017 | | 2016 |
| | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | (In Millions) |
Equity Securities | |
| $4,662 |
| |
| $2,131 |
| |
| $1 |
| |
| $3,511 |
| |
| $1,673 |
| |
| $1 |
|
Debt Securities | | 2,550 |
| | 44 |
| | 16 |
| | 2,213 |
| | 34 |
| | 27 |
|
Total | |
| $7,212 |
| |
| $2,175 |
| |
| $17 |
| |
| $5,724 |
| |
| $1,707 |
| |
| $28 |
|
The fair values of the decommissioning trust funds related to the Entergy Wholesale Commodities nuclear plants as of December 31, 2017 are $491 million for Indian Point 1, $621 million for Indian Point 2, $798 million for Indian Point 3, $458 million for Palisades, $1,068 million for Pilgrim, and $613 million for Vermont Yankee. The fair values of the decommissioning trust funds related to the Entergy Wholesale Commodities nuclear plants as of December 31, 2016 are $443 million for Indian Point 1, $564 million for Indian Point 2, $412 million for Palisades, $960 million for Pilgrim, and $584 million for Vermont Yankee. The fair values of the decommissioning trust funds for the Registrant Subsidiaries’ nuclear plants are detailed below.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Deferred taxes on unrealized gains/(losses) are recorded in other comprehensive income (loss) for the decommissioning trusts which do not meet the criteria for regulatory accounting treatment as described above. Unrealized gains/(losses) above are reported before deferred taxes of $479 million and $399 million as of December 31, 2017 and 2016, respectively. The amortized cost of debt securities was $2,539 million as of December 31, 2017 and $2,212 million as of December 31, 2016. As of December 31, 2017, the debt securities have an average coupon rate of approximately 3.24%, an average duration of approximately 6.33 years, and an average maturity of approximately 9.99 years.2020 were $531 million. The equity securities are generally held in funds that are designed to approximate or somewhat exceed the return of the Standard & Poor’s 500 Index. A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Indexindex or the Russell 3000 Index. The debt securities are generally held in individual government and credit issuances.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The available-for-sale securities held as of December 31, 2020 and 2019 are summarized as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | (In Millions) |
2020 | | | | | | |
Debt Securities (a) | | $2,617 | | | $197 | | | $3 | |
| | | | | | |
2019 | | | | | | |
Debt Securities (a) | | $2,456 | | | $96 | | | $6 | |
(a) Debt securities presented herein do not include the $507 million of debt securities held in the wholly-owned registered investment company as of December 31, 2019, which are not accounted for as available-for-sale.
The unrealized gains/(losses) above are reported before deferred taxes of $31 million as of December 31, 2020 and $13 million as of December 31, 2019 for debt securities. The amortized cost of available-for-sale debt securities was $2,423 million as of December 31, 2020 and $2,366 million as of December 31, 2019. As of December 31, 2020, available-for-sale debt securities have an average coupon rate of approximately 3.01%, an average duration of approximately 7.36 years, and an average maturity of approximately 10.72 years.
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 20172020:
| | | | | | | | | | | |
| Fair Value | | Gross Unrealized Losses |
| (In Millions) |
Less than 12 months | $187 | | | $3 | |
More than 12 months | 2 | | | 0 | |
Total | $189 | | | $3 | |
The fair value and 2016:gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2019:
| | | | | | | | | | | |
| Fair Value | | Gross Unrealized Losses |
| (In Millions) |
Less than 12 months | $404 | | | $5 | |
More than 12 months | 38 | | | 1 | |
Total | $442 | | | $6 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2017 | | 2016 |
| Equity Securities | | Debt Securities | | Equity Securities | | Debt Securities |
| Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| (In Millions) |
Less than 12 months |
| $8 |
| |
| $1 |
| |
| $1,099 |
| |
| $7 |
| |
| $23 |
| |
| $1 |
| |
| $1,169 |
| |
| $26 |
|
More than 12 months | — |
| | — |
| | 265 |
| | 9 |
| | 1 |
| | — |
| | 20 |
| | 1 |
|
Total |
| $8 |
| |
| $1 |
| |
| $1,364 |
| |
| $16 |
| |
| $24 |
| |
| $1 |
| |
| $1,189 |
| |
| $27 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair value of available-for-sale debt securities, summarized by contractual maturities, as of December 31, 20172020 and 20162019 are as follows:
| | | | | | | | | | | |
| 2020 | | 2019 |
| (In Millions) |
Less than 1 year | ($4) | | | $128 | |
1 year - 5 years | 672 | | | 807 | |
5 years - 10 years | 852 | | | 666 | |
10 years - 15 years | 377 | | | 125 | |
15 years - 20 years | 144 | | | 126 | |
20 years+ | 576 | | | 604 | |
Total | $2,617 | | | $2,456 | |
|
| | | | | | | |
| 2017 | | 2016 |
| (In Millions) |
less than 1 year |
| $74 |
| |
| $125 |
|
1 year - 5 years | 902 |
| | 763 |
|
5 years - 10 years | 812 |
| | 719 |
|
10 years - 15 years | 147 |
| | 109 |
|
15 years - 20 years | 100 |
| | 73 |
|
20 years+ | 515 |
| | 424 |
|
Total |
| $2,550 |
| |
| $2,213 |
|
During the years ended December 31, 2017, 2016,2020, 2019, and 2015,2018, proceeds from the dispositions of available-for-sale securities amounted to $3,163$1,024 million, $2,409$1,427 million, and $2,492$2,406 million, respectively. During the years ended December 31, 2017, 2016,2020, 2019, and 2015,2018, gross gains of $149$47 million, $32$25 million, and $72$7 million, respectively, and gross losses of $13$4 million, $13$4 million, and $13$47 million, respectively, related to available-for-sale securities were reclassified out of other comprehensive income or other regulatory liabilities/assets into earnings.
The fair values of the decommissioning trust funds related to the Entergy Wholesale Commodities nuclear plants as of December 31, 2020 are $631 million for Indian Point 1, $794 million for Indian Point 2, $991 million for Indian Point 3, and $554 million for Palisades. The fair values of the decommissioning trust funds related to the Entergy Wholesale Commodities nuclear plants as of December 31, 2019 are $556 million for Indian Point 1, $701 million for Indian Point 2, $930 million for Indian Point 3, and $498 million for Palisades. The fair values of the decommissioning trust funds for the Registrant Subsidiaries’ nuclear plants are detailed below.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas
Entergy Arkansas holds debt and equity securities classified asand available-for-sale debt securities in nuclear decommissioning trust accounts. The available-for-sale securities held as of December 31, 20172020 and 20162019 are summarized as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | (In Millions) |
2020 | | | | | | |
Debt Securities | | $447.9 | | | $27.7 | | | $0.3 | |
| | | | | | |
2019 | | | | | | |
Debt Securities | | $412.8 | | | $9.9 | | | $2.6 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | 2017 | | 2016 |
| | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | (In Millions) |
Equity Securities | |
| $596.7 |
| |
| $354.9 |
| |
| $— |
| |
| $525.4 |
| |
| $281.5 |
| |
| $— |
|
Debt Securities | | 348.2 |
| | 2.1 |
| | 3.0 |
| | 309.3 |
| | 3.4 |
| | 4.2 |
|
Total | |
| $944.9 |
| |
| $357.0 |
| |
| $3.0 |
| |
| $834.7 |
| |
| $284.9 |
| |
| $4.2 |
|
The amortized cost of available-for-sale debt securities was $349.1$420.4 million as of December 31, 20172020 and $310.1$405.4 million as of December 31, 2016.2019. As of December 31, 2017,2020, the available-for-sale debt securities have an average coupon rate of approximately 2.64%2.57%, an average duration of approximately 5.616.97 years, and an average maturity of approximately 7.008.24 years.
The unrealized gains/(losses) recognized during the year ended December 31, 2020 on equity securities still held as of December 31, 2020 were $116.8 million. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor’s 500 Index. A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Index.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 20172020:
| | | | | | | | | | | |
| Fair Value | | Gross Unrealized Losses |
| (In Millions) |
Less than 12 months | $29.9 | | | $0.3 | |
More than 12 months | 0 | | | 0 | |
Total | $29.9 | | | $0.3 | |
The fair value and 2016:gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2019:
| | | | | | | | | | | |
| Fair Value | | Gross Unrealized Losses |
| (In Millions) |
Less than 12 months | $104.8 | | | $2.5 | |
More than 12 months | 7.7 | | | 0.1 | |
Total | $112.5 | | | $2.6 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2017 | | 2016 |
| Equity Securities | | Debt Securities | | Equity Securities | | Debt Securities |
| Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| (In Millions) |
Less than 12 months |
| $— |
| |
| $— |
| |
| $168.0 |
| |
| $1.2 |
| |
| $— |
| |
| $— |
| |
| $146.7 |
| |
| $4.2 |
|
More than 12 months | — |
| | — |
| | 41.4 |
| | 1.8 |
| | — |
| | — |
| | — |
| | — |
|
Total |
| $— |
| |
| $— |
| |
| $209.4 |
| |
| $3.0 |
| |
| $— |
| |
| $— |
| |
| $146.7 |
| |
| $4.2 |
|
The fair value of available-for-sale debt securities, summarized by contractual maturities, as of December 31, 20172020 and 20162019 are as follows:
| | | | | | | | | | | |
| 2020 | | 2019 |
| (In Millions) |
Less than 1 year | $0 | | | $44.1 | |
1 year - 5 years | 113.1 | | | 109.1 | |
5 years - 10 years | 189.8 | | | 156.0 | |
10 years - 15 years | 81.4 | | | 31.3 | |
15 years - 20 years | 28.5 | | | 23.8 | |
20 years+ | 35.1 | | | 48.5 | |
Total | $447.9 | | | $412.8 | |
|
| | | | | | | |
| 2017 | | 2016 |
| (In Millions) |
less than 1 year |
| $13.0 |
| |
| $16.7 |
|
1 year - 5 years | 123.4 |
| | 106.2 |
|
5 years - 10 years | 180.6 |
| | 161.2 |
|
10 years - 15 years | 4.8 |
| | 7.7 |
|
15 years - 20 years | 3.4 |
| | 1.0 |
|
20 years+ | 23.0 |
| | 16.5 |
|
Total |
| $348.2 |
| |
| $309.3 |
|
During the years ended December 31, 2017, 2016,2020, 2019, and 2015,2018, proceeds from the dispositions of available-for-sale securities amounted to $339.4$94.5 million, $197.4$110.6 million, and $213$82.1 million, respectively. During the years ended December 31, 2020, 2019, and 2018, gross gains of $8.8 million, $2.9 million, and $0.1 million, respectively, and gross losses of $0.2 million, $0.1 million, and $2.9 million, respectively, related to available-for-sale securities were reclassified out of other regulatory liabilities/assets into earnings.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2017, 2016, and 2015, gross gains of $17.7 million, $1.8 million, and $5.9 million, respectively, and gross losses of $0.6 million, $0.8 million, and $0.3 million, respectively, were recorded in earnings.
Entergy Louisiana
Entergy Louisiana holds debt and equity securities classified asand available-for-sale debt securities in nuclear decommissioning trust accounts. The available-for-sale securities held as of December 31, 20172020 and 20162019 are summarized as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | (In Millions) |
2020 | | | | | | |
Debt Securities | | $632.2 | | | $51.3 | | | $0.5 | |
| | | | | | |
2019 | | | | | | |
Debt Securities | | $601.5 | | | $29.3 | | | $0.8 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | 2017 | | 2016 |
| | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | (In Millions) |
Equity Securities | |
| $818.3 |
| |
| $461.2 |
| |
| $— |
| |
| $715.9 |
| |
| $346.6 |
| |
| $— |
|
Debt Securities | | 493.8 |
| | 10.9 |
| | 3.6 |
| | 424.8 |
| | 8.0 |
| | 5.0 |
|
Total | |
| $1,312.1 |
| |
| $472.1 |
| |
| $3.6 |
| |
| $1,140.7 |
| |
| $354.6 |
| |
| $5.0 |
|
The amortized cost of available-for-sale debt securities was $490$581.4 million as of December 31, 20172020 and $421.9$573 million as of December 31, 2016.2019. As of December 31, 2017,2020, the available-for-sale debt securities have an average coupon rate of approximately 3.88%3.64%, an average duration of approximately 6.177.25 years, and an average maturity of approximately 12.0612.73 years.
The unrealized gains/(losses) recognized during the year ended December 31, 2020 on equity securities still held as of December 31, 2020 were $163.6 million. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor’s 500 Index. A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Index.
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 20172020:
| | | | | | | | | | | |
| Fair Value | | Gross Unrealized Losses |
| (In Millions) |
Less than 12 months | $36.4 | | | $0.5 | |
More than 12 months | 0.8 | | | 0 | |
Total | $37.2 | | | $0.5 | |
The fair value and 2016:gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2019:
| | | | | | | | | | | |
| Fair Value | | Gross Unrealized Losses |
| (In Millions) |
Less than 12 months | $71.2 | | | $0.8 | |
More than 12 months | 7.9 | | | 0 | |
Total | $79.1 | | | $0.8 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2017 | | 2016 |
| Equity Securities | | Debt Securities | | Equity Securities | | Debt Securities |
| Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| (In Millions) |
Less than 12 months |
| $— |
| |
| $— |
| |
| $135.3 |
| |
| $1.1 |
| |
| $— |
| |
| $— |
| |
| $198.8 |
| |
| $4.8 |
|
More than 12 months | — |
| | — |
| | 84.4 |
| | 2.5 |
| | — |
| | — |
| | 4.8 |
| | 0.2 |
|
Total |
| $— |
| |
| $— |
| |
| $219.7 |
| |
| $3.6 |
| |
| $— |
| |
| $— |
| |
| $203.6 |
| |
| $5.0 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair value of available-for-sale debt securities, summarized by contractual maturities, as of December 31, 20172020 and 20162019 are as follows:
| | | | | | | | | | | |
| 2020 | | 2019 |
| (In Millions) |
Less than 1 year | $0 | | | $40.7 | |
1 year - 5 years | 117.0 | | | 142.0 | |
5 years - 10 years | 159.4 | | | 132.4 | |
10 years - 15 years | 101.2 | | | 39.8 | |
15 years - 20 years | 66.9 | | | 49.2 | |
20 years+ | 187.7 | | | 197.4 | |
Total | $632.2 | | | $601.5 | |
|
| | | | | | | |
| 2017 | | 2016 |
| (In Millions) |
less than 1 year |
| $23.2 |
| |
| $31.4 |
|
1 year - 5 years | 122.8 |
| | 99.1 |
|
5 years - 10 years | 109.3 |
| | 122.8 |
|
10 years - 15 years | 52.7 |
| | 41.4 |
|
15 years - 20 years | 50.7 |
| | 30.9 |
|
20 years+ | 135.1 |
| | 99.2 |
|
Total |
| $493.8 |
| |
| $424.8 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
During the years ended December 31, 2017, 2016,2020, 2019, and 2015,2018, proceeds from the dispositions of available-for-sale securities amounted to $231.3$159.7 million, $219.2$186 million, and $123.5$401.7 million, respectively. During the years ended December 31, 2017, 2016,2020, 2019, and 2015,2018, gross gains of $12$8.1 million, $3.9$4.8 million, and $1.9$2.1 million, respectively, and gross losses of $0.4$0.7 million, $0.4$0.3 million, and $0.3$7.5 million, respectively, related to available-for-sale securities were recorded inreclassified out of other regulatory liabilities/assets into earnings.
System Energy
System Energy holds debt and equity securities classified asand available-for-sale debt securities in nuclear decommissioning trust accounts. The available-for-sale securities held as of December 31, 20172020 and 20162019 are summarized as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | (In Millions) |
2020 | | | | | | |
Debt Securities | | $427.7 | | | $30.0 | | | $0.8 | |
| | | | | | |
2019 | | | | | | |
Debt Securities | | $386.2 | | | $15.1 | | | $0.3 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | 2017 | | 2016 |
| | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | (In Millions) |
Equity Securities | |
| $575.2 |
| |
| $308.6 |
| |
| $— |
| |
| $473.9 |
| |
| $221.9 |
| |
| $0.1 |
|
Debt Securities | | 330.5 |
| | 4.2 |
| | 1.2 |
| | 306.6 |
| | 2.0 |
| | 4.5 |
|
Total | |
| $905.7 |
| |
| $312.8 |
| |
| $1.2 |
| |
| $780.5 |
| |
| $223.9 |
| |
| $4.6 |
|
The amortized cost of available-for-sale debt securities was $327.5$398.4 million as of December 31, 20172020 and $309.1$371.4 million as of December 31, 2016.2019. As of December 31, 2017,2020, the available-for-sale debt securities have an average coupon rate of approximately 2.67%2.74%, an average duration of approximately 6.487.54 years, and an average maturity of approximately 9.2211.09 years.
The unrealized gains/(losses) recognized during the year ended December 31, 2020 on equity securities still held as of December 31, 2020 were $111.1 million. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor’s 500 Index. A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Index.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 20172020:
| | | | | | | | | | | |
| Fair Value | | Gross Unrealized Losses |
| (In Millions) |
Less than 12 months | $28.9 | | | $0.8 | |
More than 12 months | 0 | | | 0 | |
Total | $28.9 | | | $0.8 | |
The fair value and 2016:gross unrealized losses of available-for-sale debt securities, summarized by length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2019:
| | | | | | | | | | | |
| Fair Value | | Gross Unrealized Losses |
| (In Millions) |
Less than 12 months | $56.9 | | | $0.3 | |
More than 12 months | 0.3 | | | 0 | |
Total | $57.2 | | | $0.3 | |
The fair value of available-for-sale debt securities, summarized by contractual maturities, as of December 31, 2020 and 2019 are as follows:
| | | | | | | | | | | |
| 2020 | | 2019 |
| (In Millions) |
Less than 1 year | ($1.1) | | | $8.5 | |
1 year - 5 years | 134.7 | | | 154.6 | |
5 years - 10 years | 141.5 | | | 92.3 | |
10 years - 15 years | 31.5 | | | 13.4 | |
15 years - 20 years | 5.3 | | | 14.4 | |
20 years+ | 115.8 | | | 103.0 | |
Total | $427.7 | | | $386.2 | |
During the years ended December 31, 2020, 2019, and 2018, proceeds from the dispositions of available-for-sale securities amounted to $252.2 million, $338.1 million, and $361.9 million, respectively. During the years ended December 31, 2020, 2019, and 2018, gross gains of $11.5 million, $5.4 million, and $0.5 million, respectively, and gross losses of $0.6 million, $0.7 million, and $6.1 million, respectively, related to available-for-sale securities were reclassified out of other regulatory liabilities/assets into earnings.
Allowance for expected credit losses
Entergy implemented ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, effective January 1, 2020. In accordance with the new standard, Entergy estimates the expected credit losses for its available for sale securities based on the current credit rating and remaining life of the securities. To the extent an individual security is determined to be uncollectible it is written off against this allowance. Entergy’s available-for-sale securities are held in trusts managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. Specifically, available-for-sale securities are subject to credit worthiness restrictions, with requirements for both the average credit rating of the portfolio and minimum credit ratings for individual debt
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2017 | | 2016 |
| Equity Securities | | Debt Securities | | Equity Securities | | Debt Securities |
| Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| (In Millions) |
Less than 12 months |
| $— |
| |
| $— |
| |
| $196.9 |
| |
| $1.0 |
| |
| $— |
| |
| $— |
| |
| $220.9 |
| |
| $4.4 |
|
More than 12 months | — |
| | — |
| | 10.4 |
| | 0.2 |
| | — |
| | 0.1 |
| | 0.8 |
| | 0.1 |
|
Total |
| $— |
| |
| $— |
| |
| $207.3 |
| |
| $1.2 |
| |
| $— |
| |
| $0.1 |
| |
| $221.7 |
| |
| $4.5 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair value of debt securities, summarized by contractual maturities, assecurities. As of December 31, 2017 and 2016 are as follows:
|
| | | | | | | |
| 2017 | | 2016 |
| (In Millions) |
less than 1 year |
| $4.1 |
| |
| $6.6 |
|
1 year - 5 years | 173.0 |
| | 188.2 |
|
5 years - 10 years | 78.5 |
| | 78.5 |
|
10 years - 15 years | 1.0 |
| | 1.3 |
|
15 years - 20 years | 6.9 |
| | 7.8 |
|
20 years+ | 67.0 |
| | 24.2 |
|
Total |
| $330.5 |
| |
| $306.6 |
|
During2020, Entergy’s allowance for expected credit losses related to available-for-sale securities was $0.1 million. Entergy did not record any impairments of available-for-sale debt securities for the yearsyear ended December 31, 2017, 2016, and 2015, proceeds from the dispositions of securities amounted to $565.4 million, $499.3 million, and $390.4 million, respectively. During the years ended December 31, 2017, 2016, and 2015, gross gains of $1.4 million, $3.5 million, and $3.3 million, respectively, and gross losses of $3.3 million, $1.7 million, and $0.5 million, respectively, were recorded in earnings.2020.
Other-than-temporary impairments and unrealized gains and losses
Prior to the implementation of ASU 2016-13 on January 1, 2020, Entergy evaluates investmentevaluated the available-for-sale debt securities in the Entergy Wholesale Commodities’Commodities nuclear decommissioning trust funds with unrealized losses at the end of each period to determine whether an other-than-temporary impairment hashad occurred. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment iswas based on whether Entergy hashad the intent to sell or more likely than not will bewould have been required to sell the debt security before recovery of its amortized costs. Further, if Entergy doesdid not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary impairment iswas considered to have occurred and it iswas measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). Entergy did not have any material other-than-temporary impairments relating to credit losses on debt securities for the years ended December 31, 2017, 2016,2019 and 2015. The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment is based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. Entergy did not record material charges to other income in 2017, 2016, or 2015 resulting from the recognition of the other-than-temporary impairment of equity securities held in its decommissioning trust funds.2018.
NOTE 17. VARIABLE INTEREST ENTITIES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Under applicable authoritative accounting guidance, a variable interest entity (VIE) is an entity that conducts a business or holds property that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity holders do not receive expected losses or returns. An entity may have an interest in a VIE through ownership or other contractual rights or obligations, and is required to consolidate a VIE if it is the VIE’s primary beneficiary. The primary beneficiary of a VIE is the entity that has the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance and has the obligation to absorb losses or has the right to residual returns that would potentially be significant to the entity.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas, Entergy Louisiana, and System Energy consolidate the respective companies from which they lease nuclear fuel, usually in a sale and leaseback transaction. This is because Entergy directs the nuclear fuel companies with respect to nuclear fuel purchases, assists the nuclear fuel companies in obtaining financing, and, if financing cannot be arranged, the lessee (Entergy Arkansas, Entergy Louisiana, or System Energy) is responsible to repurchase nuclear fuel to allow the nuclear fuel company (the VIE) to meet its obligations. During the term of the arrangements, none of the Entergy operating companies have been required to provide financial support apart from their scheduled lease payments. See Note 4 to the financial statements for details of the nuclear fuel companies’ credit facility and commercial paper borrowings and long-term debt that are reported by Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy. These amounts also represent Entergy’s and the respective Registrant Subsidiary’s maximum exposure to losses associated with their respective interests in the nuclear fuel companies.
Entergy Gulf States Reconstruction Funding I, LLC, and Entergy Texas Restoration Funding, LLC, companies wholly-owned and consolidated by Entergy Texas, are variable interest entities and Entergy Texas is the primary beneficiary. In June 2007, Entergy Gulf States Reconstruction Funding issued senior secured transition bonds (securitization bonds) to finance Entergy Texas’s Hurricane Rita reconstruction costs. In November 2009, Entergy Texas Restoration Funding issued senior secured transition bonds (securitization bonds) to finance Entergy Texas’s Hurricane Ike and Hurricane Gustav restoration costs. With the proceeds, the variable interest entities purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition charge amounts sufficient to service the securitization bonds. The transition property is reflected as a regulatory asset on the consolidated Entergy Texas balance sheet. The creditors of Entergy Texas do not have recourse to the assets or revenues of the variable interest entities, including the transition property, and the creditors
Entergy Corporation and Subsidiaries
Notes to Financial Statements
of the variable interest entities do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to the variable interest entities except to remit transition charge collections. See Note 5 to the financial statements for additional details regarding the securitization bonds.
Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, is a variable interest entity and Entergy Arkansas is the primary beneficiary. In August 2010, Entergy Arkansas Restoration Funding issued storm cost recovery bonds to finance Entergy Arkansas’s January 2009 ice storm damage restoration costs. With the proceeds, Entergy Arkansas Restoration Funding purchased from Entergy Arkansas the storm recovery property, which is the right to recover from customers through a storm recovery charge amounts sufficient to service the securitization bonds. The storm recovery property is reflected as a regulatory asset on the consolidated Entergy Arkansas balance sheet. The creditorssheet as of Entergy Arkansas doDecember 31, 2019. Although the principal amount was not have recourse to the assets or revenues ofdue until August 2021, Entergy Arkansas Restoration Funding includingmade principal payments on the storm recovery property, andbonds in 2020, after which the creditors of Entergy Arkansas Restoration Funding do not have recourse to the assets or revenues of Entergy Arkansas. Entergy Arkansas has no payment obligations to Entergy Arkansas Restoration Funding except to remit storm recovery charge collections.bonds were fully repaid. See Note 5 to the financial statements for additional details regarding the storm cost recovery bonds.
Entergy Louisiana Investment Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy Louisiana, is a variable interest entity and Entergy Louisiana is the primary beneficiary. In September 2011, Entergy Louisiana Investment Recovery Funding issued investment recovery bonds to recover Entergy Louisiana’s investment recovery costs associated with the canceled Little Gypsy repowering project. With the proceeds, Entergy Louisiana Investment Recovery Funding purchased from Entergy Louisiana the investment recovery property, which is the right to recover from customers through an investment recovery charge amounts sufficient to service the bonds. The investment recovery property is reflected as a regulatory asset on the consolidated Entergy Louisiana balance sheet. The creditors of Entergy Louisiana do not have recourse to the assets or revenues of Entergy Louisiana Investment Recovery Funding, including the investment recovery property, and the creditors of Entergy Louisiana Investment Recovery Funding do not have recourse to the assets or revenues of Entergy Louisiana. Entergy Louisiana has no payment obligations to Entergy Louisiana Investment Recovery Funding except to remit investment recovery charge collections. See Note 5 to the financial statements for additional details regarding the investment recovery bonds.
Entergy New Orleans Storm Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy New Orleans, is a variable interest entity, and Entergy New Orleans is the primary beneficiary. In July 2015,
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy New Orleans Storm Recovery Funding issued storm cost recovery bonds to recover Entergy New Orleans’s Hurricane Isaac storm restoration costs, including carrying costs, the costs of funding and replenishing the storm recovery reserve, and up-front financing costs associated with the securitization. With the proceeds, Entergy New Orleans Storm Recovery Funding purchased from Entergy New Orleans the storm recovery property, which is the right to recover from customers through a storm recovery charge amounts sufficient to service the securitization bonds. The storm recovery property is reflected as a regulatory asset on the consolidated Entergy New Orleans balance sheet. The creditors of Entergy New Orleans do not have recourse to the assets or revenues of Entergy New Orleans Storm Recovery Funding, including the storm recovery property, and the creditors of Entergy New Orleans Storm Recovery Funding do not have recourse to the assets or revenues of Entergy New Orleans. Entergy New Orleans has no payment obligations to Entergy New Orleans Storm Recovery Funding except to remit storm recovery charge collections. See Note 5 to the financial statements for additional details regarding the securitization bonds.
Entergy Louisiana was considered to hold a variable interest in the lessor from which it leased an undivided interest in the Waterford 3 nuclear plant. After Entergy Louisiana acquired a beneficial interest in the leased assets in March 2016, however, the lessor was no longer considered a variable interest entity. Entergy Louisiana made payments on its lease, including interest, of $9.2 million through March 2016 and $28.8 million in 2015. See Note 10 to the financial statements for a discussion of Entergy Louisiana’s purchase of the Waterford 3 leased assets.
System Energy is considered to hold a variable interest in the lessor from which it leases an undivided interest in the Grand Gulf nuclear plant. System Energy is the lessee under this arrangement, which is described in more detail in Note 105 to the financial statements. System Energy made payments on its lease, including interest, of $17.2 million in 2017,2020, $17.2 million in 2016,2019, and $52.3$17.2 million in 2015.2018. The lessor is a bank acting in the capacity of owner trustee for the benefit of equity investors in the transaction pursuant to trust agreement entered solely for the purpose of facilitating the lease transaction. It is possible that System Energy may be considered as the primary beneficiary of the lessor, but Entergyit is unable to apply the authoritative accounting guidance with respect to this VIE because the lessor is not required to, and could not, provide the necessary financial information to consolidate the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
lessor. Because EntergySystem Energy accounts for this leasing arrangement as a capital financing, however, EntergySystem Energy believes that consolidating the lessor would not materially affect the financial statements. In the unlikely event of default under a lease, remedies available to the lessor include payment by the lessee of the fair value of the undivided interest in the plant, payment of the present value of the basic rent payments, or payment of a predetermined casualty value. EntergySystem Energy believes, however, that the obligations recorded on the balance sheet materially represent the company’sits potential exposure to loss.
Entergy has also reviewed various lease arrangements, power purchase agreements, including agreements for renewable power, and other agreements that represent variable interests in other legal entities which have been determined to be variable interest entities. In these cases, Entergy has determined that it is not the primary beneficiary of the related VIE because it does not have the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance, or it does not have the obligation to absorb losses or the right to residual returns that would potentially be significant to the entity, or both.
NOTE 18. TRANSACTIONS WITH AFFILIATES (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Each Registrant Subsidiary purchases electricity from or sells electricity to the other Registrant Subsidiaries, or both, under rate schedules filed with the FERC. The Registrant Subsidiaries receive management, technical, advisory, operating, and administrative services from Entergy Services; and receive management, technical, and operating services from Entergy Operations. These transactions are on an “at cost” basis.
As described in Note 1 to the financial statements, all of System Energy’s operating revenues consist of billings to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
As described in Note 4 to the financial statements, the Registrant Subsidiaries participate in Entergy’s money pool and earn interest income from the money pool. As described in Note 2 to the financial statements, Entergy Louisiana receives preferred membership interest distributions from Entergy Holdings Company.
The tables below contain the various affiliate transactions of the Utility operating companies, System Energy, and other Entergy affiliates.
Intercompany Revenues
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| (In Millions) |
2020 | $105.2 | | | $280.5 | | | $1.2 | | | $0 | | | $40.4 | | | $520.7 | |
2019 | $117.5 | | | $277.8 | | | $1.4 | | | $0 | | | $51.6 | | | $584.1 | |
2018 | $104.3 | | | $299.0 | | | $2.5 | | | $0 | | | $58.8 | | | $456.7 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| (In Millions) |
2017 |
| $127.8 |
| |
| $282.4 |
| |
| $1.7 |
| |
| $— |
| |
| $57.9 |
| |
| $633.5 |
|
2016 |
| $49.4 |
| |
| $376.6 |
| |
| $2.9 |
| |
| $30.3 |
| |
| $180.2 |
| |
| $548.3 |
|
2015 |
| $127.9 |
| |
| $420.2 |
| |
| $86.0 |
| |
| $66.1 |
| |
| $259.1 |
| |
| $632.4 |
|
Intercompany Operating Expenses
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| (In Millions) |
2020 | $515.5 | | | $661.5 | | | $283.3 | | | $266.0 | | | $260.3 | | | $177.4 | |
2019 | $534.0 | | | $665.4 | | | $306.7 | | | $292.1 | | | $255.0 | | | $156.2 | |
2018 | $471.9 | | | $627.8 | | | $266.8 | | | $256.4 | | | $240.2 | | | $176.5 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| (In Millions) |
2017 |
| $510.2 |
| |
| $619.5 |
| |
| $310.5 |
| |
| $286.1 |
| |
| $234.6 |
| |
| $197.0 |
|
2016 |
| $467.4 |
| |
| $670.8 |
| |
| $256.5 |
| |
| $276.7 |
| |
| $343.7 |
| |
| $146.0 |
|
2015 |
| $508.5 |
| |
| $929.4 |
| |
| $331.8 |
| |
| $278.4 |
| |
| $413.7 |
| |
| $155.1 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Intercompany Interest and Investment Income
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Millions) |
| | | | | | | | | | | |
2020 | $0 | | | $127.7 | | | $0.1 | | | $0 | | | $0 | | | $0.2 | |
2019 | $0.4 | | | $128.5 | | | $0.4 | | | $0 | | | $0.4 | | | $1.0 | |
2018 | $0.4 | | | $128.2 | | | $0 | | | $0 | | | $0.2 | | | $1.2 | |
|
| | | | | | | | | | | | | | | | |
| | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | System Energy |
| | (In Millions) |
| | | | | | | | |
2017 | |
| $128.0 |
| |
| $— |
| |
| $0.2 |
| |
| $0.9 |
|
2016 | |
| $127.7 |
| |
| $0.1 |
| |
| $— |
| |
| $0.1 |
|
2015 | |
| $133.6 |
| |
| $— |
| |
| $— |
| |
| $— |
|
Transactions with Equity Method Investees
EWO Marketing, LLC, an indirect wholly-owned subsidiary of Entergy, paid capacity charges and gas transportation to RS Cogen in the amounts of $24.6$26 million in 2017, $24.7 million in 2016, and2020, $24.5 million in 2015.2019, and $24 million in 2018.
Entergy’s operating transactions with its other equity method investees were not significant in 2017, 2016,2020, 2019, or 2015.2018.
NOTE 19. REVENUE (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Revenues from electric service and the sale of natural gas are recognized when services are transferred to the customer in an amount equal to what Entergy has the right to bill the customer because this amount represents the value of services provided to customers. Entergy’s total revenues for the years ended December 31, 2020 and 2019 are as follows:
| | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | | |
| | (In Thousands) | | | |
Utility: | | | | | | | |
Residential | | $3,550,317 | | | $3,531,500 | | | | |
Commercial | | 2,292,740 | | | 2,475,586 | | | | |
Industrial | | 2,331,170 | | | 2,541,287 | | | | |
Governmental | | 212,131 | | | 228,470 | | | | |
Total billed retail | | 8,386,358 | | | 8,776,843 | | | | |
| | | | | | | |
Sales for resale (a) | | 295,810 | | | 285,722 | | | | |
Other electric revenues (b) | | 348,102 | | | 343,143 | | | | |
Revenues from contracts with customers | | 9,030,270 | | | 9,405,708 | | | | |
Other revenues (c) | | 16,373 | | | 24,270 | | | | |
Total electric revenues | | 9,046,643 | | | 9,429,978 | | | | |
| | | | | | | |
Natural gas | | 124,008 | | | 153,954 | | | | |
| | | | | | | |
Entergy Wholesale Commodities: | | | | | | | |
Competitive businesses sales from contracts with customers (a) | | 771,360 | | | 1,164,552 | | | | |
Other revenues (c) | | 171,625 | | | 130,189 | | | | |
Total competitive businesses revenues | | 942,985 | | | 1,294,741 | | | | |
| | | | | | | |
Total operating revenues | | $10,113,636 | | | $10,878,673 | | | | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The Registrant Subsidiaries’ total revenues for the year ended December 31, 2020 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2020 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | (In Thousands) |
| | | | | | | | | | |
Residential | | $841,162 | | | $1,270,187 | | | $523,379 | | | $243,502 | | | $672,087 | |
Commercial | | 466,273 | | | 886,548 | | | 395,875 | | | 179,406 | | | 364,638 | |
Industrial | | 461,907 | | | 1,314,234 | | | 145,100 | | | 24,248 | | | 385,681 | |
Governmental | | 18,011 | | | 68,901 | | | 41,955 | | | 59,819 | | | 23,445 | |
Total billed retail | | 1,787,353 | | | 3,539,870 | | | 1,106,309 | | | 506,975 | | | 1,445,851 | |
Sales for resale (a) | | 173,115 | | | 333,594 | | | 77,530 | | | 33,213 | | | 100,273 | |
Other electric revenues (b) | | 109,642 | | | 141,004 | | | 54,590 | | | 8,294 | | | 39,981 | |
Revenues from contracts with customers | | 2,070,110 | | | 4,014,468 | | | 1,238,429 | | | 548,482 | | | 1,586,105 | |
Other revenues (c) | | 14,384 | | | 4,595 | | | 9,425 | | | 12,150 | | | 1,020 | |
Total electric revenues | | 2,084,494 | | | 4,019,063 | | | 1,247,854 | | | 560,632 | | | 1,587,125 | |
Natural gas | | 0 | | | 50,799 | | | 0 | | | 73,209 | | | 0 | |
Total operating revenues | | $2,084,494 | | | $4,069,862 | | | $1,247,854 | | | $633,841 | | | $1,587,125 | |
The Registrant Subsidiaries’ total revenues for the year ended December 31, 2019 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2019 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | (In Thousands) |
| | | | | | | | | | |
Residential | | $795,269 | | | $1,270,478 | | | $562,219 | | | $245,081 | | | $658,453 | |
Commercial | | 538,850 | | | 947,412 | | | 444,173 | | | 202,138 | | | 343,013 | |
Industrial | | 520,958 | | | 1,450,966 | | | 164,491 | | | 31,824 | | | 373,048 | |
Governmental | | 20,795 | | | 71,046 | | | 44,300 | | | 70,865 | | | 21,464 | |
Total billed retail | | 1,875,872 | | | 3,739,902 | | | 1,215,183 | | | 549,908 | | | 1,395,978 | |
Sales for resale (a) | | 257,864 | | | 333,395 | | | 39,295 | | | 38,626 | | | 59,074 | |
Other electric revenues (b) | | 112,618 | | | 135,783 | | | 58,269 | | | 9,842 | | | 32,424 | |
Revenues from contracts with customers | | 2,246,354 | | | 4,209,080 | | | 1,312,747 | | | 598,376 | | | 1,487,476 | |
Other revenues (c) | | 13,240 | | | 13,947 | | | 10,296 | | | (3,959) | | | 1,479 | |
Total electric revenues | | 2,259,594 | | | 4,223,027 | | | 1,323,043 | | | 594,417 | | | 1,488,955 | |
Natural gas | | 0 | | | 62,148 | | | 0 | | | 91,806 | | | 0 | |
Total operating revenues | | $2,259,594 | | | $4,285,175 | | | $1,323,043 | | | $686,223 | | | $1,488,955 | |
(a)Sales for resale and competitive businesses sales include day-ahead sales of energy in a market administered by an ISO. These sales represent financially binding commitments for the sale of physical energy the next day. These sales are adjusted to actual power generated and delivered in the real time market. Given the short duration of these transactions, Entergy does not consider them to be derivatives subject to fair value adjustments, and includes them as part of customer revenues.
(b)Other electric revenues consist primarily of transmission and ancillary services provided to participants of an ISO-administered market and unbilled revenue.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
(c)Other revenues include the settlement of financial hedges, occasional sales of inventory, alternative revenue programs, provisions for revenue subject to refund, and late fees.
Electric Revenues
Entergy’s primary source of revenue is from retail electric sales sold under tariff rates approved by regulators in its various jurisdictions. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy’s Utility operating companies provide power to customers on demand throughout the month, measured by a meter located at the customer’s property. Approved rates vary by customer class due to differing requirements of the customers and market factors involved in fulfilling those requirements. Entergy issues monthly bills to customers at rates approved by regulators for power and related services provided during the previous billing cycle.
To the extent that deliveries have occurred but a bill has not been issued, Entergy’s Utility operating companies record an estimate for energy delivered since the latest billings. The Utility operating companies calculate the estimate based upon several factors including billings through the last billing cycle in a month, actual generation in the month, historical line loss factors, and market prices of power in the respective jurisdiction. The inputs are revised as needed to approximate actual usage and cost. Each month, estimated unbilled amounts are recorded as unbilled revenue and accounts receivable, and the prior month’s estimate is reversed. Price and volume differences resulting from factors such as weather affect the calculation of unbilled revenues from one period to the other.
Entergy may record revenue based on rates that are subject to refund. Such revenues are reduced by estimated refund amounts when Entergy believes refunds are probable based on the status of rate proceedings as of the date financial statements are prepared. Because these refunds will be made through a reduction in future rates, and not as a reduction in bills previously issued, they are presented as other revenues in the table above.
System Energy’s only source of revenue is the sale of electric power and capacity generated from its 90% interest in the Grand Gulf nuclear plant to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. System Energy issues monthly bills to its affiliated customers equal to its actual operating costs plus a return on common equity approved by the FERC.
Entergy’s Utility operating companies also sell excess power not needed for its own customers, primarily through transactions with MISO, a regional transmission organization that maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. In the MISO market, Entergy offers its generation and bids its load into the market. MISO settles these offers and bids based on locational marginal prices. These represent pricing for energy at a given location based on a market clearing price that takes into account physical limitations on the transmission system, generation, and demand throughout the MISO region. MISO evaluates each market participant’s energy offers and demand bids to economically and reliably dispatch the entire MISO system. Entergy nets purchases and sales within the MISO market and reports in operating revenues when in a net selling position and in operating expenses when in a net purchasing position.
Natural Gas
Entergy Louisiana and Entergy New Orleans also distribute natural gas to retail customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. Gas transferred to customers is measured by a meter at the customer’s property. Entergy issues monthly invoices to customers at rates approved by regulators for the volume of gas transferred to date.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Competitive Businesses Revenues
The Entergy Wholesale Commodities segment derives almost all of its revenue from sales of electric power and capacity produced by its operating plants to wholesale customers. The majority of Entergy Wholesale Commodities’ revenues are from Entergy’s nuclear power plants located in the northern United States. Entergy issues monthly invoices to the counterparties for these electric sales at the respective contracted or ISO market rate of electricity and related services provided during the previous month.
Almost all of the Palisades nuclear plant output is sold under a 15-year PPA with Consumers Energy, executed as part of the acquisition of the plant in 2007 and expiring in April 2022. Prices under the original PPA range from $43.50/MWh in 2007 to $61.50/MWh in 2022, and the average price under the PPA is $51/MWh. Entergy executed an additional PPA to cover the period from the expiration of the original PPA through final shutdown in May 2022, at a price of $24.14/MWh. Entergy issues monthly invoices to Consumers Energy for electric sales based on the actual output of electricity and related services provided during the previous month at the contract price. The PPA was at below-market prices at the time of the acquisition and Entergy amortizes a liability to revenue over the life of the agreement. The amount amortized each period is based upon the present value, calculated at the date of acquisition, of each year’s difference between revenue under the agreement and revenue based on estimated market prices. Amounts amortized to revenue were $11 million in 2020, $10 million in 2019, and $6 million in 2018. Amounts to be amortized to revenue through the remaining life of the agreement will be approximately $12 million in 2021 and $5 million in 2022.
Practical Expedients and Exceptions
Entergy has elected not to disclose the value of unsatisfied performance obligations for contracts with an original expected term of one year or less, or for revenue recognized in an amount equal to what Entergy has the right to bill the customer for services performed.
Most of Entergy’s contracts, except in a few cases where there are defined minimums or stated terms, are on demand. This results in customer bills that vary each month based on an approved tariff and usage. Entergy imposes monthly or annual minimum requirements on some customers primarily as credit and cost recovery guarantees and not as pricing for unsatisfied performance obligations. These minimums typically expire after the initial term or when specified costs have been recovered. The minimum amounts are part of each month’s bill and recognized as revenue accordingly. Some of the subsidiaries within the Entergy Wholesale Commodities segment have operations and maintenance services contracts that have fixed components and terms longer than one year. The total fixed consideration related to these unsatisfied performance obligations, however, is not material to Entergy revenues.
Recovery of Fuel Costs
Entergy’s Utility operating companies’ rate schedules include either fuel adjustment clauses or fixed fuel factors, which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Where the fuel component of revenues is based on a pre-determined fuel cost (fixed fuel factor), the fuel factor remains in effect until changed as part of a general rate case, fuel reconciliation, or fixed fuel factor filing. System Energy’s operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are based on System Energy’s common equity funds allocable to its net investment in Grand Gulf, plus System Energy’s effective interest cost for its debt allocable to its investment in Grand Gulf.
Taxes Imposed on Revenue-Producing Transactions
Governmental authorities assess taxes that are both imposed on and concurrent with a specific revenue-producing transaction between a seller and a customer, including, but not limited to, sales, use, value added, and
Entergy Corporation and Subsidiaries
Notes to Financial Statements
some excise taxes. Entergy presents these taxes on a net basis, excluding them from revenues.
Allowance for doubtful accounts
The allowance for doubtful accounts reflects Entergy’s best estimate of expected losses on its accounts receivable balances. Due to the essential nature of utility services, Entergy has historically experienced a low rate of default on its accounts receivables. Due to the effect of the COVID-19 pandemic on customer receivables, however, Entergy recorded an increase in its allowance for doubtful accounts, as shown below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| (In Millions) |
Balance as of December 31, 2019 | $7.4 | | | $1.2 | | | $1.9 | | | $0.6 | | | $3.2 | | | $0.5 | |
Provisions (a) | 109.0 | | | 16.2 | | | 43.7 | | | 18.8 | | | 14.1 | | | 16.2 | |
Write-offs | (8.6) | | | (1.8) | | | (3.5) | | | (1.2) | | | (1.0) | | | (1.1) | |
Recoveries | 9.9 | | | 2.7 | | | 3.6 | | | 1.3 | | | 1.1 | | | 1.2 | |
Balance as of December 31, 2020 | $117.7 | | | $18.3 | | | $45.7 | | | $19.5 | | | $17.4 | | | $16.8 | |
(a)Provisions include estimated incremental bad debt expenses resulting from the COVID-19 pandemic of $87.1 million for Entergy, $10.5 million for Entergy Arkansas, $36 million for Entergy Louisiana, $15.5 million for Entergy Mississippi, $12.2 million for Entergy New Orleans, and $12.9 million for Entergy Texas that have been deferred as regulatory assets. See Note 2 to the financial statements for discussion of the COVID-19 orders issued by retail regulators.
The allowance for currently expected credit losses is calculated as the historical rate of customer write-offs multiplied by the current accounts receivable balance, taking into account the length of time the receivable balances have been outstanding. Although the rate of customer write-offs has historically experienced minimal variation, management monitors the current condition of individual customer accounts to manage collections and ensure bad debt expense is recorded in a timely manner.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 19.20. QUARTERLY FINANCIAL DATA (UNAUDITED) (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Operating results for the four quarters of 20172020 and 20162019 for Entergy Corporation and subsidiaries were:
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | Operating Income | | Consolidated Net Income | | Net Income Attributable to Entergy Corporation |
| (In Thousands) |
2020: | | | |
First Quarter | $2,427,179 | | | $399,756 | | | $123,294 | | | $118,714 | |
Second Quarter | $2,412,788 | | | $439,311 | | | $365,113 | | | $360,533 | |
Third Quarter | $2,903,568 | | | $778,016 | | | $525,699 | | | $521,119 | |
Fourth Quarter | $2,370,101 | | | $152,112 | | | $392,547 | | | $387,968 | |
2019: | | | |
First Quarter | $2,609,584 | | | $283,254 | | | $258,646 | | | $254,537 | |
Second Quarter | $2,666,209 | | | $338,775 | | | $240,533 | | | $236,424 | |
Third Quarter | $3,140,575 | | | $519,929 | | | $369,459 | | | $365,240 | |
Fourth Quarter | $2,462,305 | | | $248,539 | | | $389,606 | | | $385,025 | |
|
| | | | | | | | | | | | | | | |
| Operating Revenues | | Operating Income (Loss) | | Consolidated Net Income (Loss) | | Net Income (Loss) Attributable to Entergy Corporation |
| (In Thousands) |
2017: | | | |
First Quarter |
| $2,588,458 |
| |
| $174,803 |
| |
| $86,051 |
| |
| $82,605 |
|
Second Quarter |
| $2,618,550 |
| |
| $143,509 |
| |
| $413,368 |
| |
| $409,922 |
|
Third Quarter |
| $3,243,628 |
| |
| $729,469 |
| |
| $401,644 |
| |
| $398,198 |
|
Fourth Quarter |
| $2,623,845 |
| |
| $211,901 |
| |
| ($475,710 | ) | |
| ($479,113 | ) |
2016: | | | |
First Quarter |
| $2,609,852 |
| |
| $498,218 |
| |
| $235,242 |
| |
| $229,966 |
|
Second Quarter |
| $2,462,562 |
| |
| $442,258 |
| |
| $572,590 |
| |
| $567,314 |
|
Third Quarter |
| $3,124,703 |
| |
| $772,060 |
| |
| $393,204 |
| |
| $388,170 |
|
Fourth Quarter |
| $2,648,528 |
| |
| ($2,599,001 | ) | |
| ($1,765,539 | ) | |
| ($1,769,068 | ) |
Earnings (loss) per average common share
| | | | | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 |
| Basic | | Diluted | | Basic | | Diluted |
First Quarter | $0.59 | | | $0.59 | | | $1.34 | | | $1.32 | |
Second Quarter | $1.80 | | | $1.79 | | | $1.22 | | | $1.22 | |
Third Quarter | $2.60 | | | $2.59 | | | $1.84 | | | $1.82 | |
Fourth Quarter | $1.95 | | | $1.93 | | | $1.96 | | | $1.94 | |
|
| | | | | | | | | | | | | | | |
| 2017 | | 2016 |
| Basic | | Diluted | | Basic | | Diluted |
First Quarter |
| $0.46 |
| |
| $0.46 |
| |
| $1.29 |
| |
| $1.28 |
|
Second Quarter |
| $2.28 |
| |
| $2.27 |
| |
| $3.17 |
| |
| $3.16 |
|
Third Quarter |
| $2.22 |
| |
| $2.21 |
| |
| $2.17 |
| |
| $2.16 |
|
Fourth Quarter |
| ($2.67 | ) | |
| ($2.66 | ) | |
| ($9.89 | ) | |
| ($9.86 | ) |
Results of operations for 20172020 include resolution of the 2014-2015 IRS audit, which resulted in a reduction in deferred income tax expense of $230 million that includes a $396 million reduction in deferred income tax expense at Utility related to the basis of assets contributed in the 2015 Entergy Louisiana and Entergy Gulf States Louisiana business combination, including the recognition of previously uncertain tax positions, and deferred income tax expense of $105 million at Entergy Wholesale Commodities and $61 million at Parent and Other resulting from the revaluation of net operating losses as a result of the release of the reserves. See Note 3 to the financial statements for further discussion of the IRS audit resolution.
Results of operations for 2019 include: 1) $538a loss of $190 million ($350156 million net-of-tax) as a result of the sale of the Pilgrim plant in August 2019; 2) a $156 million reduction in income tax expense recognized by Entergy Wholesale Commodities as a result of an internal restructuring; and 3) impairment charges of $100 million ($79 million net-of-tax) due to costs being charged directly to expense as incurred as a result of the impaired value of the Entergy Wholesale Commodities nuclear plants’ long-lived assets due to the significantly reduced remaining estimated operating lives associated with management’s strategy to reduce the size ofexit the Entergy Wholesale Commodities’ merchant fleet; 2) a reduction in income of $181 million, including a $34 million net-of-tax reduction of regulatory liabilities, at Utility and $397 million at Entergy Wholesale Commodities and an increase in income of $52 million at Parent and Other as a result of Entergy’s re-measurement of its deferred tax assets and liabilities not subjectpower business. See Note 3 to the ratemaking process due to the enactmentfinancial statements for further discussion of the Tax Cuts and Jobs Act, in December 2017, which lowered the federal corporate income tax rate from 35% to 21%; and 3) a reduction in income tax expense, net of unrecognized tax benefits, of $373 million as a result of a change in the tax classification of legal entities that own Entergy Wholesale Commodities nuclear power plants.internal restructuring. See Note 14 to the financial statements for further discussion of the impairment and related charges. See Note 3 to the financial statements for further discussionsale of the effects of the Tax Cuts and Jobs Act and the change in the tax classification.Pilgrim plant.
Results of operations for 2016 include: 1) $2,836 million ($1,829 million net-of-tax) of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ Palisades, Indian Point 2, and Indian Point 3 plants and related assets to their fair values; 2) a reduction of income tax expense, net of unrecognized tax benefits, of $238 million as a result of a change in the tax classification of a legal entity that owned one of the Entergy Wholesale Commodities nuclear power plants; income tax benefits as a result of the settlement of the 2010-2011 IRS audit, including a $75 million tax benefit recognized by Entergy Louisiana related to the treatment
Entergy Corporation and Subsidiaries
Notes to Financial Statements
of the Vidalia purchased power agreement and a $54 million net benefit recognized by Entergy Louisiana related to the treatment of proceeds received in 2010 for the financing of Hurricane Gustav and Hurricane Ike storm costs pursuant to Louisiana Act 55; and 3) a reduction in expenses of $100 million ($64 million net-of-tax) due to the effects of recording in 2016 the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. See Note 14 to the financial statements for further discussion of the impairment and related charges, see Note 3 to the financial statements for additional discussion of the income tax items, and see Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.
The business of the Utility operating companies is subject to seasonal fluctuations with the peak periods occurring during the third quarter. Operating results for the Registrant Subsidiaries for the four quarters of 20172020 and 20162019 were:
Operating Revenues
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| (In Thousands) |
2020: | | | | | | | | | | | |
First Quarter | $481,912 | | | $930,647 | | | $293,922 | | | $149,302 | | | $339,336 | | | $130,664 | |
Second Quarter | $491,767 | | | $1,011,652 | | | $297,954 | | | $147,343 | | | $372,194 | | | $126,049 | |
Third Quarter | $644,389 | | | $1,120,022 | | | $356,496 | | | $182,064 | | | $494,922 | | | $148,517 | |
Fourth Quarter | $466,426 | | | $1,007,541 | | | $299,482 | | | $155,132 | | | $380,673 | | | $90,228 | |
2019: | | | | | | | | | | | |
First Quarter | $545,812 | | | $959,330 | | | $282,244 | | | $163,194 | | | $340,474 | | | $140,104 | |
Second Quarter | $542,929 | | | $1,106,317 | | | $302,737 | | | $175,793 | | | $363,580 | | | $139,009 | |
Third Quarter | $687,526 | | | $1,231,677 | | | $398,732 | | | $194,204 | | | $442,877 | | | $145,472 | |
Fourth Quarter | $483,327 | | | $987,851 | | | $339,330 | | | $153,032 | | | $342,024 | | | $148,825 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| (In Thousands) |
2017: | | | | | | | | | | | |
First Quarter |
| $474,351 |
| |
| $880,783 |
| |
| $258,443 |
| |
| $168,989 |
| |
| $363,927 |
| |
| $154,787 |
|
Second Quarter |
| $496,662 |
| |
| $1,083,434 |
| |
| $291,212 |
| |
| $176,222 |
| |
| $378,488 |
| |
| $164,956 |
|
Third Quarter |
| $673,226 |
| |
| $1,290,494 |
| |
| $349,197 |
| |
| $199,017 |
| |
| $432,909 |
| |
| $156,106 |
|
Fourth Quarter |
| $495,680 |
| |
| $1,045,839 |
| |
| $299,377 |
| |
| $171,842 |
| |
| $369,569 |
| |
| $157,609 |
|
2016: | | | | | | | | | | | |
First Quarter |
| $465,373 |
| |
| $955,145 |
| |
| $263,046 |
| |
| $149,340 |
| |
| $378,304 |
| |
| $137,693 |
|
Second Quarter |
| $504,252 |
| |
| $999,034 |
| |
| $248,138 |
| |
| $164,920 |
| |
| $412,922 |
| |
| $151,323 |
|
Third Quarter |
| $654,599 |
| |
| $1,249,452 |
| |
| $309,739 |
| |
| $201,336 |
| |
| $442,085 |
| |
| $114,039 |
|
Fourth Quarter |
| $462,384 |
| |
| $973,417 |
| |
| $273,726 |
| |
| $149,867 |
| |
| $382,308 |
| |
| $145,236 |
|
Operating Income
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| (In Thousands) |
2020: | | | | | | | | | | | |
First Quarter | $67,835 | | | $166,779 | | | $41,181 | | | $12,091 | | | $36,060 | | | $35,309 | |
Second Quarter | $107,949 | | | $256,412 | | | $67,705 | | | $7,602 | | | $56,443 | | | $31,236 | |
Third Quarter | $217,648 | | | $324,496 | | | $93,843 | | | $32,322 | | | $108,306 | | | $48,896 | |
Fourth Quarter | $9,126 | | | $117,134 | | | $33,466 | | | $12,397 | | | $46,040 | | | $1,303 | |
2019: | | | | | | | | | | | |
First Quarter | $42,471 | | | $153,944 | | | $30,792 | | | $16,136 | | | $16,741 | | | $31,368 | |
Second Quarter | $69,774 | | | $241,520 | | | $45,607 | | | $17,509 | | | $36,022 | | | $24,300 | |
Third Quarter | $182,176 | | | $336,754 | | | $87,024 | | | $28,876 | | | $69,510 | | | $29,086 | |
Fourth Quarter | $32,576 | | | $164,424 | | | $40,331 | | | $6,164 | | | $24,229 | | | $30,231 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| (In Thousands) |
2017: | | | | | | | | | | | |
First Quarter |
| $39,847 |
| |
| $152,648 |
| |
| $39,608 |
| |
| $21,762 |
| |
| $38,842 |
| |
| $41,544 |
|
Second Quarter |
| $68,994 |
| |
| $193,779 |
| |
| $55,262 |
| |
| $27,606 |
| |
| $47,787 |
| |
| $40,717 |
|
Third Quarter |
| $169,755 |
| |
| $290,089 |
| |
| $84,035 |
| |
| $33,415 |
| |
| $78,950 |
| |
| $37,459 |
|
Fourth Quarter |
| $14,507 |
| |
| $210,325 |
| |
| $42,169 |
| |
| $12,333 |
| |
| $33,800 |
| |
| $41,073 |
|
2016: | | | | | | | | | | | |
First Quarter |
| $54,378 |
| |
| $181,618 |
| |
| $41,573 |
| |
| $21,880 |
| |
| $41,269 |
| |
| $47,466 |
|
Second Quarter |
| $73,447 |
| |
| $193,752 |
| |
| $61,890 |
| |
| $26,913 |
| |
| $58,039 |
| |
| $45,020 |
|
Third Quarter |
| $188,660 |
| |
| $312,951 |
| |
| $88,312 |
| |
| $42,279 |
| |
| $107,964 |
| |
| $43,886 |
|
Fourth Quarter |
| $29,843 |
| |
| $111,066 |
| |
| $32,464 |
| |
| $8,807 |
| |
| $38,338 |
| |
| $44,781 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Net Income (Loss)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| (In Thousands) |
2020: | | | | | | | | | | | |
First Quarter | $44,595 | | | $189,396 | | | $22,526 | | | $11,186 | | | $32,707 | | | $28,513 | |
Second Quarter | $60,170 | | | $170,459 | | | $38,893 | | | $4,929 | | | $46,868 | | | $28,991 | |
Third Quarter | $135,843 | | | $223,466 | | | $58,589 | | | $19,450 | | | $92,164 | | | $31,064 | |
Fourth Quarter | $4,624 | | | $499,031 | | | $20,575 | | | $13,773 | | | $43,334 | | | $10,563 | |
2019: | | | | | | | | | | | |
First Quarter | $39,121 | | | $127,633 | | | $15,398 | | | $9,023 | | | $21,342 | | | $23,578 | |
Second Quarter | $50,299 | | | $183,084 | | | $26,667 | | | $13,003 | | | $38,936 | | | $24,472 | |
Third Quarter | $149,716 | | | $255,260 | | | $56,237 | | | $24,908 | | | $73,224 | | | $25,031 | |
Fourth Quarter | $23,828 | | | $125,560 | | | $21,623 | | | $5,695 | | | $25,895 | | | $26,039 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| (In Thousands) |
2017: | | | | | | | | | | | |
First Quarter |
| $14,304 |
| |
| $94,378 |
| |
| $17,158 |
| |
| $10,978 |
| |
| $10,854 |
| |
| $20,347 |
|
Second Quarter |
| $38,550 |
| |
| $124,479 |
| |
| $28,303 |
| |
| $14,882 |
| |
| $21,101 |
| |
| $19,350 |
|
Third Quarter |
| $92,638 |
| |
| $186,284 |
| |
| $46,545 |
| |
| $18,529 |
| |
| $39,588 |
| |
| $20,583 |
|
Fourth Quarter |
| ($5,648 | ) | |
| ($88,794 | ) | |
| $18,026 |
| |
| $164 |
| |
| $4,630 |
| |
| $18,316 |
|
2016: | | | | | | | | | | | |
First Quarter |
| $19,294 |
| |
| $111,606 |
| |
| $17,118 |
| |
| $11,167 |
| |
| $14,562 |
| |
| $25,958 |
|
Second Quarter |
| $33,891 |
| |
| $253,325 |
| |
| $32,194 |
| |
| $11,843 |
| |
| $24,058 |
| |
| $25,090 |
|
Third Quarter |
| $110,148 |
| |
| $189,506 |
| |
| $46,612 |
| |
| $23,701 |
| |
| $56,133 |
| |
| $22,370 |
|
Fourth Quarter |
| $3,879 |
| |
| $67,610 |
| |
| $13,260 |
| |
| $2,138 |
| |
| $12,785 |
| |
| $23,326 |
|
Earnings (Loss) Applicable to Common EquityEquity/Stock
| | | | | | | | | | | | | |
| | | | | | | Entergy Texas |
| | | | | | (In Thousands) |
2020: | | | | | | | |
First Quarter | | | | | | | $32,237 | |
Second Quarter | | | | | | | $46,397 | |
Third Quarter | | | | | | | $91,694 | |
Fourth Quarter | | | | | | | $42,863 | |
2019: | | | | | | | |
First Quarter | | | | | | | $21,342 | |
Second Quarter | | | | | | | $38,936 | |
Third Quarter | | | | | | | $73,114 | |
Fourth Quarter | | | | | | | $25,425 | |
|
| | | | | | | | | | | |
| Entergy Arkansas | | Entergy Mississippi | | Entergy New Orleans |
| (In Thousands) |
2017: | | | | | |
First Quarter |
| $13,947 |
| |
| $16,920 |
| |
| $10,737 |
|
Second Quarter |
| $38,193 |
| |
| $28,064 |
| |
| $14,641 |
|
Third Quarter |
| $92,281 |
| |
| $46,307 |
| |
| $18,288 |
|
Fourth Quarter |
| ($6,005 | ) | |
| $17,788 |
| |
| $46 |
|
2016: | | | | | |
First Quarter |
| $17,576 |
| |
| $16,411 |
| |
| $10,926 |
|
Second Quarter |
| $32,173 |
| |
| $31,487 |
| |
| $11,602 |
|
Third Quarter |
| $108,672 |
| |
| $45,905 |
| |
| $23,460 |
|
Fourth Quarter |
| $3,521 |
| |
| $12,938 |
| |
| $1,896 |
|
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
RISK FACTORS SUMMARY
Entergy’s business is subject to numerous risks and uncertainties that could affect its ability to successfully implement its business strategy and affect its financial results. Carefully consider all of the information in this report and, in particular, the following principal risks and all of the other specific factors described in Item 1A. of this report, “Risk Factors,” before deciding whether to invest in Entergy or the Registrant Subsidiaries.
Utility Regulatory Risks
•The impacts of the COVID-19 pandemic and responsive measures taken are highly uncertain and cannot be predicted.
•The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that can be lengthy and subject to appeal, potentially resulting in lengthy litigation and uncertainty as to ultimate results.
•The Utility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings.
•Entergy’s business could experience adverse effects related to changes to state or federal legislation or regulation.
•There remains uncertainty regarding the effect of the termination of the System Agreement on the Utility operating companies.
•The Utility operating companies are subject to risks associated with participation in the MISO markets and the allocation of transmission upgrade costs.
•A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather (including from Hurricane Laura, Hurricane Delta, and Hurricane Zeta) could have material effects on Entergy and those Utility operating companies affected by severe weather.
Nuclear Operating, Shutdown, and Regulatory Risks
•The results of operations, financial condition, and liquidity of Entergy Arkansas, Entergy Louisiana, System Energy, and Entergy Wholesale Commodities could be materially affected by the following:
◦failure to consistently operate their nuclear power plants at high capacity factors;
◦refueling outages that last longer than anticipated or unplanned outages;
◦risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication);
◦the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants;
◦risks and costs related to operating and maintaining their nuclear power plants;
◦the costs associated with the storage of the spent nuclear fuel, as well as the costs of and their ability to fully decommission their nuclear power plants;
◦the potential requirement to pay substantial retrospective premiums imposed under the Price-Anderson Act in the event of a nuclear incident, and losses not covered by insurance;
◦the risk that the decommissioning trust fund assets for the nuclear power plants may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts; and
◦new or existing safety concerns regarding operating nuclear power plants and nuclear fuel.
•Entergy Wholesale Commodities’ power plants are subject to impairment charges in certain circumstances and its nuclear power plants are exposed to price risk.
•The Entergy Wholesale Commodities business is subject to substantial governmental regulation and may be adversely affected by legislative, regulatory, or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
General Business Risks
•Entergy and the Utility operating companies depend on access to the capital markets and, at times, may face potential liquidity constraints, which could make it more difficult to handle future contingencies. Disruptions in the capital and credit markets may adversely affect Entergy’s and its subsidiaries’ ability to meet liquidity needs, access capital and operate and grow their businesses, and the cost of capital.
•A downgrade in Entergy Corporation’s or its subsidiaries’ credit ratings could, among other things, negatively affect Entergy Corporation’s and its subsidiaries’ ability to access capital.
•Changes in tax legislation and taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s, the Utility operating companies’, and System Energy’s results of operations, financial condition, and liquidity.
•Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to complete capital projects, other capital improvements, and strategic transactions is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies.
•Failure to attract, retain, and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
•The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs (i) to fulfill their obligations related to environmental and other matters or (ii) related to reliability standards.
•Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas usage and otherwise materially affect the Utility operating companies’ results of operations.
•Entergy could be negatively affected by the effects of climate change and environmental and regulatory obligations intended to compel greenhouse gas emission reductions or increase clean or renewable energy requirements or to place a price on greenhouse gas emissions.
•Entergy is dependent on the continued and future availability and quality of water for cooling, process, and sanitary uses.
•Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices.
•The Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties may not meet their obligations.
•Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.
•The litigation environment in the states in which certain Entergy subsidiaries operate poses a significant risk to those businesses.
•Terrorist attacks, cyber attacks, system failures, or data breaches of Entergy’s and its subsidiaries’ or its suppliers’ technology systems may adversely affect Entergy’s results of operations.
•The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidity.
•System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings.
•As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
ENTERGY’S BUSINESS
Entergy is an integrated energy company engaged primarily in electric power production and retail distribution operations. Entergy owns and operates power plants with approximately 30,000 MW of electric generating capacity, including nearly 9,000approximately 8,000 MW of nuclear power. Entergy delivers electricity to 2.93.0 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy had annual revenues of $11.1$10.1 billion in 20172020 and had more than 13,000 employees as of December 31, 2017.2020.
Entergy operates primarily through two business segments: Utility and Entergy Wholesale Commodities.
•The Utility business segment includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operation of a small natural gas distribution business.
•The Entergy Wholesale Commodities business segment includes the ownership, operation, and decommissioning of nuclear power plants located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities also provides services to other nuclear power plant owners and owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” for discussion of the operation and planned shutdown orand sale of each of the Entergy Wholesale Commodities nuclear power plants.
See Note 13 to the financial statements for financial information regarding Entergy’s business segments.
Strategy
Entergy’s missionstrategy is to operate a world-class energyand grow the premier utility business that creates sustainable value for its owners, customers, employees, communities, and communities. Entergy aspiresowners. Entergy’s strategy to achieve top quartile total shareholder returnsits stakeholder objectives has two key aspects. First, Entergy invests in a socially and environmentally responsible fashion by leveraging the scale and expertise inherent in its operations. Entergy’s current scope includes electricity generation, transmission, and distribution as well as natural gas distribution. Entergy focuses on operational excellence with an emphasis on safety, reliability, customer service, sustainability, cost efficiency, risk management, and engaged employees. Entergy also continually seeks opportunities to grow its utility business to benefit all stakeholders and to optimize its portfolio of assets in an ever-dynamic market through periodic buy, build, hold, or disposal decisions. To accomplish this, Entergy has established strategic imperatives for each business segment. For the Utility for the strategic imperative is to modernize its operations, maintain reliability, and better servebenefit of its customers, while growingwhich supports steady, predictable growth in earnings and dividends. Second, Entergy manages risks by ensuring its Utility investments are customer-centric, supported by progressive regulatory constructs, and executed with disciplined project management. Entergy’s strategy for the business. For Entergy Wholesale Commodities the strategic imperativebusiness segment is to continue to manage the risk of its operating portfolio as Entergy completes its exit from the merchant power business.
Utility
The Utility business segment includes five wholly-owned retail electric utility subsidiaries: Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas. These companies generate, transmit, distribute, and sell electric power to retail and wholesale customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy Louisiana and Entergy New Orleans also provide natural gas utility services to customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. Also included in the Utility is System Energy, a wholly-owned subsidiary of Entergy Corporation that owns or leases 90 percent of Grand Gulf. System Energy sells its power and capacity from Grand Gulf at wholesale to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. The five retail utility subsidiaries are each regulated by the FERC and by state utility commissions, or, in the case of Entergy New Orleans, the City Council. System Energy is regulated by the FERC because all of its transactions are at wholesale. The overall generation portfolio of the Utility, which relies heavily on natural gas and nuclear generation, is consistent with Entergy’s strong support for the environment.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Customers
As of December 31, 2017,2020, the Utility operating companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Electric Customers | | Gas Customers |
| Area Served | | (In Thousands) | | (%) | | (In Thousands) | | (%) |
Entergy Arkansas | Portions of Arkansas | | 722 | | | 25 | % | | | | |
Entergy Louisiana | Portions of Louisiana | | 1,096 | | | 37 | % | | 94 | | | 47 | % |
Entergy Mississippi | Portions of Mississippi | | 456 | | | 15 | % | | | | |
Entergy New Orleans | City of New Orleans | | 207 | | | 7 | % | | 108 | | | 53 | % |
Entergy Texas | Portions of Texas | | 473 | | | 16 | % | | | | |
Total customers | | | 2,954 | | | 100 | % | | 202 | | | 100 | % |
|
| | | | | | | | | | | | | |
| | | Electric Customers | | Gas Customers |
| Area Served | | (In Thousands) | | (%) | | (In Thousands) | | (%) |
Entergy Arkansas | Portions of Arkansas | | 709 |
| | 25 | % | | | | |
Entergy Louisiana | Portions of Louisiana | | 1,078 |
| | 37 | % | | 93 |
| | 47 | % |
Entergy Mississippi | Portions of Mississippi | | 449 |
| | 16 | % | | | | |
Entergy New Orleans | City of New Orleans | | 200 |
| | 7 | % | | 106 |
| | 53 | % |
Entergy Texas | Portions of Texas | | 448 |
| | 15 | % | | | | |
Total customers | | | 2,884 |
| | 100 | % | | 199 |
| | 100 | % |
Electric Energy Sales
The electric energy sales of the Utility operating companies are subject to seasonal fluctuations, with the peak sales period normally occurring during the third quarter of each year. On July 20, 2017,August 10, 2020, Entergy reached a 20172020 peak demand of 21,67121,340 MWh, compared to the 20162019 peak of 21,38721,598 MWh recorded on July 21, 2016.August 12, 2019. Selected electric energy sales data is shown in the table below:
Selected 20172020 Electric Energy Sales Data
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy (a) |
| (In GWh) |
Sales to retail customers | 20,749 | | | 53,896 | | | 12,402 | | | 5,447 | | | 18,677 | | | — | | | 111,170 | |
Sales for resale: | | | | | | | | | | | | | |
Affiliates | 1,659 | | | 5,585 | | | — | | | — | | | 1,203 | | | 5,849 | | | — | |
Others | 4,198 | | | 2,365 | | | 4,316 | | | 1,969 | | | 810 | | | — | | | 13,658 | |
Total | 26,606 | | | 61,846 | | | 16,718 | | | 7,416 | | | 20,690 | | | 5,849 | | | 124,828 | |
Average use per residential customer (kWh) | 12,633 | | | 14,576 | | | 14,093 | | | 12,315 | | | 14,829 | | | — | | | 13,917 | |
|
| | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy (a) |
| (In GWh) |
Sales to retail customers | 20,888 |
| | 55,243 |
| | 13,048 |
| | 5,622 |
| | 18,058 |
| | — |
| | 112,859 |
|
Sales for resale: | | | | | | | | | | | | | |
Affiliates | 1,782 |
| | 4,793 |
| | — |
| | — |
| | 1,534 |
| | 6,675 |
| | — |
|
Others | 6,549 |
| | 1,711 |
| | 857 |
| | 1,703 |
| | 729 |
| | — |
| | 11,550 |
|
Total | 29,219 |
| | 61,747 |
| | 13,905 |
| | 7,325 |
| | 20,321 |
| | 6,675 |
| | 124,409 |
|
Average use per residential customer (kWh) | 12,349 |
| | 14,377 |
| | 14,142 |
| | 11,986 |
| | 14,597 |
| | — |
| | 13,716 |
|
(a)Includes the effect of intercompany eliminations.
| |
(a) | Includes the effect of intercompany eliminations. |
The following table illustrates the Utility operating companies’ 20172020 combined electric sales volume as a percentage of total electric sales volume, and 20172020 combined electric revenues as a percentage of total 20172020 electric revenue, each by customer class.
| | | | | | | | | | | | | | |
Customer Class | | % of Sales Volume | | % of Revenue |
Residential | | 28.2 | | 39.2 |
Commercial | | 21.2 | | 25.4 |
Industrial (a) | | 37.7 | | 25.8 |
Governmental | | 2.0 | | 2.3 |
Wholesale/Other | | 10.9 | | 7.3 |
|
| | | | |
Customer Class | | % of Sales Volume | | % of Revenue |
Residential | | 27.2 | | 36.2 |
Commercial | | 23.1 | | 26.7 |
Industrial (a) | | 38.4 | | 27.8 |
Governmental | | 2.0 | | 2.5 |
Wholesale/Other | | 9.3 | | 6.8 |
| |
(a) | Major industrial customers are primarily in the petroleum refining and chemical industries. |
(a)Major industrial customers are primarily in the petroleum refining and chemical industries.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
See “Selected Financial Data” for each of the Utility operating companies for the detail of their sales by customer class for 2013-2017.2016-2020.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Selected 20172020 Natural Gas Sales Data
Entergy New Orleans and Entergy Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Louisiana sold 9,745,8749,467,899 and 6,017,1746,268,003 Mcf, respectively, of natural gas to retail customers in 2017.2020. In 2017,2020, 99% of Entergy Louisiana’s operating revenue was derived from the electric utility business, and only 1% from the natural gas distribution business. For Entergy New Orleans, 88% of operating revenue was derived from the electric utility business and 12% from the natural gas distribution business in 2017. 2020.
Following is data concerning Entergy New Orleans’s 20172020 retail operating revenue sources.
| | | | | | | | | | | | | | |
Customer Class | | Electric Operating Revenue | | Natural Gas Operating Revenue |
Residential | | 48% | | 51% |
Commercial | | 35% | | 25% |
Industrial | | 5% | | 18% |
Governmental/Municipal | | 12% | | 6% |
|
| | | | |
Customer Class | | Electric Operating Revenue | | Natural Gas Operating Revenue |
Residential | | 42% | | 46% |
Commercial | | 39% | | 28% |
Industrial | | 6% | | 7% |
Governmental/Municipal | | 13% | | 19% |
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Retail Rate Regulation
General (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas)
Each Utility operating company regularly participates in retail rate proceedings. The status of material retail rate proceedings is described in Note 2 to the financial statements. Certain aspects of the Utility operating companies’ retail rate mechanisms are discussed below.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Rate base (in billions) | | Current authorized return on common equity | | Weighted average cost of capital (after-tax) | | Equity ratio | | Regulatory construct | |
| | | | | | | | | | | |
Entergy Arkansas | | $8.4 (a) | | 9.25% - 10.25% | | 5.04% | | 36.6% | | - forward test year formula rate plan through 2021 test year (i)
- riders: MISO, capacity, Grand Gulf, tax adjustment, energy efficiency, fuel and purchased power | |
| | | | | | | | | | | |
Entergy Louisiana (electric) | | $11.9 (b) | | 9.2% - 10.4% | | 6.97% | | 48.63% | | - formula rate plan through 2019 test year (j)
- riders/specific recovery: MISO, capacity, transmission, fuel | |
| | | | | | | | | | | |
Entergy Louisiana (gas) | | $0.08 (c) | | 9.3% - 10.3% | | 6.96% | | 48.37% | | - gas rate stabilization plan
- rider: gas infrastructure | |
| | | | | | | | | | | |
|
| | | | | | | | | | | |
| | Rate base (in billions) | | Current authorized return on common equity | | Weighted average cost of capital (after-tax) | | Equity ratio | | Regulatory construct | |
| | | | | | | | | | | |
Entergy Arkansas | | $7.095 (a) | | 9.25% -10.25% | | 4.67% | | 31.69% | | - forward test year formula rate plan
- riders: MISO, capacity, Grand Gulf, energy efficiency, fuel and purchased power | |
| | | | | | | | | | | |
Entergy Louisiana (electric) | | $8.303 (b) | | 9.15% - 10.75% | | 7.35% | | 49.64% | | - formula rate plan through 2016 test year
- riders/specific recovery: MISO, capacity, fuel | |
| | | | | | | | | | | |
Entergy Louisiana (gas) | | $0.059 (c) | | 9.45% - 10.45% | | 7.54% | | 51.63% | | - gas rate stabilization plan
- rider: gas infrastructure | |
| | | | | | | | | | | |
Entergy Mississippi | | $2.131 (d) | | 9.47% - 11.49% | | 7.35% | | 49.37% | | - formula rate plan with forward-looking features
- riders: power management, Grand Gulf, fuel, MISO, unit power cost, storm damage, energy efficiency, ad valorem tax adjustment
| |
| | | | | | | | | | | |
Entergy New Orleans (electric) | | $0.299 (e) | | 10.7% - 11.5% | | 8.58% | | 50.08% | | - rate case
- riders/specific recovery: fuel, capacity | |
| | | | | | | | | | | |
Entergy New Orleans (gas) | | $0.089 (f) | | 10.25% - 11.25% | | 8.40% | | 50.08% | | - rate case
- rider: purchased gas | |
| | | | | | | | | | | |
Entergy Texas | | $1.634 (g) | | 9.8% | | 8.22% | | 48.6% | | - rate case
- riders: fuel, distribution and transmission, RPCE payments and rate case expenses, among others | |
| | | | | | | | | | | |
System Energy | | $1.201 (h) | | 10.94% | | 8.90% | | 65% | | - monthly cost of service | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Entergy Mississippi | | $3.0 (d) | | 8.89% - 10.93% | | 6.82% | | 49.09% | | - formula rate plan with forward-looking features
- riders: power management, Grand Gulf, fuel, MISO, unit power cost, storm damage, energy efficiency, ad valorem tax adjustment, vegetation, grid modernization, restructuring credit | |
| | | | | | | | | | | |
Entergy New Orleans (electric) | | $0.8 (e) | | 9.35% | | 7.09% | | 50% | | - formula rate plan with forward-looking features
- riders/specific recovery: fuel and purchased power, MISO, energy efficiency, environmental | |
| | | | | | | | | | | |
Entergy New Orleans (gas) | | $0.1 (e) | | 9.35% | | 7.09% | | 50% | | - formula rate plan with forward-looking features
- rider: purchased gas | |
| | | | | | | | | | | |
Entergy Texas | | $2.4 (f) | | 9.65% | | 7.73% | | 50.9% | | - rate case
- riders: fuel, distribution and transmission, generation, rate case expenses, AMI surcharge, tax reform, among others | |
| | | | | | | | | | | |
System Energy | | $1.6 (g) | | 10.94% (h) | | 8.57 % | | 65% (h) | | - monthly cost of service | |
| |
(a) | Based on 2018 forward test year. |
| |
(b) | Based on December 31, 2016 test year. |
| |
(c) | Based on September 30, 2016 test year. |
| |
(d) | Based on 2017 forward test year. |
| |
(e) | Based on December 31, 2011 test year and excludes approximately $228 million first-year average rate base for Union. |
| |
(f) | Based on December 31, 2011 test year. |
| |
(g) | Based on March 31, 2013 adjusted test year and excludes approximately $331 million for rate base being recovered through the distribution cost recovery rider and the transmission cost recovery rider |
| |
(h) | Based on calculation as of December 31, 2017. |
(a)Based on 2021 test year.
(b)Based on December 31, 2019 test year and excludes approximately $800 million for the Lake Charles Power Station and $300 million for the Washington Parish Energy Center, each included in the capacity rider, and $400 million of transmission plant, included in the transmission rider.
(c)Based on September 30, 2019 test year.
(d)Based on 2020 forward test year and excludes approximately $300 million for the Choctaw Generating Station, included in interim capacity mechanism.
(e)Based on December 31, 2018 test year and known and measurables through December 31, 2019. Electric rate base excludes approximately $190 million for New Orleans Power Station and $40 million for New Orleans Solar Station.
(f)Based on December 31, 2017 test year and excludes $1.0 billion in cost recovery riders.
(g)Based on calculation as of December 31, 2020.
(h)See Note 2 to the financial statements for discussion of ongoing proceedings at the FERC challenging System Energy’s authorized return on common equity and capital structure.
(i)See Note 2 to the financial statements for discussion of Entergy Arkansas’s pending formula rate plan extension request.
(j)See Note 2 to the financial statements for discussion of Entergy Louisiana’s pending formula rate plan extension request.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Entergy Arkansas
Fuel and Purchased Power Cost Recovery
Entergy Arkansas’s rate schedules include an energy cost recovery rider to recover fuel and purchased power costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy cost for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs. In December 2007 the APSC issued an order stating that Entergy Arkansas’s energy cost recovery rider will remain in effect, and any future termination of the rider would be subject to eighteen months advance notice by the APSC, which would occur following notice and hearing.
Production Cost Allocation Rider
Entergy Arkansas has in place an APSC-approved production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of System Agreement proceedings.
Entergy Louisiana
Fuel Recovery
Entergy Louisiana’s rate schedules include a fuel adjustment clause designed to recover the cost of fuel and purchased power costs. The fuel adjustment clause contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers, including carrying charges. See Note 2 to the financial statements for a discussion of proceedings related to audits of Entergy Louisiana’s fuel adjustment clause filings.
To help stabilize electricity costs, Entergy Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Louisiana hedgeshistorically hedged approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity iswas reviewed on an annual basis. In January 2018, Entergy Louisiana filed an application with the LPSC to suspend these seasonal hedging programs and implement financial hedges with terms up to five years for a portion of its natural gas exposure. A decision is expectedexposure, which was approved in November 2018.
Entergy Louisiana’s gas rates include a purchased gas adjustment clause based on estimated gas costs for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
To help stabilize retailRetail Rates - Gas
In accordance with the settlement of Entergy Gulf States Louisiana’s gas costs,rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana received approval fromsubmitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to hedge its exposure to natural gas price volatility for its gas purchased for resale throughrecover the use of financial instruments. Entergy Louisiana hedges approximately one-half of the projected natural gas volumes used to serve its natural gas customers for November through March. The hedge quantity is reviewed on an annual basis.
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Dueinvestment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to higher fuel costsinclude actual investment incurred for the operating monthprior quarter and is subject to the following conditions, among others: a ten-year term; application of January 2018 resulting in part from recent cold weather, higher Henry Hub prices, and an increase in total fuel and purchased power costs, Entergy Louisiana plans to cap the average fuel adjustment charge to be billed in March 2018 at $0.03060 per kWh and to defer billing of all fuel costsany earnings in excess of the capped amountsupper end of the earnings band as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by including such coststhe LPSC in January 2015. Implementation of the over- or under-recovery account.infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.
Other
In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and the second is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the LPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the recently-approved Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax obligation at the parent level of a consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020.
Entergy Mississippi
Fuel Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.
To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.
Formula Rate Plan
In August 2012 the MPSC opened inquiries to review whether the current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan was still appropriate or could be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan docket.proceeding. In March 2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the return on common equity formulas
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Entergy Corporation, Utility operating companies, and System Energy
or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans. The docket remains open.
Entergy New Orleans
Fuel Recovery
Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.
Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of its natural gas hedging program consistent with the City Council’s stated policy objectives. The program uses financial instruments to hedge exposure to volatility in the wholesale price of natural gas purchased to serve Entergy New Orleans gas customers. Entergy New Orleans hedges up to 25% of actual gas sales made during the winter months.
Due to higher fuel costs associated in part with the extended Grand Gulf outage and the partially simultaneous Union Power Block 1 planned outage, for the December 2016, January 2017, and February 2017 billing months, the City Council authorized Entergy New Orleans to cap the fuel adjustment charge billed to customers at $0.035 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.
Due to higher fuel costs for the operating month of January 2018 resulting in part from recent cold weather, higher Henry Hub prices, and an increase in total fuel and purchased power costs associated in part with certain plant outages, Entergy New Orleans has proposed to cap the fuel adjustment charge to be billed in March 2018 to non-transmission Entergy New Orleans legacy customers and Entergy New Orleans Algiers customers at $0.035323 per kWh and $0.025446 per kWh, respectively. Entergy New Orleans has also proposed to cap the fuel adjustment charge to be billed in March 2018 for Entergy New Orleans legacy transmission customers at $0.034609 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy New Orleans’s efforts to recover storm-related costs.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Energy Efficiency Programs
A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. The rate settlement provided an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provided a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. In January 2015 the City Council approved funding for the Energy Smart program from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In April 2017 the City Council approved an implementation plan for the Energy Smart program from April 2017 through December 2019. The City Council directed that the $11.8 million balance reported for Energy Smart funds be used to continue funding the program for Entergy New Orleans’s legacy customers and that the Energy Smart Algiers program continue to be funded through the Algiers fuel adjustment clause, until additional customer funding is required for the legacy customers. In September 2017, Entergy New Orleans filed a supplemental plan and proposed several options for an interim cost recovery mechanism necessary to recover program costs during the period between when existing funds directed to Energy Smart programs are depleted and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect. In December 2017 the City Council approved an energy efficiency cost recovery rider as an interim funding mechanism for Energy Smart, subject to verification that no additional funding sources exist. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. See Note 2 to the financial statements for discussion of Entergy New Orleans’s application with the City Council seeking approval of an implementation plan for the Energy Smart program from April 2020 through December 2022.
Entergy Texas
Fuel Recovery
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included in base rates. Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. The PUCT fuel cost proceedings are discussed in Note 2 to the financial statements.
At the PUCT’s April 2013 open meeting, the PUCT Commissioners discussed their view that a purchased power capacity rider was good public policy. The PUCT issued an order in May 2013 adopting the rule allowing for a purchased power capacity rider, subject to an offsetting adjustment for load growth. The rule, as adopted, also includes a process for obtaining pre-approval by the PUCT of purchased power agreements. Entergy Texas has not exercised the option to recover its capacity costs under the new rider mechanism, but will continue to evaluate the benefits of utilizing the new rider to recover future capacity costs.
Electric Industry Restructuring
In June 2009, a law was enacted in Texas that required Entergy Texas to cease all activities relating to Entergy Texas’s transition to competition. The law allows Entergy Texas to remain a part of the SERC Reliability Corporation (SERC) Region, although it does not prevent Entergy Texas from joining another power region. The law provides that proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding
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Entergy Corporation, Utility operating companies, and System Energy
exist. Under the law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT’s certification of Entergy Texas’s power region.
The law also contains provisions that allow Entergy Texas to take advantage of a cost recovery mechanism that permits annual filings for the recovery of reasonable and necessary expenditures for transmission infrastructure improvement and changes in wholesale transmission charges. This mechanism was previously available to other non-ERCOT Texas utility companies, but not to Entergy Texas.
The law further amended already existing law that had required Entergy Texas to propose for PUCT approval a tariff to allow eligible customers the ability to contract for competitive generation. The amending language in the law provides, among other things, that: 1) the tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers who choose not to participate in the tariff; 2) Entergy Texas shall “purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer”;customer;” and 3) Entergy Texas shall provide and price transmission service and ancillary services under that tariff at a rate that is unbundled from its cost of service. The law directs that the PUCT may not issue an order on the tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction.
Entergy Texas and the other parties to the PUCT proceeding to determine the design of the competitive generation tariff were involved in negotiations throughout 2011 and 2012 with the objective of resolving as many disputed issues as possible regarding the tariff. The PUCT determined that unrecovered costs that couldmay be recovered through the rider consist only of those costs necessary to implement and administer the competitive generation program and do not include lost revenues or embedded generation costs. The PUCT also ruled that the amount of customer load that may be included in the competitive generation service program is limited to 115 MW. After additional negotiations, and ultimately the scheduling of a hearing to resolve remaining contested issues, the PUCT issued the order approving the competitive generation service rider in July 2013. Entergy Texas filed for rehearing of the PUCT’s July 2013 order, which the PUCT denied. Entergy Texas has since filed its appeal of that PUCT order to the Travis County District Court, which found in favor of the PUCT in an order issued in October 2014. In November 2014, Entergy Texas appealed the District Court’s order which moves the appeal to the Third Court of Appeals. Entergy
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Texas and opposing parties filed briefs and responses in the first quarter 2015. Oral argument was held in May 2015. In March 2016 the Court of Appeals upheld the District Court’s ruling favoring the PUCT. In May 2016, Entergy Texas filed with the Texas Supreme Court a petition for review of the Court of Appeals ruling. In January 2017, Entergy Texas filed its petitioner’s brief on the merits with the Texas Supreme Court. In June 2017 the Texas Supreme Court denied Entergy Texas’s petition in this matter.
In September 2011 the PUCT adopted a proposed rule implementing a distribution cost recovery factor to recover capital and capital-related costs related to distribution infrastructure. The distribution cost recovery factor permits utilities once per year to implement an increase or decrease in rates above or below amounts reflected in base rates to reflect depreciation expense, federal income tax and other taxes, and return on investment. The distribution cost recovery factor rider may be changed a maximum of four times between base rate cases.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery factor rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas franchises are considered to be contracts and, therefore, are terminable pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.
Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas, and holds non-exclusive franchises to provide electric service in approximately 68 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire during 2018-2058.over the period 2020-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Property and Other Generation Resources
Owned Generating Stations
The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2017,2020, is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Owned and Leased Capability MW(a) |
Company | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
Entergy Arkansas | | 5,175 | | | 2,091 | | | 1,817 | | | 1,194 | | | 73 | | | — | |
Entergy Louisiana | | 11,317 | | | 8,827 | | | 2,144 | | | 346 | | | — | | | — | |
Entergy Mississippi | | 3,347 | | | 2,929 | | | — | | | 416 | | | — | | | 2 | |
Entergy New Orleans | | 665 | | | 638 | | | — | | | — | | | — | | | 27 | |
Entergy Texas | | 2,260 | | | 2,005 | | | — | | | 255 | | | — | | | — | |
System Energy | | 1,256 | | | — | | | 1,256 | | | — | | | — | | | — | |
Total | | 24,020 | | | 16,490 | | | 5,217 | | | 2,211 | | | 73 | | | 29 | |
|
| | | | | | | | | | | | | | | | | | |
| | Owned and Leased Capability MW(a) |
Company | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
Entergy Arkansas | | 5,217 |
| | 2,136 |
| | 1,821 |
| | 1,189 |
| | 71 |
| | — |
|
Entergy Louisiana | | 9,099 |
| | 6,603 |
| | 2,136 |
| | 360 |
| | — |
| | — |
|
Entergy Mississippi | | 3,359 |
| | 2,944 |
| | — |
| | 414 |
| | — |
| | 1 |
|
Entergy New Orleans | | 492 |
| | 491 |
| | — |
| | — |
| | — |
| | 1 |
|
Entergy Texas | | 2,331 |
| | 2,065 |
| | — |
| | 266 |
| | — |
| | — |
|
System Energy | | 1,271 |
| | — |
| | 1,271 |
| | — |
| | — |
| | — |
|
Total | | 21,769 |
| | 14,239 |
| | 5,228 |
| | 2,229 |
| | 71 |
| | 2 |
|
(a)“Owned and Leased Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.
| |
(a) | “Owned and Leased Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize. |
Summer peak load for the Utility has averaged 21,53321,591 MW over the previous decade.
The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, the economy, environmental regulations,Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 6,8008,801 MW of new long-term resources and the deactivation of over 5,200about 4,664 MW of legacy generation. As MISO market participants, the Utility operating companies also participate in MISO’s Day Ahead and Real Time Energy and Ancillary Services markets to economically dispatch generation and purchase energy to serve customers reliably and at the lowest reasonable cost.
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Entergy Corporation, Utility operating companies, and System Energy
Other Generation Resources
RFP Procurements
The Utility operating companies from time to time issue requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies. The RFPs issued by the Utility operating companies have sought resources needed to meet near-term MISO reliability requirements as well as longer-termlong-term requirements through a broad range of wholesale power products, including limited-term (1 to 3 years) and long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
Entergy Louisiana’s June 2005 purchase of the 718 MW, gas-fired Perryville plant, of which 35% of the output is sold to Entergy Texas;
Entergy Arkansas’s September 2008 purchase of the 789 MW, combined-cycle, gas-fired Ouachita Generating Facility. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns one-third of the facility;
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Entergy Corporation, Utility operating companies, and System Energy
Entergy Arkansas’s November 2012 purchase of the 620 MW, combined-cycle, gas-fired Hot Spring Energy facility;
Entergy Mississippi’s November 2012 purchase of the 450 MW, combined-cycle, gas-fired Hinds Energy facility;
Entergy Louisiana’s construction of the 560 MW, combined-cycle, gas turbine Ninemile 6 generating facility at its existing Ninemile Point electric generating station. The facility reached commercial operation in December 2014;
•Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine J. Wayne Leonard Power Station (previously referred to as the St. Charles generating facilityfacility) at its existing Little Gypsy electric generating station. Entergy Louisiana received regulatory approval from the LPSCThe facility began commercial operation in December 2016 and the facility is scheduled to be in service by mid-2019;May 2019;
•Entergy Texas’s construction of the 993 MW, combined-cycle, gas turbine Montgomery County generating facilityPower Station at its existing Lewis Creek electric generating station. Entergy Texas received regulatory approval from the PUCTThe facility began commercial operation in July 2017 and the facility is scheduled to be in service by mid-2021; andJanuary 2021;
•Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station.station site. The facility began commercial operation in March 2020;
•In October 2018, Entergy LouisianaMississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the LPSCMPSC in July 2017April 2020, and the facility is scheduled to be in service by mid-2020.early 2022;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020 and the facility is scheduled to be in service by the end of 2021;
•Entergy New Orleans received regulatory approval in August 2019 to construct the New Orleans Solar Station (a 20 MW self-build solar project) located at the NASA Michoud Facility.The facility was placed in service in December 2020;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Lee County, Arkansas. In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2022;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2023; and
•In June 2020, Entergy Texas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 1,200 acres in Liberty County near Dayton, Texas.In September 2020, Entergy Texas filed a petition with the PUCT seeking a finding that the transaction is in the public interest and requesting all necessary approvals.Closing is expected to occur by the end of 2023.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:
•River BendBend’s 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
•Entergy ArkansasArkansas’s wholesale base load capacity life-of-unit PPAs executed in 2003 totaling approximately 220 MW between Entergy Arkansas and Entergy Louisiana (110 MW) and between Entergy Arkansas and Entergy New Orleans (110 MW) related to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which had not been included in Entergy Arkansas’s retail rates);
In December 2009, Entergy Texas and Exelon Generation Company, LLC executed a 10-year agreement for 150-300 MW from the Frontier Generating Station located in Grimes County, Texas;
•In May 2011, Entergy Texas and Calpine Energy Services, L.P. executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. Entergy Louisiana purchases 50% of the facility’s capacity and energy from Entergy Texas. In July 2014, LS Power purchased the Carville Energy Center and replaced Calpine Energy Services as the counterparty to the agreement;
•In September 2012, Entergy Gulf States Louisiana executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 MW when available, from Rain CII Carbon LLC’s petpetroleum coke calcining facility in Sulphur, Louisiana. The facility began commercial operation in May 2013. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with the facility;
•In March 2013, Entergy Gulf States Louisiana executed a 20-year agreement for 8.5 MW from Agrilectric Power Partners, LP’s refurbished rice hull-fueled electric generation facility located in Lake Charles, Louisiana. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with Agrilectric;
•In September 2013, Entergy Louisiana executed a 10-year agreement with TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, to purchase approximately 3 MW from its landfill gas-fueled power generation facility located in Cleveland, Texas;
•Entergy Mississippi’s cost-based purchase, beginning in January 2013, of 90 MW from Entergy Arkansas’s share of Grand Gulf (only 60 MW of this PPA came through the RFP process). Cost recovery for the 90 MW was approved by the MPSC in January 2013;
•In April 2015, Entergy Arkansas and Stuttgart Solar, LLC executed a 20-year agreement for 81 MW from a solar photovoltaic electric generation facility located near Stuttgart, Arkansas. The APSC has approved the project and the expected commercial operation date isdeliveries pursuant to that agreement commenced in June 2019;2018;
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
•In November 2016, Entergy Louisiana and LS Power executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. The transaction has received regulatory approval and will begin in June 2022;
•In November 2016, Entergy Louisiana and Occidental Chemical Corporation executed a 10-year agreement for 500 MW from the Taft Cogeneration facility located in Hahnville, Louisiana. The transaction has received regulatory approval and will beginbegan in June 2018; and
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
•In February 2018, Entergy Arkansas filedLouisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2017.2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021;
•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a five-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021; and
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a solar photovoltaic electric generating facility located in Polk County, Texas.The PPA is expected to start when the facility reaches commercial operation in 2023.
In April 2020, Entergy Services, on behalf of Entergy Texas, issued an RFP for combined-cycle gas turbine capacity and energy resources. The RFP was seeking up to 1,000 MW - 1,200 MW of capacity, capacity-related benefits, energy, other electric products, and environmental attributes, if any, from a single generation resource located in the “Eastern Region” of Entergy Texas’s service area. In December 2020, Entergy Texas posted notice that it has elected to proceed with the self-build alternative, Orange County Power Station. The self-build alternative will be conditioned on receipt of required internal and regulatory approvals.
In June 2016,2020, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for long-term renewable generationsolar photovoltaic resources. The RFP was seeking up300 MW of energy, capacity, capacity-related benefits, other electric products, and environmental attributes from eligible new-build solar photovoltaic generation resources. In December 2020, Entergy Louisiana concluded evaluations of the RFP. Three proposals have been placed on the primary selection list and two proposals have been placed on the secondary selection list. Negotiations are currently in progress.
In January 2021, Entergy Texas provided notice that it intends to issue an RFP for solar generation resources. The RFP is seeking a minimum of 200 MW through a combination of renewable resourcesbuild-own-transfer agreements, self-build alternatives, and power purchase agreements that couldcan provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Texas customers. Two proposals were placed in the primary selection list and the transactions are currently in negotiations.
In July 2016, Entergy Services, on behalf of Entergy New Orleans, issued an RFP for long-term renewable generation resources. The RFP was seeking up to 20 MW of renewable resources that could provide increased depth and diversity to Entergy New Orleans’s generation resource portfolio. In May 2017, Entergy New Orleans selected three proposals, including a 5 MW self-build option for an aggregated solar photovoltaic resource located within Orleans Parish, Louisiana. In October 2017, Entergy New Orleans filed an application seeking City Council approval for the self-build option, which is pending before the City Council. Following unsuccessful negotiations related to the other proposals selected in May 2017, Entergy New Orleans suspended negotiations in November 2017 and invited bidders to re-submit proposals with current information. From these submissions, in January 2018, Entergy New Orleans selected three proposals with an anticipated total capacity of 90 MW. The updated proposals selected are in addition to the self-build option.
Natural Gas
Entergy Louisiana and Entergy New Orleans also distribute natural gas to retail customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. Gas transferred to customers is measured by a meter at the customer’s property. Entergy issues monthly invoices to customers at rates approved by regulators for the volume of gas transferred to date.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Competitive Businesses Revenues
The Entergy Wholesale Commodities segment derives almost all of its revenue from sales of electric power and capacity produced by its operating plants to wholesale customers. The majority of Entergy Wholesale Commodities’ revenues are from Entergy’s nuclear power plants located in the northern United States. Entergy issues monthly invoices to the counterparties for these electric sales at the respective contracted or ISO market rate of electricity and related services provided during the previous month.
Almost all of the Palisades nuclear plant output is sold under a 15-year PPA with Consumers Energy, executed as part of the acquisition of the plant in 2007 and expiring in April 2022. Prices under the original PPA range from $43.50/MWh in 2007 to $61.50/MWh in 2022, and the average price under the PPA is $51/MWh. Entergy executed an additional PPA to cover the period from the expiration of the original PPA through final shutdown in May 2022, at a price of $24.14/MWh. Entergy issues monthly invoices to Consumers Energy for electric sales based on the actual output of electricity and related services provided during the previous month at the contract price. The PPA was at below-market prices at the time of the acquisition and Entergy amortizes a liability to revenue over the life of the agreement. The amount amortized each period is based upon the present value, calculated at the date of acquisition, of each year’s difference between revenue under the agreement and revenue based on estimated market prices. Amounts amortized to revenue were $11 million in 2020, $10 million in 2019, and $6 million in 2018. Amounts to be amortized to revenue through the remaining life of the agreement will be approximately $12 million in 2021 and $5 million in 2022.
Practical Expedients and Exceptions
Entergy has elected not to disclose the value of unsatisfied performance obligations for contracts with an original expected term of one year or less, or for revenue recognized in an amount equal to what Entergy has the right to bill the customer for services performed.
Most of Entergy’s contracts, except in a few cases where there are defined minimums or stated terms, are on demand. This results in customer bills that vary each month based on an approved tariff and usage. Entergy imposes monthly or annual minimum requirements on some customers primarily as credit and cost recovery guarantees and not as pricing for unsatisfied performance obligations. These minimums typically expire after the initial term or when specified costs have been recovered. The minimum amounts are part of each month’s bill and recognized as revenue accordingly. Some of the subsidiaries within the Entergy Wholesale Commodities segment have operations and maintenance services contracts that have fixed components and terms longer than one year. The total fixed consideration related to these unsatisfied performance obligations, however, is not material to Entergy revenues.
Recovery of Fuel Costs
Entergy’s Utility operating companies’ rate schedules include either fuel adjustment clauses or fixed fuel factors, which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Where the fuel component of revenues is based on a pre-determined fuel cost (fixed fuel factor), the fuel factor remains in effect until changed as part of a general rate case, fuel reconciliation, or fixed fuel factor filing. System Energy’s operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are based on System Energy’s common equity funds allocable to its net investment in Grand Gulf, plus System Energy’s effective interest cost for its debt allocable to its investment in Grand Gulf.
Taxes Imposed on Revenue-Producing Transactions
Governmental authorities assess taxes that are both imposed on and concurrent with a specific revenue-producing transaction between a seller and a customer, including, but not limited to, sales, use, value added, and
Entergy Corporation and Subsidiaries
Notes to Financial Statements
some excise taxes. Entergy presents these taxes on a net basis, excluding them from revenues.
Allowance for doubtful accounts
The allowance for doubtful accounts reflects Entergy’s best estimate of expected losses on its accounts receivable balances. Due to the essential nature of utility services, Entergy has historically experienced a low rate of default on its accounts receivables. Due to the effect of the COVID-19 pandemic on customer receivables, however, Entergy recorded an increase in its allowance for doubtful accounts, as shown below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| (In Millions) |
Balance as of December 31, 2019 | $7.4 | | | $1.2 | | | $1.9 | | | $0.6 | | | $3.2 | | | $0.5 | |
Provisions (a) | 109.0 | | | 16.2 | | | 43.7 | | | 18.8 | | | 14.1 | | | 16.2 | |
Write-offs | (8.6) | | | (1.8) | | | (3.5) | | | (1.2) | | | (1.0) | | | (1.1) | |
Recoveries | 9.9 | | | 2.7 | | | 3.6 | | | 1.3 | | | 1.1 | | | 1.2 | |
Balance as of December 31, 2020 | $117.7 | | | $18.3 | | | $45.7 | | | $19.5 | | | $17.4 | | | $16.8 | |
(a)Provisions include estimated incremental bad debt expenses resulting from the COVID-19 pandemic of $87.1 million for Entergy, $10.5 million for Entergy Arkansas, $36 million for Entergy Louisiana, $15.5 million for Entergy Mississippi, $12.2 million for Entergy New Orleans, and $12.9 million for Entergy Texas that have been deferred as regulatory assets. See Note 2 to the financial statements for discussion of the COVID-19 orders issued by retail regulators.
The allowance for currently expected credit losses is calculated as the historical rate of customer write-offs multiplied by the current accounts receivable balance, taking into account the length of time the receivable balances have been outstanding. Although the rate of customer write-offs has historically experienced minimal variation, management monitors the current condition of individual customer accounts to manage collections and ensure bad debt expense is recorded in a timely manner.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 20. QUARTERLY FINANCIAL DATA (UNAUDITED) (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Operating results for the four quarters of 2020 and 2019 for Entergy Corporation and subsidiaries were:
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | Operating Income | | Consolidated Net Income | | Net Income Attributable to Entergy Corporation |
| (In Thousands) |
2020: | | | |
First Quarter | $2,427,179 | | | $399,756 | | | $123,294 | | | $118,714 | |
Second Quarter | $2,412,788 | | | $439,311 | | | $365,113 | | | $360,533 | |
Third Quarter | $2,903,568 | | | $778,016 | | | $525,699 | | | $521,119 | |
Fourth Quarter | $2,370,101 | | | $152,112 | | | $392,547 | | | $387,968 | |
2019: | | | |
First Quarter | $2,609,584 | | | $283,254 | | | $258,646 | | | $254,537 | |
Second Quarter | $2,666,209 | | | $338,775 | | | $240,533 | | | $236,424 | |
Third Quarter | $3,140,575 | | | $519,929 | | | $369,459 | | | $365,240 | |
Fourth Quarter | $2,462,305 | | | $248,539 | | | $389,606 | | | $385,025 | |
Earnings per average common share
| | | | | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 |
| Basic | | Diluted | | Basic | | Diluted |
First Quarter | $0.59 | | | $0.59 | | | $1.34 | | | $1.32 | |
Second Quarter | $1.80 | | | $1.79 | | | $1.22 | | | $1.22 | |
Third Quarter | $2.60 | | | $2.59 | | | $1.84 | | | $1.82 | |
Fourth Quarter | $1.95 | | | $1.93 | | | $1.96 | | | $1.94 | |
Results of operations for 2020 include resolution of the 2014-2015 IRS audit, which resulted in a reduction in deferred income tax expense of $230 million that includes a $396 million reduction in deferred income tax expense at Utility related to the basis of assets contributed in the 2015 Entergy Louisiana and Entergy Gulf States Louisiana business combination, including the recognition of previously uncertain tax positions, and deferred income tax expense of $105 million at Entergy Wholesale Commodities and $61 million at Parent and Other Procurements From Third Partiesresulting from the revaluation of net operating losses as a result of the release of the reserves. See Note 3 to the financial statements for further discussion of the IRS audit resolution.
Results of operations for 2019 include: 1) a loss of $190 million ($156 million net-of-tax) as a result of the sale of the Pilgrim plant in August 2019; 2) a $156 million reduction in income tax expense recognized by Entergy Wholesale Commodities as a result of an internal restructuring; and 3) impairment charges of $100 million ($79 million net-of-tax) due to costs being charged directly to expense as incurred as a result of the impaired value of the Entergy Wholesale Commodities nuclear plants’ long-lived assets due to the significantly reduced remaining estimated operating lives associated with management’s strategy to exit the Entergy Wholesale Commodities’ merchant power business. See Note 3 to the financial statements for further discussion of the internal restructuring. See Note 14 to the financial statements for further discussion of the sale of the Pilgrim plant.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The business of the Utility operating companies is subject to seasonal fluctuations with the peak periods occurring during the third quarter. Operating results for the Registrant Subsidiaries for the four quarters of 2020 and 2019 were:
Operating Revenues
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| (In Thousands) |
2020: | | | | | | | | | | | |
First Quarter | $481,912 | | | $930,647 | | | $293,922 | | | $149,302 | | | $339,336 | | | $130,664 | |
Second Quarter | $491,767 | | | $1,011,652 | | | $297,954 | | | $147,343 | | | $372,194 | | | $126,049 | |
Third Quarter | $644,389 | | | $1,120,022 | | | $356,496 | | | $182,064 | | | $494,922 | | | $148,517 | |
Fourth Quarter | $466,426 | | | $1,007,541 | | | $299,482 | | | $155,132 | | | $380,673 | | | $90,228 | |
2019: | | | | | | | | | | | |
First Quarter | $545,812 | | | $959,330 | | | $282,244 | | | $163,194 | | | $340,474 | | | $140,104 | |
Second Quarter | $542,929 | | | $1,106,317 | | | $302,737 | | | $175,793 | | | $363,580 | | | $139,009 | |
Third Quarter | $687,526 | | | $1,231,677 | | | $398,732 | | | $194,204 | | | $442,877 | | | $145,472 | |
Fourth Quarter | $483,327 | | | $987,851 | | | $339,330 | | | $153,032 | | | $342,024 | | | $148,825 | |
Operating Income
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| (In Thousands) |
2020: | | | | | | | | | | | |
First Quarter | $67,835 | | | $166,779 | | | $41,181 | | | $12,091 | | | $36,060 | | | $35,309 | |
Second Quarter | $107,949 | | | $256,412 | | | $67,705 | | | $7,602 | | | $56,443 | | | $31,236 | |
Third Quarter | $217,648 | | | $324,496 | | | $93,843 | | | $32,322 | | | $108,306 | | | $48,896 | |
Fourth Quarter | $9,126 | | | $117,134 | | | $33,466 | | | $12,397 | | | $46,040 | | | $1,303 | |
2019: | | | | | | | | | | | |
First Quarter | $42,471 | | | $153,944 | | | $30,792 | | | $16,136 | | | $16,741 | | | $31,368 | |
Second Quarter | $69,774 | | | $241,520 | | | $45,607 | | | $17,509 | | | $36,022 | | | $24,300 | |
Third Quarter | $182,176 | | | $336,754 | | | $87,024 | | | $28,876 | | | $69,510 | | | $29,086 | |
Fourth Quarter | $32,576 | | | $164,424 | | | $40,331 | | | $6,164 | | | $24,229 | | | $30,231 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Net Income
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| (In Thousands) |
2020: | | | | | | | | | | | |
First Quarter | $44,595 | | | $189,396 | | | $22,526 | | | $11,186 | | | $32,707 | | | $28,513 | |
Second Quarter | $60,170 | | | $170,459 | | | $38,893 | | | $4,929 | | | $46,868 | | | $28,991 | |
Third Quarter | $135,843 | | | $223,466 | | | $58,589 | | | $19,450 | | | $92,164 | | | $31,064 | |
Fourth Quarter | $4,624 | | | $499,031 | | | $20,575 | | | $13,773 | | | $43,334 | | | $10,563 | |
2019: | | | | | | | | | | | |
First Quarter | $39,121 | | | $127,633 | | | $15,398 | | | $9,023 | | | $21,342 | | | $23,578 | |
Second Quarter | $50,299 | | | $183,084 | | | $26,667 | | | $13,003 | | | $38,936 | | | $24,472 | |
Third Quarter | $149,716 | | | $255,260 | | | $56,237 | | | $24,908 | | | $73,224 | | | $25,031 | |
Fourth Quarter | $23,828 | | | $125,560 | | | $21,623 | | | $5,695 | | | $25,895 | | | $26,039 | |
Earnings Applicable to Common Equity/Stock
| | | | | | | | | | | | | |
| | | | | | | Entergy Texas |
| | | | | | (In Thousands) |
2020: | | | | | | | |
First Quarter | | | | | | | $32,237 | |
Second Quarter | | | | | | | $46,397 | |
Third Quarter | | | | | | | $91,694 | |
Fourth Quarter | | | | | | | $42,863 | |
2019: | | | | | | | |
First Quarter | | | | | | | $21,342 | |
Second Quarter | | | | | | | $38,936 | |
Third Quarter | | | | | | | $73,114 | |
Fourth Quarter | | | | | | | $25,425 | |
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
RISK FACTORS SUMMARY
Entergy’s business is subject to numerous risks and uncertainties that could affect its ability to successfully implement its business strategy and affect its financial results. Carefully consider all of the information in this report and, in particular, the following principal risks and all of the other specific factors described in Item 1A. of this report, “Risk Factors,” before deciding whether to invest in Entergy or the Registrant Subsidiaries.
Utility Regulatory Risks
•The impacts of the COVID-19 pandemic and responsive measures taken are highly uncertain and cannot be predicted.
•The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that can be lengthy and subject to appeal, potentially resulting in lengthy litigation and uncertainty as to ultimate results.
•The Utility operating companies have also made resource acquisitions outsiderecover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings.
•Entergy’s business could experience adverse effects related to changes to state or federal legislation or regulation.
•There remains uncertainty regarding the effect of the RFP process, including Entergy Mississippi’s January 2006 acquisitiontermination of the 480 MW, combined-cycle, gas-fired Attala power plant; Entergy Gulf States Louisiana’s March 2008 acquisition ofSystem Agreement on the 322 MW, simple-cycle, gas-fired Calcasieu Generating Facility; Entergy Louisiana’s April 2011 acquisition of the 580 MW, combined-cycle, gas-fired Acadia Energy Center Unit 2; and Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) March 2016 acquisitions of the 1,980 MW (summer rating), natural gas-fired, combined-cycle gas turbine Union Power Station power blocks, each rated at 495 MW (summer rating). Utility operating companies.
•The Utility operating companies have also entered into various limited-are subject to risks associated with participation in the MISO markets and long-term contractsthe allocation of transmission upgrade costs.
•A delay or failure in recent yearsrecovering amounts for storm restoration costs incurred as a result of bilateral negotiations.
The Washington Parish Energy Center is a 361 MW natural gas-fired peaking power plant under advanced development approximately 60 miles north of New Orleanssevere weather (including from Hurricane Laura, Hurricane Delta, and Hurricane Zeta) could have material effects on a partially developed site Calpine has owned since 2001. This simple-cycle power plant is proposed to be developed pursuant to an agreement with Entergy Louisiana, which will purchase the plant upon completion in 2021 for a fixed payment to reimburse construction costs plus an associated premium. In May 2017, Entergy Louisiana filed an application with the LPSC seeking certification of the plant. The application is pending.
Interconnections
The Utility operating companies’ generating units are interconnected by a transmission system operating at various voltages up to 500 kV. These generating units consist primarily of steam-electric production facilities and are provided dispatch instructions by MISO. Entergy’sthose Utility operating companies are MISO market participantsaffected by severe weather.
Nuclear Operating, Shutdown, and are interconnectedRegulatory Risks
•The results of operations, financial condition, and liquidity of Entergy Arkansas, Entergy Louisiana, System Energy, and Entergy Wholesale Commodities could be materially affected by the following:
◦failure to consistently operate their nuclear power plants at high capacity factors;
◦refueling outages that last longer than anticipated or unplanned outages;
◦risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication);
◦the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants;
◦risks and costs related to operating and maintaining their nuclear power plants;
◦the costs associated with many neighboring utilities. MISO is an essential linkthe storage of the spent nuclear fuel, as well as the costs of and their ability to fully decommission their nuclear power plants;
◦the potential requirement to pay substantial retrospective premiums imposed under the Price-Anderson Act in the safe, cost-effective deliveryevent of electrica nuclear incident, and losses not covered by insurance;
◦the risk that the decommissioning trust fund assets for the nuclear power across allplants may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts; and
◦new or parts of 15 U.S. statesexisting safety concerns regarding operating nuclear power plants and the Canadian province of Manitoba. As a Regional Transmission Organization, MISO assures consumers of unbiased regional grid managementnuclear fuel.
•Entergy Wholesale Commodities’ power plants are subject to impairment charges in certain circumstances and open accessits nuclear power plants are exposed to the transmissionprice risk.
•The Entergy Wholesale Commodities business is subject to substantial governmental regulation and may be adversely affected by legislative, regulatory, or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
General Business Risks
•Entergy and the Utility operating companies depend on access to the capital markets and, at times, may face potential liquidity constraints, which could make it more difficult to handle future contingencies. Disruptions in the capital and credit markets may adversely affect Entergy’s and its subsidiaries’ ability to meet liquidity needs, access capital and operate and grow their businesses, and the cost of capital.
•A downgrade in Entergy Corporation’s or its subsidiaries’ credit ratings could, among other things, negatively affect Entergy Corporation’s and its subsidiaries’ ability to access capital.
•Changes in tax legislation and taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s, the Utility operating companies’, and System Energy’s results of operations, financial condition, and liquidity.
•Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to complete capital projects, other capital improvements, and strategic transactions is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies.
•Failure to attract, retain, and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
•The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs (i) to fulfill their obligations related to environmental and other matters or (ii) related to reliability standards.
•Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas usage and otherwise materially affect the Utility operating companies’ results of operations.
•Entergy could be negatively affected by the effects of climate change and environmental and regulatory obligations intended to compel greenhouse gas emission reductions or increase clean or renewable energy requirements or to place a price on greenhouse gas emissions.
•Entergy is dependent on the continued and future availability and quality of water for cooling, process, and sanitary uses.
•Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices.
•The Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties may not meet their obligations.
•Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.
•The litigation environment in the states in which certain Entergy subsidiaries operate poses a significant risk to those businesses.
•Terrorist attacks, cyber attacks, system failures, or data breaches of Entergy’s and its subsidiaries’ or its suppliers’ technology systems may adversely affect Entergy’s results of operations.
•The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidity.
•System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings.
•As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
facilities under MISO’s functional supervision. In addition, the Utility operating companies are membersENTERGY’S BUSINESS
Entergy is an integrated energy company engaged primarily in electric power production and retail distribution operations. Entergy owns and operates power plants with approximately 30,000 MW of the SERC Reliability Corporation (SERC). SERC is a nonprofit corporation responsible for promotingelectric generating capacity, including approximately 8,000 MW of nuclear power. Entergy delivers electricity to 3.0 million utility customers in Arkansas, Louisiana, Mississippi, and improving the reliability, adequacy,Texas. Entergy had annual revenues of $10.1 billion in 2020 and critical infrastructure of the bulk power supply systems in all or portions of 16 central and southeastern states.SERC serveshad more than 13,000 employees as a regional entity with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing reliability standards within the SERC Region.
Gas Property
As of December 31, 2017, 2020.
Entergy operates primarily through two business segments: Utility and Entergy Wholesale Commodities.
•The Utility business segment includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans distributedOrleans; and transportedoperation of a small natural gas for distribution within New Orleans, Louisiana, through approximately 2,500 milesbusiness.
•The Entergy Wholesale Commodities business segment includes the ownership, operation, and decommissioning of gas pipeline. As of December 31, 2017, the gas properties of Entergy Louisiana, which arenuclear power plants located in the northern United States and around Baton Rouge, Louisiana, were not materialthe sale of the electric power produced by its operating plants to wholesale customers. Entergy Louisiana’sWholesale Commodities also provides services to other nuclear power plant owners and owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” for discussion of the operation and planned shutdown and sale of each of the Entergy Wholesale Commodities nuclear power plants.
See Note 13 to the financial position.statements for financial information regarding Entergy’s business segments.
TitleStrategy
Entergy’s strategy is to operate and grow the premier utility business that creates sustainable value for its customers, employees, communities, and owners. Entergy’s strategy to achieve its stakeholder objectives has two key aspects. First, Entergy invests in the Utility for the benefit of its customers, which supports steady, predictable growth in earnings and dividends. Second, Entergy manages risks by ensuring its Utility investments are customer-centric, supported by progressive regulatory constructs, and executed with disciplined project management. Entergy’s strategy for the Entergy Wholesale Commodities business segment is to continue to manage the risk of its operating portfolio as Entergy completes its exit from the merchant power business.
Utility
The Utility operating companies’ generating stations are generally located on properties owned in fee simple. Most of the substations and transmission and distribution lines are constructed on private property or public rights-of-way pursuant to easements, servitudes, or appropriate franchises. Some substation properties are owned in fee simple. The Utility operating companies generally have the right of eminent domain, whereby they may perfect title to, or secure easements or servitudes on, private property for theirbusiness segment includes five retail electric utility operations.
Substantially all of the physical properties and assets owned bysubsidiaries: Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas,Texas. These companies generate, transmit, distribute, and sell electric power to retail and wholesale customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy Louisiana and Entergy New Orleans also provide natural gas utility services to customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. Also included in the Utility is System Energy, are subject to the liens of mortgages securing bonds issued by those companies. The Lewis Creek generating station is owned by GSG&T, Inc., a wholly-owned subsidiary of Entergy Texas,Corporation that owns or leases 90 percent of Grand Gulf. System Energy sells its power and capacity from Grand Gulf at wholesale to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. The five retail utility subsidiaries are each regulated by the FERC and by state utility commissions, or, in the case of Entergy New Orleans, the City Council. System Energy is not subject toregulated by the FERC because all of its mortgage lien. Lewis Creektransactions are at wholesale. The overall generation portfolio of the Utility, which relies heavily on natural gas and nuclear generation, is leased to and operated by Entergy Texas.
Fuel Supply
The sources of generation and average fuel cost per kWhconsistent with Entergy’s strong support for the Utility operating companies and System Energy for the years 2015-2017 were:environment.
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | Natural Gas | | Nuclear | | Coal | | Purchased Power | | MISO Purchases |
Year | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh |
2017 | | 38 | | 2.60 |
| | 26 | | 0.86 |
| | 8 | | 2.35 |
| | 8 | | 4.02 |
| | 20 | | 3.09 |
|
2016 | | 41 | | 2.44 |
| | 28 | | 0.63 |
| | 7 | | 2.65 |
| | 9 | | 3.71 |
| | 15 | | 3.13 |
|
2015 | | 35 | | 2.65 |
| | 31 | | 0.85 |
| | 7 | | 2.85 |
| | 11 | | 3.63 |
| | 16 | | 3.24 |
|
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Customers
Actual
As of December 31, 2020, the Utility operating companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Electric Customers | | Gas Customers |
| Area Served | | (In Thousands) | | (%) | | (In Thousands) | | (%) |
Entergy Arkansas | Portions of Arkansas | | 722 | | | 25 | % | | | | |
Entergy Louisiana | Portions of Louisiana | | 1,096 | | | 37 | % | | 94 | | | 47 | % |
Entergy Mississippi | Portions of Mississippi | | 456 | | | 15 | % | | | | |
Entergy New Orleans | City of New Orleans | | 207 | | | 7 | % | | 108 | | | 53 | % |
Entergy Texas | Portions of Texas | | 473 | | | 16 | % | | | | |
Total customers | | | 2,954 | | | 100 | % | | 202 | | | 100 | % |
Electric Energy Sales
The electric energy sales of the Utility operating companies are subject to seasonal fluctuations, with the peak sales period normally occurring during the third quarter of each year. On August 10, 2020, Entergy reached a 2020 peak demand of 21,340 MWh, compared to the 2019 peak of 21,598 MWh recorded on August 12, 2019. Selected electric energy sales data is shown in the table below:
Selected 2020 Electric Energy Sales Data
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy (a) |
| (In GWh) |
Sales to retail customers | 20,749 | | | 53,896 | | | 12,402 | | | 5,447 | | | 18,677 | | | — | | | 111,170 | |
Sales for resale: | | | | | | | | | | | | | |
Affiliates | 1,659 | | | 5,585 | | | — | | | — | | | 1,203 | | | 5,849 | | | — | |
Others | 4,198 | | | 2,365 | | | 4,316 | | | 1,969 | | | 810 | | | — | | | 13,658 | |
Total | 26,606 | | | 61,846 | | | 16,718 | | | 7,416 | | | 20,690 | | | 5,849 | | | 124,828 | |
Average use per residential customer (kWh) | 12,633 | | | 14,576 | | | 14,093 | | | 12,315 | | | 14,829 | | | — | | | 13,917 | |
(a)Includes the effect of intercompany eliminations.
The following table illustrates the Utility operating companies’ 2020 combined electric sales volume as a percentage of total electric sales volume, and 2020 combined electric revenues as a percentage of total 2020 electric revenue, each by customer class.
| | | | | | | | | | | | | | |
Customer Class | | % of Sales Volume | | % of Revenue |
Residential | | 28.2 | | 39.2 |
Commercial | | 21.2 | | 25.4 |
Industrial (a) | | 37.7 | | 25.8 |
Governmental | | 2.0 | | 2.3 |
Wholesale/Other | | 10.9 | | 7.3 |
(a)Major industrial customers are primarily in the petroleum refining and chemical industries.
See “Selected Financial Data” for each of the Utility operating companies for the detail of their sales by customer class for 2016-2020.
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Entergy Corporation, Utility operating companies, and System Energy
Selected 2020 Natural Gas Sales Data
Entergy New Orleans and Entergy Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Louisiana sold 9,467,899 and 6,268,003 Mcf, respectively, of natural gas to retail customers in 2020. In 2020, 99% of Entergy Louisiana’s operating revenue was derived from the electric utility business, and only 1% from the natural gas distribution business. For Entergy New Orleans, 88% of operating revenue was derived from the electric utility business and 12% from the natural gas distribution business in 2020.
Following is data concerning Entergy New Orleans’s 2020 retail operating revenue sources.
| | | | | | | | | | | | | | |
Customer Class | | Electric Operating Revenue | | Natural Gas Operating Revenue |
Residential | | 48% | | 51% |
Commercial | | 35% | | 25% |
Industrial | | 5% | | 18% |
Governmental/Municipal | | 12% | | 6% |
Retail Rate Regulation
General (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas)
Each Utility operating company regularly participates in retail rate proceedings. The status of material retail rate proceedings is described in Note 2 to the financial statements. Certain aspects of the Utility operating companies’ retail rate mechanisms are discussed below.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Rate base (in billions) | | Current authorized return on common equity | | Weighted average cost of capital (after-tax) | | Equity ratio | | Regulatory construct | |
| | | | | | | | | | | |
Entergy Arkansas | | $8.4 (a) | | 9.25% - 10.25% | | 5.04% | | 36.6% | | - forward test year formula rate plan through 2021 test year (i)
- riders: MISO, capacity, Grand Gulf, tax adjustment, energy efficiency, fuel and purchased power | |
| | | | | | | | | | | |
Entergy Louisiana (electric) | | $11.9 (b) | | 9.2% - 10.4% | | 6.97% | | 48.63% | | - formula rate plan through 2019 test year (j)
- riders/specific recovery: MISO, capacity, transmission, fuel | |
| | | | | | | | | | | |
Entergy Louisiana (gas) | | $0.08 (c) | | 9.3% - 10.3% | | 6.96% | | 48.37% | | - gas rate stabilization plan
- rider: gas infrastructure | |
| | | | | | | | | | | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Entergy Mississippi | | $3.0 (d) | | 8.89% - 10.93% | | 6.82% | | 49.09% | | - formula rate plan with forward-looking features
- riders: power management, Grand Gulf, fuel, MISO, unit power cost, storm damage, energy efficiency, ad valorem tax adjustment, vegetation, grid modernization, restructuring credit | |
| | | | | | | | | | | |
Entergy New Orleans (electric) | | $0.8 (e) | | 9.35% | | 7.09% | | 50% | | - formula rate plan with forward-looking features
- riders/specific recovery: fuel and purchased power, MISO, energy efficiency, environmental | |
| | | | | | | | | | | |
Entergy New Orleans (gas) | | $0.1 (e) | | 9.35% | | 7.09% | | 50% | | - formula rate plan with forward-looking features
- rider: purchased gas | |
| | | | | | | | | | | |
Entergy Texas | | $2.4 (f) | | 9.65% | | 7.73% | | 50.9% | | - rate case
- riders: fuel, distribution and transmission, generation, rate case expenses, AMI surcharge, tax reform, among others | |
| | | | | | | | | | | |
System Energy | | $1.6 (g) | | 10.94% (h) | | 8.57 % | | 65% (h) | | - monthly cost of service | |
(a)Based on 2021 test year.
(b)Based on December 31, 2019 test year and excludes approximately $800 million for the Lake Charles Power Station and $300 million for the Washington Parish Energy Center, each included in the capacity rider, and $400 million of transmission plant, included in the transmission rider.
(c)Based on September 30, 2019 test year.
(d)Based on 2020 forward test year and excludes approximately $300 million for the Choctaw Generating Station, included in interim capacity mechanism.
(e)Based on December 31, 2018 test year and known and measurables through December 31, 2019. Electric rate base excludes approximately $190 million for New Orleans Power Station and $40 million for New Orleans Solar Station.
(f)Based on December 31, 2017 test year and excludes $1.0 billion in cost recovery riders.
(g)Based on calculation as of December 31, 2020.
(h)See Note 2 to the financial statements for discussion of ongoing proceedings at the FERC challenging System Energy’s authorized return on common equity and capital structure.
(i)See Note 2 to the financial statements for discussion of Entergy Arkansas’s pending formula rate plan extension request.
(j)See Note 2 to the financial statements for discussion of Entergy Louisiana’s pending formula rate plan extension request.
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Entergy Corporation, Utility operating companies, and System Energy
Entergy Arkansas
Fuel and Purchased Power Cost Recovery
Entergy Arkansas’s rate schedules include an energy cost recovery rider to recover fuel and purchased power costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy cost for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs. In December 2007 the APSC issued an order stating that Entergy Arkansas’s energy cost recovery rider will remain in effect, and any future termination of the rider would be subject to eighteen months advance notice by the APSC, which would occur following notice and hearing.
Production Cost Allocation Rider
Entergy Arkansas has in place an APSC-approved production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of System Agreement proceedings.
Entergy Louisiana
Fuel Recovery
Entergy Louisiana’s rate schedules include a fuel adjustment clause designed to recover the cost of fuel and purchased power costs. The fuel adjustment clause contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers, including carrying charges. See Note 2 to the financial statements for a discussion of proceedings related to audits of Entergy Louisiana’s fuel adjustment clause filings.
To help stabilize electricity costs, Entergy Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Louisiana historically hedged approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity was reviewed on an annual basis. In January 2018, Entergy Louisiana filed an application with the LPSC to suspend these seasonal hedging programs and implement financial hedges with terms up to five years for a portion of its natural gas exposure, which was approved in November 2018.
Entergy Louisiana’s gas rates include a purchased gas adjustment clause based on estimated gas costs for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
Retail Rates - Gas
In accordance with the settlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the
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Entergy Corporation, Utility operating companies, and System Energy
investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of the upper end of the earnings band as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.
Other
In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and the second is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the LPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax obligation at the parent level of a consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020.
Entergy Mississippi
Fuel Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.
To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
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Entergy Corporation, Utility operating companies, and System Energy
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.
Formula Rate Plan
In August 2012 the MPSC opened inquiries to review whether the current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan was still appropriate or could be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan proceeding. In March 2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans. The docket remains open.
Entergy New Orleans
Fuel Recovery
Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.
Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of its natural gas hedging program consistent with the City Council’s stated policy objectives. The program uses financial instruments to hedge exposure to volatility in the wholesale price of natural gas purchased to serve Entergy New Orleans gas customers. Entergy New Orleans hedges up to 25% of actual gas sales made during the winter months.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy New Orleans’s efforts to recover storm-related costs.
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Entergy Corporation, Utility operating companies, and System Energy
Energy Efficiency Programs
A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. The rate settlement provided an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provided a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. In January 2015 the City Council approved funding for the Energy Smart program from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In April 2017 the City Council approved an implementation plan for the Energy Smart program from April 2017 through December 2019. The City Council directed that the $11.8 million balance reported for Energy Smart funds be used to continue funding the program for Entergy New Orleans’s legacy customers and that the Energy Smart Algiers program continue to be funded through the Algiers fuel adjustment clause, until additional customer funding is required for the legacy customers. In September 2017, Entergy New Orleans filed a supplemental plan and proposed several options for an interim cost recovery mechanism necessary to recover program costs during the period between when existing funds directed to Energy Smart programs are depleted and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect. In December 2017 the City Council approved an energy efficiency cost recovery rider as an interim funding mechanism for Energy Smart, subject to verification that no additional funding sources exist. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. See Note 2 to the financial statements for discussion of Entergy New Orleans’s application with the City Council seeking approval of an implementation plan for the Energy Smart program from April 2020 through December 2022.
Entergy Texas
Fuel Recovery
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included in base rates. Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. The PUCT fuel cost proceedings are discussed in Note 2 to the financial statements.
At the PUCT’s April 2013 open meeting, the PUCT Commissioners discussed their view that a purchased power capacity rider was good public policy. The PUCT issued an order in May 2013 adopting the rule allowing for a purchased power capacity rider, subject to an offsetting adjustment for load growth. The rule, as adopted, also includes a process for obtaining pre-approval by the PUCT of purchased power agreements. Entergy Texas has not exercised the option to recover its capacity costs under the new rider mechanism, but will continue to evaluate the benefits of utilizing the new rider to recover future capacity costs.
Electric Industry Restructuring
In June 2009, a law was enacted in Texas that required Entergy Texas to cease all activities relating to Entergy Texas’s transition to competition. The law allows Entergy Texas to remain a part of the SERC Reliability Corporation (SERC) Region, although it does not prevent Entergy Texas from joining another power region. The law provides that proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding
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exist. Under the law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT’s certification of Entergy Texas’s power region.
The law also contains provisions that allow Entergy Texas to take advantage of a cost recovery mechanism that permits annual filings for the recovery of reasonable and necessary expenditures for transmission infrastructure improvement and changes in wholesale transmission charges. This mechanism was previously available to other non-ERCOT Texas utility companies, but not to Entergy Texas.
The law further amended already existing law that had required Entergy Texas to propose for PUCT approval a tariff to allow eligible customers the ability to contract for competitive generation. The amending language in the law provides, among other things, that: 1) the tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers who choose not to participate in the tariff; 2) Entergy Texas shall “purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer;” and 3) Entergy Texas shall provide and price transmission service and ancillary services under that tariff at a rate that is unbundled from its cost of service. The law directs that the PUCT may not issue an order on the tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction.
The PUCT determined that unrecovered costs that may be recovered through the rider consist only of those costs necessary to implement and administer the competitive generation program and do not include lost revenues or embedded generation costs. The amount of customer load that may be included in the competitive generation service program is limited to 115 MW.
In September 2011 the PUCT adopted a proposed rule implementing a distribution cost recovery factor to recover capital and capital-related costs related to distribution infrastructure. The distribution cost recovery factor permits utilities once per year to implement an increase or decrease in rates above or below amounts reflected in base rates to reflect depreciation expense, federal income tax and other taxes, and return on investment. The distribution cost recovery factor rider may be changed a maximum of four times between base rate cases.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery factor rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas franchises are considered to be contracts and, therefore, are terminable pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.
Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
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Entergy Corporation, Utility operating companies, and System Energy
Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas, and holds non-exclusive franchises to provide electric service in approximately 68 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire over the period 2020-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
Property and Other Generation Resources
Owned Generating Stations
The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2020, is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Owned and Leased Capability MW(a) |
Company | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
Entergy Arkansas | | 5,175 | | | 2,091 | | | 1,817 | | | 1,194 | | | 73 | | | — | |
Entergy Louisiana | | 11,317 | | | 8,827 | | | 2,144 | | | 346 | | | — | | | — | |
Entergy Mississippi | | 3,347 | | | 2,929 | | | — | | | 416 | | | — | | | 2 | |
Entergy New Orleans | | 665 | | | 638 | | | — | | | — | | | — | | | 27 | |
Entergy Texas | | 2,260 | | | 2,005 | | | — | | | 255 | | | — | | | — | |
System Energy | | 1,256 | | | — | | | 1,256 | | | — | | | — | | | — | |
Total | | 24,020 | | | 16,490 | | | 5,217 | | | 2,211 | | | 73 | | | 29 | |
(a)“Owned and Leased Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.
Summer peak load for the Utility has averaged 21,591 MW over the previous decade.
The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 8,801 MW of new long-term resources and the deactivation of about 4,664 MW of legacy generation. As MISO market participants, the Utility operating companies also participate in MISO’s Day Ahead and Real Time Energy and Ancillary Services markets to economically dispatch generation and purchase energy to serve customers reliably and at the lowest reasonable cost.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Other Generation Resources
RFP Procurements
The Utility operating companies from time to time issue requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies. The RFPs issued by the Utility operating companies have sought resources needed to meet near-term MISO reliability requirements as well as long-term requirements through a broad range of wholesale power products, including certainlimited-term (1 to 3 years) and long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
•Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine J. Wayne Leonard Power Station (previously referred to as the St. Charles generating facility) at its existing Little Gypsy electric generating station. The facility began commercial operation in May 2019;
•Entergy Texas’s construction of the 993 MW, combined-cycle, gas turbine Montgomery County Power Station at its existing Lewis Creek electric generating station. The facility began commercial operation in January 2021;
•Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station site. The facility began commercial operation in March 2020;
•In October 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the facility is scheduled to be in service by early 2022;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020 and the facility is scheduled to be in service by the end of 2021;
•Entergy New Orleans received regulatory approval in August 2019 to construct the New Orleans Solar Station (a 20 MW self-build solar project) located at the NASA Michoud Facility.The facility was placed in service in December 2020;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Lee County, Arkansas. In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2022;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2023; and
•In June 2020, Entergy Texas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 1,200 acres in Liberty County near Dayton, Texas.In September 2020, Entergy Texas filed a petition with the PUCT seeking a finding that the transaction is in the public interest and requesting all necessary approvals.Closing is expected to occur by the end of 2023.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:
•River Bend’s 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
•Entergy Arkansas’s wholesale base load capacity life-of-unit PPAs executed in 2003 totaling approximately 220 MW between Entergy Arkansas and Entergy Louisiana (110 MW) and between Entergy Arkansas and Entergy New Orleans (110 MW) related to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which had not been included in Entergy Arkansas’s retail rates);
•In May 2011, Entergy Texas and Calpine Energy Services, L.P. executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. Entergy Louisiana purchases 50% of the facility’s capacity and energy from affiliates under lifeEntergy Texas. In July 2014, LS Power purchased the Carville Energy Center and replaced Calpine Energy Services as the counterparty to the agreement;
•In September 2012, Entergy Gulf States Louisiana executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 MW when available, from Rain CII Carbon LLC’s petroleum coke calcining facility in Sulphur, Louisiana. The facility began commercial operation in May 2013. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with the facility;
•In March 2013, Entergy Gulf States Louisiana executed a 20-year agreement for 8.5 MW from Agrilectric Power Partners, LP’s refurbished rice hull-fueled electric generation facility located in Lake Charles, Louisiana. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with Agrilectric;
•In September 2013, Entergy Louisiana executed a 10-year agreement with TX LFG Energy, LP, a wholly-owned subsidiary of unitMontauk Energy Holdings, LLC, to purchase approximately 3 MW from its landfill gas-fueled power generation facility located in Cleveland, Texas;
•Entergy Mississippi’s cost-based purchase, beginning in January 2013, of 90 MW from Entergy Arkansas’s share of Grand Gulf (only 60 MW of this PPA came through the RFP process). Cost recovery for the 90 MW was approved by the MPSC in January 2013;
•In April 2015, Entergy Arkansas and Stuttgart Solar, LLC executed a 20-year agreement for 81 MW from a solar photovoltaic electric generation facility located near Stuttgart, Arkansas. The APSC approved the project and deliveries pursuant to that agreement commenced in June 2018;
•In November 2016, Entergy Louisiana and LS Power executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. The transaction received regulatory approval and will begin in June 2022;
•In November 2016, Entergy Louisiana and Occidental Chemical Corporation executed a 10-year agreement for 500 MW from the Taft Cogeneration facility located in Hahnville, Louisiana. The transaction received regulatory approval and began in June 2018;
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
•In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021;
•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a five-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021; and
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a solar photovoltaic electric generating facility located in Polk County, Texas.The PPA is expected to start when the facility reaches commercial operation in 2023.
In April 2020, Entergy Services, on behalf of Entergy Texas, issued an RFP for combined-cycle gas turbine capacity and energy resources. The RFP was seeking up to 1,000 MW - 1,200 MW of capacity, capacity-related benefits, energy, other electric products, and environmental attributes, if any, from a single generation resource located in the “Eastern Region” of Entergy Texas’s service area. In December 2020, Entergy Texas posted notice that it has elected to proceed with the self-build alternative, Orange County Power Station. The self-build alternative will be conditioned on receipt of required internal and regulatory approvals.
In June 2020, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic resources. The RFP was seeking 300 MW of energy, capacity, capacity-related benefits, other electric products, and environmental attributes from eligible new-build solar photovoltaic generation resources. In December 2020, Entergy Louisiana concluded evaluations of the RFP. Three proposals have been placed on the primary selection list and two proposals have been placed on the secondary selection list. Negotiations are currently in progress.
In January 2021, Entergy Texas provided notice that it intends to issue an RFP for solar generation resources. The RFP is seeking a minimum of 200 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements including the Unit Power Sales Agreement, are:that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Texas customers.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural Gas | | Nuclear | | Coal | | Purchased Power (d) | | MISO Purchases (e) |
| 2017 | | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 | | 2018 |
Entergy Arkansas (a) | 28 | % | | 33 | % | | 49 | % | | 51 | % | | 18 | % | | 15 | % | | — | % | | 1 | % | | 5 | % | | — |
Entergy Louisiana | 38 | % | | 49 | % | | 26 | % | | 33 | % | | 3 | % | | 4 | % | | 9 | % | | 14 | % | | 24 | % | | — |
Entergy Mississippi (b) | 47 | % | | 55 | % | | 18 | % | | 30 | % | | 13 | % | | 15 | % | | — | % | | — |
| | 22 | % | | — |
Entergy New Orleans (b) | 53 | % | | 57 | % | | 33 | % | | 41 | % | | 2 | % | | 1 | % | | — | % | | 1 | % | | 12 | % | | — |
Entergy Texas | 30 | % | | 33 | % | | 10 | % | | 17 | % | | 7 | % | | 9 | % | | 28 | % | | 41 | % | | 25 | % | | — |
System Energy (c) | — |
| | — |
| | 100 | % | | 100 | % | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
Utility (a) (b) | 38 | % | | 44 | % | | 26 | % | | 36 | % | | 8 | % | | 9 | % | | 8 | % | | 11 | % | | 20 | % | | — |
| |
(a) | Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2017 and is expected to provide about less than1% of its generation in 2018. |
| |
(b) | Solar power provided less than 1% of Entergy Mississippi’s and Entergy New Orleans's generation in 2017 and is expected to provide less than 1% of each of Entergy Mississippi’s and Entergy New Orleans's generation in 2018. |
| |
(c) | Capacity and energy from System Energy’s interest in Grand Gulf is allocated as follows under the Unit Power Sales Agreement: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%. Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. |
| |
(d) | Excludes MISO purchases |
| |
(e) | In December 2013, Entergy integrated its transmission system into the MISO RTO. Entergy offers all of its generation into the MISO energy market on a day-ahead and real-time basis and bids for power in the MISO energy market to serve the demand of its customers, with MISO making dispatch decisions. MISO purchases cannot be projected for 2018. |
Some of the Utility’s gas-fired plants are also capable of using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in 2018, it is possible that various operational events including weather or pipeline maintenance may require the use of fuel oil.
Natural Gas
Entergy Louisiana and Entergy New Orleans also distribute natural gas to retail customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. Gas transferred to customers is measured by a meter at the customer’s property. Entergy issues monthly invoices to customers at rates approved by regulators for the volume of gas transferred to date.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Competitive Businesses Revenues
The Entergy Wholesale Commodities segment derives almost all of its revenue from sales of electric power and capacity produced by its operating plants to wholesale customers. The majority of Entergy Wholesale Commodities’ revenues are from Entergy’s nuclear power plants located in the northern United States. Entergy issues monthly invoices to the counterparties for these electric sales at the respective contracted or ISO market rate of electricity and related services provided during the previous month.
Almost all of the Palisades nuclear plant output is sold under a 15-year PPA with Consumers Energy, executed as part of the acquisition of the plant in 2007 and expiring in April 2022. Prices under the original PPA range from $43.50/MWh in 2007 to $61.50/MWh in 2022, and the average price under the PPA is $51/MWh. Entergy executed an additional PPA to cover the period from the expiration of the original PPA through final shutdown in May 2022, at a price of $24.14/MWh. Entergy issues monthly invoices to Consumers Energy for electric sales based on the actual output of electricity and related services provided during the previous month at the contract price. The PPA was at below-market prices at the time of the acquisition and Entergy amortizes a liability to revenue over the life of the agreement. The amount amortized each period is based upon the present value, calculated at the date of acquisition, of each year’s difference between revenue under the agreement and revenue based on estimated market prices. Amounts amortized to revenue were $11 million in 2020, $10 million in 2019, and $6 million in 2018. Amounts to be amortized to revenue through the remaining life of the agreement will be approximately $12 million in 2021 and $5 million in 2022.
Practical Expedients and Exceptions
Entergy has elected not to disclose the value of unsatisfied performance obligations for contracts with an original expected term of one year or less, or for revenue recognized in an amount equal to what Entergy has the right to bill the customer for services performed.
Most of Entergy’s contracts, except in a few cases where there are defined minimums or stated terms, are on demand. This results in customer bills that vary each month based on an approved tariff and usage. Entergy imposes monthly or annual minimum requirements on some customers primarily as credit and cost recovery guarantees and not as pricing for unsatisfied performance obligations. These minimums typically expire after the initial term or when specified costs have been recovered. The minimum amounts are part of each month’s bill and recognized as revenue accordingly. Some of the subsidiaries within the Entergy Wholesale Commodities segment have operations and maintenance services contracts that have fixed components and terms longer than one year. The total fixed consideration related to these unsatisfied performance obligations, however, is not material to Entergy revenues.
Recovery of Fuel Costs
Entergy’s Utility operating companies’ rate schedules include either fuel adjustment clauses or fixed fuel factors, which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Where the fuel component of revenues is based on a pre-determined fuel cost (fixed fuel factor), the fuel factor remains in effect until changed as part of a general rate case, fuel reconciliation, or fixed fuel factor filing. System Energy’s operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are based on System Energy’s common equity funds allocable to its net investment in Grand Gulf, plus System Energy’s effective interest cost for its debt allocable to its investment in Grand Gulf.
Taxes Imposed on Revenue-Producing Transactions
Governmental authorities assess taxes that are both imposed on and concurrent with a specific revenue-producing transaction between a seller and a customer, including, but not limited to, sales, use, value added, and
Entergy Corporation and Subsidiaries
Notes to Financial Statements
some excise taxes. Entergy presents these taxes on a net basis, excluding them from revenues.
Allowance for doubtful accounts
The allowance for doubtful accounts reflects Entergy’s best estimate of expected losses on its accounts receivable balances. Due to the essential nature of utility services, Entergy has historically experienced a low rate of default on its accounts receivables. Due to the effect of the COVID-19 pandemic on customer receivables, however, Entergy recorded an increase in its allowance for doubtful accounts, as shown below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| (In Millions) |
Balance as of December 31, 2019 | $7.4 | | | $1.2 | | | $1.9 | | | $0.6 | | | $3.2 | | | $0.5 | |
Provisions (a) | 109.0 | | | 16.2 | | | 43.7 | | | 18.8 | | | 14.1 | | | 16.2 | |
Write-offs | (8.6) | | | (1.8) | | | (3.5) | | | (1.2) | | | (1.0) | | | (1.1) | |
Recoveries | 9.9 | | | 2.7 | | | 3.6 | | | 1.3 | | | 1.1 | | | 1.2 | |
Balance as of December 31, 2020 | $117.7 | | | $18.3 | | | $45.7 | | | $19.5 | | | $17.4 | | | $16.8 | |
(a)Provisions include estimated incremental bad debt expenses resulting from the COVID-19 pandemic of $87.1 million for Entergy, $10.5 million for Entergy Arkansas, $36 million for Entergy Louisiana, $15.5 million for Entergy Mississippi, $12.2 million for Entergy New Orleans, and $12.9 million for Entergy Texas that have been deferred as regulatory assets. See Note 2 to the financial statements for discussion of the COVID-19 orders issued by retail regulators.
The allowance for currently expected credit losses is calculated as the historical rate of customer write-offs multiplied by the current accounts receivable balance, taking into account the length of time the receivable balances have been outstanding. Although the rate of customer write-offs has historically experienced minimal variation, management monitors the current condition of individual customer accounts to manage collections and ensure bad debt expense is recorded in a timely manner.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 20. QUARTERLY FINANCIAL DATA (UNAUDITED) (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Operating results for the four quarters of 2020 and 2019 for Entergy Corporation and subsidiaries were:
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | Operating Income | | Consolidated Net Income | | Net Income Attributable to Entergy Corporation |
| (In Thousands) |
2020: | | | |
First Quarter | $2,427,179 | | | $399,756 | | | $123,294 | | | $118,714 | |
Second Quarter | $2,412,788 | | | $439,311 | | | $365,113 | | | $360,533 | |
Third Quarter | $2,903,568 | | | $778,016 | | | $525,699 | | | $521,119 | |
Fourth Quarter | $2,370,101 | | | $152,112 | | | $392,547 | | | $387,968 | |
2019: | | | |
First Quarter | $2,609,584 | | | $283,254 | | | $258,646 | | | $254,537 | |
Second Quarter | $2,666,209 | | | $338,775 | | | $240,533 | | | $236,424 | |
Third Quarter | $3,140,575 | | | $519,929 | | | $369,459 | | | $365,240 | |
Fourth Quarter | $2,462,305 | | | $248,539 | | | $389,606 | | | $385,025 | |
Earnings per average common share
| | | | | | | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 |
| Basic | | Diluted | | Basic | | Diluted |
First Quarter | $0.59 | | | $0.59 | | | $1.34 | | | $1.32 | |
Second Quarter | $1.80 | | | $1.79 | | | $1.22 | | | $1.22 | |
Third Quarter | $2.60 | | | $2.59 | | | $1.84 | | | $1.82 | |
Fourth Quarter | $1.95 | | | $1.93 | | | $1.96 | | | $1.94 | |
Results of operations for 2020 include resolution of the 2014-2015 IRS audit, which resulted in a reduction in deferred income tax expense of $230 million that includes a $396 million reduction in deferred income tax expense at Utility related to the basis of assets contributed in the 2015 Entergy Louisiana and Entergy Gulf States Louisiana business combination, including the recognition of previously uncertain tax positions, and deferred income tax expense of $105 million at Entergy Wholesale Commodities and $61 million at Parent and Other resulting from the revaluation of net operating losses as a result of the release of the reserves. See Note 3 to the financial statements for further discussion of the IRS audit resolution.
Results of operations for 2019 include: 1) a loss of $190 million ($156 million net-of-tax) as a result of the sale of the Pilgrim plant in August 2019; 2) a $156 million reduction in income tax expense recognized by Entergy Wholesale Commodities as a result of an internal restructuring; and 3) impairment charges of $100 million ($79 million net-of-tax) due to costs being charged directly to expense as incurred as a result of the impaired value of the Entergy Wholesale Commodities nuclear plants’ long-lived assets due to the significantly reduced remaining estimated operating lives associated with management’s strategy to exit the Entergy Wholesale Commodities’ merchant power business. See Note 3 to the financial statements for further discussion of the internal restructuring. See Note 14 to the financial statements for further discussion of the sale of the Pilgrim plant.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The business of the Utility operating companies is subject to seasonal fluctuations with the peak periods occurring during the third quarter. Operating results for the Registrant Subsidiaries for the four quarters of 2020 and 2019 were:
Operating Revenues
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| (In Thousands) |
2020: | | | | | | | | | | | |
First Quarter | $481,912 | | | $930,647 | | | $293,922 | | | $149,302 | | | $339,336 | | | $130,664 | |
Second Quarter | $491,767 | | | $1,011,652 | | | $297,954 | | | $147,343 | | | $372,194 | | | $126,049 | |
Third Quarter | $644,389 | | | $1,120,022 | | | $356,496 | | | $182,064 | | | $494,922 | | | $148,517 | |
Fourth Quarter | $466,426 | | | $1,007,541 | | | $299,482 | | | $155,132 | | | $380,673 | | | $90,228 | |
2019: | | | | | | | | | | | |
First Quarter | $545,812 | | | $959,330 | | | $282,244 | | | $163,194 | | | $340,474 | | | $140,104 | |
Second Quarter | $542,929 | | | $1,106,317 | | | $302,737 | | | $175,793 | | | $363,580 | | | $139,009 | |
Third Quarter | $687,526 | | | $1,231,677 | | | $398,732 | | | $194,204 | | | $442,877 | | | $145,472 | |
Fourth Quarter | $483,327 | | | $987,851 | | | $339,330 | | | $153,032 | | | $342,024 | | | $148,825 | |
Operating Income
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| (In Thousands) |
2020: | | | | | | | | | | | |
First Quarter | $67,835 | | | $166,779 | | | $41,181 | | | $12,091 | | | $36,060 | | | $35,309 | |
Second Quarter | $107,949 | | | $256,412 | | | $67,705 | | | $7,602 | | | $56,443 | | | $31,236 | |
Third Quarter | $217,648 | | | $324,496 | | | $93,843 | | | $32,322 | | | $108,306 | | | $48,896 | |
Fourth Quarter | $9,126 | | | $117,134 | | | $33,466 | | | $12,397 | | | $46,040 | | | $1,303 | |
2019: | | | | | | | | | | | |
First Quarter | $42,471 | | | $153,944 | | | $30,792 | | | $16,136 | | | $16,741 | | | $31,368 | |
Second Quarter | $69,774 | | | $241,520 | | | $45,607 | | | $17,509 | | | $36,022 | | | $24,300 | |
Third Quarter | $182,176 | | | $336,754 | | | $87,024 | | | $28,876 | | | $69,510 | | | $29,086 | |
Fourth Quarter | $32,576 | | | $164,424 | | | $40,331 | | | $6,164 | | | $24,229 | | | $30,231 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Net Income
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| (In Thousands) |
2020: | | | | | | | | | | | |
First Quarter | $44,595 | | | $189,396 | | | $22,526 | | | $11,186 | | | $32,707 | | | $28,513 | |
Second Quarter | $60,170 | | | $170,459 | | | $38,893 | | | $4,929 | | | $46,868 | | | $28,991 | |
Third Quarter | $135,843 | | | $223,466 | | | $58,589 | | | $19,450 | | | $92,164 | | | $31,064 | |
Fourth Quarter | $4,624 | | | $499,031 | | | $20,575 | | | $13,773 | | | $43,334 | | | $10,563 | |
2019: | | | | | | | | | | | |
First Quarter | $39,121 | | | $127,633 | | | $15,398 | | | $9,023 | | | $21,342 | | | $23,578 | |
Second Quarter | $50,299 | | | $183,084 | | | $26,667 | | | $13,003 | | | $38,936 | | | $24,472 | |
Third Quarter | $149,716 | | | $255,260 | | | $56,237 | | | $24,908 | | | $73,224 | | | $25,031 | |
Fourth Quarter | $23,828 | | | $125,560 | | | $21,623 | | | $5,695 | | | $25,895 | | | $26,039 | |
Earnings Applicable to Common Equity/Stock
| | | | | | | | | | | | | |
| | | | | | | Entergy Texas |
| | | | | | (In Thousands) |
2020: | | | | | | | |
First Quarter | | | | | | | $32,237 | |
Second Quarter | | | | | | | $46,397 | |
Third Quarter | | | | | | | $91,694 | |
Fourth Quarter | | | | | | | $42,863 | |
2019: | | | | | | | |
First Quarter | | | | | | | $21,342 | |
Second Quarter | | | | | | | $38,936 | |
Third Quarter | | | | | | | $73,114 | |
Fourth Quarter | | | | | | | $25,425 | |
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
RISK FACTORS SUMMARY
Entergy’s business is subject to numerous risks and uncertainties that could affect its ability to successfully implement its business strategy and affect its financial results. Carefully consider all of the information in this report and, in particular, the following principal risks and all of the other specific factors described in Item 1A. of this report, “Risk Factors,” before deciding whether to invest in Entergy or the Registrant Subsidiaries.
Utility Regulatory Risks
•The impacts of the COVID-19 pandemic and responsive measures taken are highly uncertain and cannot be predicted.
•The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that can be lengthy and subject to appeal, potentially resulting in lengthy litigation and uncertainty as to ultimate results.
•The Utility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings.
•Entergy’s business could experience adverse effects related to changes to state or federal legislation or regulation.
•There remains uncertainty regarding the effect of the termination of the System Agreement on the Utility operating companies.
•The Utility operating companies are subject to risks associated with participation in the MISO markets and the allocation of transmission upgrade costs.
•A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather (including from Hurricane Laura, Hurricane Delta, and Hurricane Zeta) could have material effects on Entergy and those Utility operating companies affected by severe weather.
Nuclear Operating, Shutdown, and Regulatory Risks
•The results of operations, financial condition, and liquidity of Entergy Arkansas, Entergy Louisiana, System Energy, and Entergy Wholesale Commodities could be materially affected by the following:
◦failure to consistently operate their nuclear power plants at high capacity factors;
◦refueling outages that last longer than anticipated or unplanned outages;
◦risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication);
◦the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants;
◦risks and costs related to operating and maintaining their nuclear power plants;
◦the costs associated with the storage of the spent nuclear fuel, as well as the costs of and their ability to fully decommission their nuclear power plants;
◦the potential requirement to pay substantial retrospective premiums imposed under the Price-Anderson Act in the event of a nuclear incident, and losses not covered by insurance;
◦the risk that the decommissioning trust fund assets for the nuclear power plants may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts; and
◦new or existing safety concerns regarding operating nuclear power plants and nuclear fuel.
•Entergy Wholesale Commodities’ power plants are subject to impairment charges in certain circumstances and its nuclear power plants are exposed to price risk.
•The Entergy Wholesale Commodities business is subject to substantial governmental regulation and may be adversely affected by legislative, regulatory, or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
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General Business Risks
•Entergy and the Utility operating companies depend on access to the capital markets and, at times, may face potential liquidity constraints, which could make it more difficult to handle future contingencies. Disruptions in the capital and credit markets may adversely affect Entergy’s and its subsidiaries’ ability to meet liquidity needs, access capital and operate and grow their businesses, and the cost of capital.
•A downgrade in Entergy Corporation’s or its subsidiaries’ credit ratings could, among other things, negatively affect Entergy Corporation’s and its subsidiaries’ ability to access capital.
•Changes in tax legislation and taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s, the Utility operating companies’, and System Energy’s results of operations, financial condition, and liquidity.
•Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to complete capital projects, other capital improvements, and strategic transactions is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies.
•Failure to attract, retain, and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
•The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs (i) to fulfill their obligations related to environmental and other matters or (ii) related to reliability standards.
•Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas usage and otherwise materially affect the Utility operating companies’ results of operations.
•Entergy could be negatively affected by the effects of climate change and environmental and regulatory obligations intended to compel greenhouse gas emission reductions or increase clean or renewable energy requirements or to place a price on greenhouse gas emissions.
•Entergy is dependent on the continued and future availability and quality of water for cooling, process, and sanitary uses.
•Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices.
•The Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties may not meet their obligations.
•Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.
•The litigation environment in the states in which certain Entergy subsidiaries operate poses a significant risk to those businesses.
•Terrorist attacks, cyber attacks, system failures, or data breaches of Entergy’s and its subsidiaries’ or its suppliers’ technology systems may adversely affect Entergy’s results of operations.
•The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidity.
•System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings.
•As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock.
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ENTERGY’S BUSINESS
Entergy is an integrated energy company engaged primarily in electric power production and retail distribution operations. Entergy owns and operates power plants with approximately 30,000 MW of electric generating capacity, including approximately 8,000 MW of nuclear power. Entergy delivers electricity to 3.0 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy had annual revenues of $10.1 billion in 2020 and had more than 13,000 employees as of December 31, 2020.
Entergy operates primarily through two business segments: Utility and Entergy Wholesale Commodities.
•The Utility business segment includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operation of a small natural gas distribution business.
•The Entergy Wholesale Commodities business segment includes the ownership, operation, and decommissioning of nuclear power plants located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities also provides services to other nuclear power plant owners and owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” for discussion of the operation and planned shutdown and sale of each of the Entergy Wholesale Commodities nuclear power plants.
See Note 13 to the financial statements for financial information regarding Entergy’s business segments.
Strategy
Entergy’s strategy is to operate and grow the premier utility business that creates sustainable value for its customers, employees, communities, and owners. Entergy’s strategy to achieve its stakeholder objectives has two key aspects. First, Entergy invests in the Utility for the benefit of its customers, which supports steady, predictable growth in earnings and dividends. Second, Entergy manages risks by ensuring its Utility investments are customer-centric, supported by progressive regulatory constructs, and executed with disciplined project management. Entergy’s strategy for the Entergy Wholesale Commodities business segment is to continue to manage the risk of its operating portfolio as Entergy completes its exit from the merchant power business.
Utility
The Utility business segment includes five retail electric utility subsidiaries: Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas. These companies generate, transmit, distribute, and sell electric power to retail and wholesale customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy Louisiana and Entergy New Orleans also provide natural gas utility services to customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. Also included in the Utility is System Energy, a wholly-owned subsidiary of Entergy Corporation that owns or leases 90 percent of Grand Gulf. System Energy sells its power and capacity from Grand Gulf at wholesale to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. The five retail utility subsidiaries are each regulated by the FERC and by state utility commissions, or, in the case of Entergy New Orleans, the City Council. System Energy is regulated by the FERC because all of its transactions are at wholesale. The overall generation portfolio of the Utility, which relies heavily on natural gas and nuclear generation, is consistent with Entergy’s strong support for the environment.
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Customers
As of December 31, 2020, the Utility operating companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:
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| | | Electric Customers | | Gas Customers |
| Area Served | | (In Thousands) | | (%) | | (In Thousands) | | (%) |
Entergy Arkansas | Portions of Arkansas | | 722 | | | 25 | % | | | | |
Entergy Louisiana | Portions of Louisiana | | 1,096 | | | 37 | % | | 94 | | | 47 | % |
Entergy Mississippi | Portions of Mississippi | | 456 | | | 15 | % | | | | |
Entergy New Orleans | City of New Orleans | | 207 | | | 7 | % | | 108 | | | 53 | % |
Entergy Texas | Portions of Texas | | 473 | | | 16 | % | | | | |
Total customers | | | 2,954 | | | 100 | % | | 202 | | | 100 | % |
Electric Energy Sales
The electric energy sales of the Utility operating companies are subject to seasonal fluctuations, with the peak sales period normally occurring during the third quarter of each year. On August 10, 2020, Entergy reached a 2020 peak demand of 21,340 MWh, compared to the 2019 peak of 21,598 MWh recorded on August 12, 2019. Selected electric energy sales data is shown in the table below:
Selected 2020 Electric Energy Sales Data
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy (a) |
| (In GWh) |
Sales to retail customers | 20,749 | | | 53,896 | | | 12,402 | | | 5,447 | | | 18,677 | | | — | | | 111,170 | |
Sales for resale: | | | | | | | | | | | | | |
Affiliates | 1,659 | | | 5,585 | | | — | | | — | | | 1,203 | | | 5,849 | | | — | |
Others | 4,198 | | | 2,365 | | | 4,316 | | | 1,969 | | | 810 | | | — | | | 13,658 | |
Total | 26,606 | | | 61,846 | | | 16,718 | | | 7,416 | | | 20,690 | | | 5,849 | | | 124,828 | |
Average use per residential customer (kWh) | 12,633 | | | 14,576 | | | 14,093 | | | 12,315 | | | 14,829 | | | — | | | 13,917 | |
(a)Includes the effect of intercompany eliminations.
The following table illustrates the Utility operating companies’ 2020 combined electric sales volume as a percentage of total electric sales volume, and 2020 combined electric revenues as a percentage of total 2020 electric revenue, each by customer class.
| | | | | | | | | | | | | | |
Customer Class | | % of Sales Volume | | % of Revenue |
Residential | | 28.2 | | 39.2 |
Commercial | | 21.2 | | 25.4 |
Industrial (a) | | 37.7 | | 25.8 |
Governmental | | 2.0 | | 2.3 |
Wholesale/Other | | 10.9 | | 7.3 |
(a)Major industrial customers are primarily in the petroleum refining and chemical industries.
See “Selected Financial Data” for each of the Utility operating companies for the detail of their sales by customer class for 2016-2020.
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Selected 2020 Natural Gas Sales Data
Entergy New Orleans and Entergy Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Louisiana sold 9,467,899 and 6,268,003 Mcf, respectively, of natural gas to retail customers in 2020. In 2020, 99% of Entergy Louisiana’s operating revenue was derived from the electric utility business, and only 1% from the natural gas distribution business. For Entergy New Orleans, 88% of operating revenue was derived from the electric utility business and 12% from the natural gas distribution business in 2020.
Following is data concerning Entergy New Orleans’s 2020 retail operating revenue sources.
| | | | | | | | | | | | | | |
Customer Class | | Electric Operating Revenue | | Natural Gas Operating Revenue |
Residential | | 48% | | 51% |
Commercial | | 35% | | 25% |
Industrial | | 5% | | 18% |
Governmental/Municipal | | 12% | | 6% |
Retail Rate Regulation
General (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas)
Each Utility operating company regularly participates in retail rate proceedings. The status of material retail rate proceedings is described in Note 2 to the financial statements. Certain aspects of the Utility operating companies’ retail rate mechanisms are discussed below.
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| | Rate base (in billions) | | Current authorized return on common equity | | Weighted average cost of capital (after-tax) | | Equity ratio | | Regulatory construct | |
| | | | | | | | | | | |
Entergy Arkansas | | $8.4 (a) | | 9.25% - 10.25% | | 5.04% | | 36.6% | | - forward test year formula rate plan through 2021 test year (i)
- riders: MISO, capacity, Grand Gulf, tax adjustment, energy efficiency, fuel and purchased power | |
| | | | | | | | | | | |
Entergy Louisiana (electric) | | $11.9 (b) | | 9.2% - 10.4% | | 6.97% | | 48.63% | | - formula rate plan through 2019 test year (j)
- riders/specific recovery: MISO, capacity, transmission, fuel | |
| | | | | | | | | | | |
Entergy Louisiana (gas) | | $0.08 (c) | | 9.3% - 10.3% | | 6.96% | | 48.37% | | - gas rate stabilization plan
- rider: gas infrastructure | |
| | | | | | | | | | | |
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Entergy Mississippi | | $3.0 (d) | | 8.89% - 10.93% | | 6.82% | | 49.09% | | - formula rate plan with forward-looking features
- riders: power management, Grand Gulf, fuel, MISO, unit power cost, storm damage, energy efficiency, ad valorem tax adjustment, vegetation, grid modernization, restructuring credit | |
| | | | | | | | | | | |
Entergy New Orleans (electric) | | $0.8 (e) | | 9.35% | | 7.09% | | 50% | | - formula rate plan with forward-looking features
- riders/specific recovery: fuel and purchased power, MISO, energy efficiency, environmental | |
| | | | | | | | | | | |
Entergy New Orleans (gas) | | $0.1 (e) | | 9.35% | | 7.09% | | 50% | | - formula rate plan with forward-looking features
- rider: purchased gas | |
| | | | | | | | | | | |
Entergy Texas | | $2.4 (f) | | 9.65% | | 7.73% | | 50.9% | | - rate case
- riders: fuel, distribution and transmission, generation, rate case expenses, AMI surcharge, tax reform, among others | |
| | | | | | | | | | | |
System Energy | | $1.6 (g) | | 10.94% (h) | | 8.57 % | | 65% (h) | | - monthly cost of service | |
(a)Based on 2021 test year.
(b)Based on December 31, 2019 test year and excludes approximately $800 million for the Lake Charles Power Station and $300 million for the Washington Parish Energy Center, each included in the capacity rider, and $400 million of transmission plant, included in the transmission rider.
(c)Based on September 30, 2019 test year.
(d)Based on 2020 forward test year and excludes approximately $300 million for the Choctaw Generating Station, included in interim capacity mechanism.
(e)Based on December 31, 2018 test year and known and measurables through December 31, 2019. Electric rate base excludes approximately $190 million for New Orleans Power Station and $40 million for New Orleans Solar Station.
(f)Based on December 31, 2017 test year and excludes $1.0 billion in cost recovery riders.
(g)Based on calculation as of December 31, 2020.
(h)See Note 2 to the financial statements for discussion of ongoing proceedings at the FERC challenging System Energy’s authorized return on common equity and capital structure.
(i)See Note 2 to the financial statements for discussion of Entergy Arkansas’s pending formula rate plan extension request.
(j)See Note 2 to the financial statements for discussion of Entergy Louisiana’s pending formula rate plan extension request.
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Entergy Arkansas
Fuel and Purchased Power Cost Recovery
Entergy Arkansas’s rate schedules include an energy cost recovery rider to recover fuel and purchased power costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy cost for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs. In December 2007 the APSC issued an order stating that Entergy Arkansas’s energy cost recovery rider will remain in effect, and any future termination of the rider would be subject to eighteen months advance notice by the APSC, which would occur following notice and hearing.
Production Cost Allocation Rider
Entergy Arkansas has in place an APSC-approved production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of System Agreement proceedings.
Entergy Louisiana
Fuel Recovery
Entergy Louisiana’s rate schedules include a fuel adjustment clause designed to recover the cost of fuel and purchased power costs. The fuel adjustment clause contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers, including carrying charges. See Note 2 to the financial statements for a discussion of proceedings related to audits of Entergy Louisiana’s fuel adjustment clause filings.
To help stabilize electricity costs, Entergy Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Louisiana historically hedged approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity was reviewed on an annual basis. In January 2018, Entergy Louisiana filed an application with the LPSC to suspend these seasonal hedging programs and implement financial hedges with terms up to five years for a portion of its natural gas exposure, which was approved in November 2018.
Entergy Louisiana’s gas rates include a purchased gas adjustment clause based on estimated gas costs for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
Retail Rates - Gas
In accordance with the settlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the
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investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of the upper end of the earnings band as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.
Other
In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and the second is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the LPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax obligation at the parent level of a consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020.
Entergy Mississippi
Fuel Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.
To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
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Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.
Formula Rate Plan
In August 2012 the MPSC opened inquiries to review whether the current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan was still appropriate or could be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan proceeding. In March 2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans. The docket remains open.
Entergy New Orleans
Fuel Recovery
Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.
Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of its natural gas hedging program consistent with the City Council’s stated policy objectives. The program uses financial instruments to hedge exposure to volatility in the wholesale price of natural gas purchased to serve Entergy New Orleans gas customers. Entergy New Orleans hedges up to 25% of actual gas sales made during the winter months.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy New Orleans’s efforts to recover storm-related costs.
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Energy Efficiency Programs
A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. The rate settlement provided an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provided a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. In January 2015 the City Council approved funding for the Energy Smart program from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In April 2017 the City Council approved an implementation plan for the Energy Smart program from April 2017 through December 2019. The City Council directed that the $11.8 million balance reported for Energy Smart funds be used to continue funding the program for Entergy New Orleans’s legacy customers and that the Energy Smart Algiers program continue to be funded through the Algiers fuel adjustment clause, until additional customer funding is required for the legacy customers. In September 2017, Entergy New Orleans filed a supplemental plan and proposed several options for an interim cost recovery mechanism necessary to recover program costs during the period between when existing funds directed to Energy Smart programs are depleted and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect. In December 2017 the City Council approved an energy efficiency cost recovery rider as an interim funding mechanism for Energy Smart, subject to verification that no additional funding sources exist. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. See Note 2 to the financial statements for discussion of Entergy New Orleans’s application with the City Council seeking approval of an implementation plan for the Energy Smart program from April 2020 through December 2022.
Entergy Texas
Fuel Recovery
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included in base rates. Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. The PUCT fuel cost proceedings are discussed in Note 2 to the financial statements.
At the PUCT’s April 2013 open meeting, the PUCT Commissioners discussed their view that a purchased power capacity rider was good public policy. The PUCT issued an order in May 2013 adopting the rule allowing for a purchased power capacity rider, subject to an offsetting adjustment for load growth. The rule, as adopted, also includes a process for obtaining pre-approval by the PUCT of purchased power agreements. Entergy Texas has not exercised the option to recover its capacity costs under the new rider mechanism, but will continue to evaluate the benefits of utilizing the new rider to recover future capacity costs.
Electric Industry Restructuring
In June 2009, a law was enacted in Texas that required Entergy Texas to cease all activities relating to Entergy Texas’s transition to competition. The law allows Entergy Texas to remain a part of the SERC Reliability Corporation (SERC) Region, although it does not prevent Entergy Texas from joining another power region. The law provides that proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding
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exist. Under the law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT’s certification of Entergy Texas’s power region.
The law also contains provisions that allow Entergy Texas to take advantage of a cost recovery mechanism that permits annual filings for the recovery of reasonable and necessary expenditures for transmission infrastructure improvement and changes in wholesale transmission charges. This mechanism was previously available to other non-ERCOT Texas utility companies, but not to Entergy Texas.
The law further amended already existing law that had required Entergy Texas to propose for PUCT approval a tariff to allow eligible customers the ability to contract for competitive generation. The amending language in the law provides, among other things, that: 1) the tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers who choose not to participate in the tariff; 2) Entergy Texas shall “purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer;” and 3) Entergy Texas shall provide and price transmission service and ancillary services under that tariff at a rate that is unbundled from its cost of service. The law directs that the PUCT may not issue an order on the tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction.
The PUCT determined that unrecovered costs that may be recovered through the rider consist only of those costs necessary to implement and administer the competitive generation program and do not include lost revenues or embedded generation costs. The amount of customer load that may be included in the competitive generation service program is limited to 115 MW.
In September 2011 the PUCT adopted a proposed rule implementing a distribution cost recovery factor to recover capital and capital-related costs related to distribution infrastructure. The distribution cost recovery factor permits utilities once per year to implement an increase or decrease in rates above or below amounts reflected in base rates to reflect depreciation expense, federal income tax and other taxes, and return on investment. The distribution cost recovery factor rider may be changed a maximum of four times between base rate cases.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery factor rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas franchises are considered to be contracts and, therefore, are terminable pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.
Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
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Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas, and holds non-exclusive franchises to provide electric service in approximately 68 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire over the period 2020-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
Property and Other Generation Resources
Owned Generating Stations
The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2020, is indicated below:
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| | Owned and Leased Capability MW(a) |
Company | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
Entergy Arkansas | | 5,175 | | | 2,091 | | | 1,817 | | | 1,194 | | | 73 | | | — | |
Entergy Louisiana | | 11,317 | | | 8,827 | | | 2,144 | | | 346 | | | — | | | — | |
Entergy Mississippi | | 3,347 | | | 2,929 | | | — | | | 416 | | | — | | | 2 | |
Entergy New Orleans | | 665 | | | 638 | | | — | | | — | | | — | | | 27 | |
Entergy Texas | | 2,260 | | | 2,005 | | | — | | | 255 | | | — | | | — | |
System Energy | | 1,256 | | | — | | | 1,256 | | | — | | | — | | | — | |
Total | | 24,020 | | | 16,490 | | | 5,217 | | | 2,211 | | | 73 | | | 29 | |
(a)“Owned and Leased Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.
Summer peak load for the Utility has averaged 21,591 MW over the previous decade.
The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 8,801 MW of new long-term resources and the deactivation of about 4,664 MW of legacy generation. As MISO market participants, the Utility operating companies also participate in MISO’s Day Ahead and Real Time Energy and Ancillary Services markets to economically dispatch generation and purchase energy to serve customers reliably and at the lowest reasonable cost.
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Other Generation Resources
RFP Procurements
The Utility operating companies from time to time issue requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies. The RFPs issued by the Utility operating companies have sought resources needed to meet near-term MISO reliability requirements as well as long-term requirements through a broad range of wholesale power products, including limited-term (1 to 3 years) and long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
•Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine J. Wayne Leonard Power Station (previously referred to as the St. Charles generating facility) at its existing Little Gypsy electric generating station. The facility began commercial operation in May 2019;
•Entergy Texas’s construction of the 993 MW, combined-cycle, gas turbine Montgomery County Power Station at its existing Lewis Creek electric generating station. The facility began commercial operation in January 2021;
•Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station site. The facility began commercial operation in March 2020;
•In October 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the facility is scheduled to be in service by early 2022;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020 and the facility is scheduled to be in service by the end of 2021;
•Entergy New Orleans received regulatory approval in August 2019 to construct the New Orleans Solar Station (a 20 MW self-build solar project) located at the NASA Michoud Facility.The facility was placed in service in December 2020;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Lee County, Arkansas. In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2022;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2023; and
•In June 2020, Entergy Texas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 1,200 acres in Liberty County near Dayton, Texas.In September 2020, Entergy Texas filed a petition with the PUCT seeking a finding that the transaction is in the public interest and requesting all necessary approvals.Closing is expected to occur by the end of 2023.
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The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:
•River Bend’s 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
•Entergy Arkansas’s wholesale base load capacity life-of-unit PPAs executed in 2003 totaling approximately 220 MW between Entergy Arkansas and Entergy Louisiana (110 MW) and between Entergy Arkansas and Entergy New Orleans (110 MW) related to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which had not been included in Entergy Arkansas’s retail rates);
•In May 2011, Entergy Texas and Calpine Energy Services, L.P. executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. Entergy Louisiana purchases 50% of the facility’s capacity and energy from Entergy Texas. In July 2014, LS Power purchased the Carville Energy Center and replaced Calpine Energy Services as the counterparty to the agreement;
•In September 2012, Entergy Gulf States Louisiana executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 MW when available, from Rain CII Carbon LLC’s petroleum coke calcining facility in Sulphur, Louisiana. The facility began commercial operation in May 2013. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with the facility;
•In March 2013, Entergy Gulf States Louisiana executed a 20-year agreement for 8.5 MW from Agrilectric Power Partners, LP’s refurbished rice hull-fueled electric generation facility located in Lake Charles, Louisiana. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with Agrilectric;
•In September 2013, Entergy Louisiana executed a 10-year agreement with TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, to purchase approximately 3 MW from its landfill gas-fueled power generation facility located in Cleveland, Texas;
•Entergy Mississippi’s cost-based purchase, beginning in January 2013, of 90 MW from Entergy Arkansas’s share of Grand Gulf (only 60 MW of this PPA came through the RFP process). Cost recovery for the 90 MW was approved by the MPSC in January 2013;
•In April 2015, Entergy Arkansas and Stuttgart Solar, LLC executed a 20-year agreement for 81 MW from a solar photovoltaic electric generation facility located near Stuttgart, Arkansas. The APSC approved the project and deliveries pursuant to that agreement commenced in June 2018;
•In November 2016, Entergy Louisiana and LS Power executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. The transaction received regulatory approval and will begin in June 2022;
•In November 2016, Entergy Louisiana and Occidental Chemical Corporation executed a 10-year agreement for 500 MW from the Taft Cogeneration facility located in Hahnville, Louisiana. The transaction received regulatory approval and began in June 2018;
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
•In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021;
•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a five-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
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•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021; and
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a solar photovoltaic electric generating facility located in Polk County, Texas.The PPA is expected to start when the facility reaches commercial operation in 2023.
In April 2020, Entergy Services, on behalf of Entergy Texas, issued an RFP for combined-cycle gas turbine capacity and energy resources. The RFP was seeking up to 1,000 MW - 1,200 MW of capacity, capacity-related benefits, energy, other electric products, and environmental attributes, if any, from a single generation resource located in the “Eastern Region” of Entergy Texas’s service area. In December 2020, Entergy Texas posted notice that it has elected to proceed with the self-build alternative, Orange County Power Station. The self-build alternative will be conditioned on receipt of required internal and regulatory approvals.
In June 2020, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic resources. The RFP was seeking 300 MW of energy, capacity, capacity-related benefits, other electric products, and environmental attributes from eligible new-build solar photovoltaic generation resources. In December 2020, Entergy Louisiana concluded evaluations of the RFP. Three proposals have been placed on the primary selection list and two proposals have been placed on the secondary selection list. Negotiations are currently in progress.
In January 2021, Entergy Texas provided notice that it intends to issue an RFP for solar generation resources. The RFP is seeking a minimum of 200 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Texas customers.
Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process, including Entergy Mississippi’s January 2006 acquisition of the 480 MW, combined-cycle, gas-fired Attala power plant; Entergy Gulf States Louisiana’s March 2008 acquisition of the 322 MW, simple-cycle, gas-fired Calcasieu Generating Facility; Entergy Louisiana’s April 2011 acquisition of the 580 MW, combined-cycle, gas-fired Acadia Energy Center Unit 2; Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) March 2016 acquisitions of the 1,980 MW (summer rating), natural gas-fired, combined-cycle gas turbine Union Power Station power blocks, each rated at 495 MW (summer rating); and Entergy Mississippi’s October 2019 acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The Utility operating companies have also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.
The Washington Parish Energy Center is a 361 MW natural gas-fired peaking power plant approximately 60 miles north of New Orleans on a site Entergy Louisiana purchased from Calpine in 2019. In May 2018, Entergy Louisiana received LPSC approval of its certification application for this simple-cycle power plant to be developed pursuant to an agreement between Calpine and Entergy Louisiana. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020.
The Hardin County Peaking Facility is an existing 147 MW simple-cycle gas-fired peaking power plant in Kountze, Texas, owned by East Texas Electric Cooperative. Entergy Texas is currently seeking regulatory certification to move forward with the purchase of the facility. The facility has been in operation since January 2010.
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Power Through Program
In December 2020, Entergy Texas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation that is to be installed at commercial and industrial customer premises. If approved, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.”
Interconnections
The Utility operating companies’ generating units are interconnected to a transmission system operating at various voltages up to 500 kV. These generating units consist of steam-electric production facilities, combustion-turbine generators, pressurized and boiling water nuclear reactors, and inverter-based technologies operating in the MISO energy and ancillary services market. Entergy’s Utility operating companies are MISO market participants and are interconnected with many neighboring utilities. MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. As a Regional Transmission Organization, MISO assures consumers of unbiased regional grid management and open access to the transmission facilities under MISO’s functional supervision. In addition, the Utility operating companies are members of SERC Reliability Corporation (SERC). SERC is a nonprofit corporation responsible for promoting and improving the reliability, adequacy, and critical infrastructure of the bulk power supply systems in all or portions of 16 central and southeastern states.SERC serves as a regional entity with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing Bulk Electric System reliability standards within the SERC Region.
Gas Property
As of December 31, 2020, Entergy New Orleans distributed and transported natural gas for distribution within New Orleans, Louisiana, through approximately 2,600 miles of gas pipeline. As of December 31, 2020, the gas properties of Entergy Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Louisiana’s financial position.
Title
The Utility operating companies’ generating stations are generally located on properties owned in fee simple. Most of the substations and transmission and distribution lines are constructed on private property or public rights-of-way pursuant to easements, servitudes, or appropriate franchises. Some substation properties are owned in fee simple. The Utility operating companies generally have the right of eminent domain, whereby they may perfect title to, or secure easements or servitudes on, private property for their utility operations.
Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are subject to the liens of mortgages securing bonds issued by those companies. The Lewis Creek generating station of Entergy Texas was acquired by merger with a subsidiary of Entergy Texas and is currently not subject to the lien of the Entergy Texas indenture.
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Fuel Supply
The sources of generation and average fuel cost per kWh for the Utility operating companies and System Energy for the years 2018-2020 were:
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| | Natural Gas | | Nuclear | | Coal | | Purchased Power | | MISO Purchases |
Year | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh |
2020 | | 47 | | | 1.92 | | | 29 | | | 0.57 | | | 3 | | | 2.54 | | | 8 | | | 4.36 | | | 13 | | | 2.48 | |
2019 | | 40 | | | 2.33 | | | 28 | | | 0.73 | | | 6 | | | 2.31 | | | 8 | | | 4.86 | | | 18 | | | 2.71 | |
2018 | | 39 | | | 2.84 | | | 27 | | | 0.84 | | | 9 | | | 2.24 | | | 8 | | | 5.23 | | | 17 | | | 3.71 | |
Actual 2020 and projected 2021 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:
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| Natural Gas | | Nuclear | | Coal | | Purchased Power (d) | | MISO Purchases (e) |
| 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 |
Entergy Arkansas (a) | 24 | % | | 35 | % | | 60 | % | | 51 | % | | 10 | % | | 13 | % | | 1 | % | | 1 | % | | 5 | % | | — | |
Entergy Louisiana | 51 | % | | 59 | % | | 26 | % | | 27 | % | | 1 | % | | 2 | % | | 9 | % | | 12 | % | | 13 | % | | — | |
Entergy Mississippi (b) | 73 | % | | 69 | % | | 14 | % | | 22 | % | | 4 | % | | 9 | % | | — | | | — | | | 9 | % | | — | |
Entergy New Orleans (b) | 55 | % | | 56 | % | | 33 | % | | 40 | % | | 1 | % | | 2 | % | | 2 | % | | 2 | % | | 9 | % | | — | |
Entergy Texas | 39 | % | | 60 | % | | 11 | % | | 13 | % | | 2 | % | | 6 | % | | 23 | % | | 21 | % | | 25 | % | | — | |
System Energy (c) | — | | | — | | | 100 | % | | 100 | % | | — | | | — | | | — | | | — | | | — | | | — | |
Utility (a) (b) | 47 | % | | 55 | % | | 29 | % | | 31 | % | | 3 | % | | 6 | % | | 8 | % | | 8 | % | | 13 | % | | — | |
(a)Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2020 and is expected to provide less than 1% of its generation in 2021.
(b)Solar power provided less than 1% of Entergy Mississippi’s and Entergy New Orleans's generation in 2020 and is expected to provide less than 1% of each of Entergy Mississippi’s and Entergy New Orleans's generation in 2021.
(c)Capacity and energy from System Energy’s interest in Grand Gulf is allocated as follows under the Unit Power Sales Agreement: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%. Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.
(d)Excludes MISO purchases.
(e)In December 2013, Entergy integrated its transmission system into the MISO RTO. Entergy offers all of its generation into the MISO energy market on a day-ahead and real-time basis and bids for power in the MISO energy market to serve the demand of its customers, with MISO making dispatch decisions. The MISO purchases metric provided for 2020 is not projected for 2021.
Some of the Utility’s gas-fired plants are also capable of using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in 2021, it is possible that various operational events including weather or pipeline maintenance may require the use of fuel oil.
Natural Gas
The Utility operating companies have long-term firm and short-term interruptible gas contracts for both supply and transportation. Over 50% of the Utility operating companies’ power plants maintain some level of long-termlong-
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term firm transportation. Short-term contracts and spot-market purchases satisfy additional gas requirements. Entergy Texas owns a gas storage facility that provides reliable and flexible natural gas service to certain generating stations.
Many factors, including wellhead deliverability, storage, pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies willmay in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
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Coal
Entergy Arkansas has committed to eightseven one- to three-year and two spot contracts that will supply approximately 85% of the total coal supply needs in 2018.2021. These contracts are staggered in term so that not all contracts have to be renewed the same year. The remaining 15% of total coal requirements will be satisfied by contracts with a term of less than one year. Based on continued improved Powder River Basin (PRB) coal deliveries by rail and the high cost of alternate sources and modes of transportation, no alternative coal consumption is expected at Entergy Arkansas during 2018.2021. Coal will be transported to Arkansas via an existing transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2018.2021.
Entergy Louisiana has committed to five one- to three-year contracts that will supply approximately 90% of Nelson Unit 6 coal needs in 2018.2021. If needed, additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as for Entergy Arkansas’s plants, no alternative coal consumption is expected at Nelson Unit 6 during 2018.2021. Coal will be transported to Nelson primarily via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2018.2021.
For the year 2017,2020, coal transportation delivery rates to Entergy Arkansas-and Entergy Louisiana-operated coal-fired units waswere adequate for the majority of the year but experienced some delays in the fourth quarter of 2017. Itto meet supply needs and obligations, and it is expected that delivery times in 2021 will improve in 2018.continue to be consistent. Both Entergy Arkansas and Entergy Louisiana control a sufficient number of railcars to satisfy the rail transportation requirement.
The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2018.2021. Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.
Nuclear Fuel
The nuclear fuel cycle consists of the following:
•mining and milling of uranium ore to produce a concentrate;
•conversion of the concentrate to uranium hexafluoride gas;
•enrichment of the uranium hexafluoride gas;
•fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and
•disposal of spent fuel.
The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated
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uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the owner of a nuclear power plant.
Based upon currently planned fuel cycles, the Utility nuclear units in both the Utility and Entergy Wholesale Commodities segments have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through most of 2018 or beyond. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment is being adjusted to reflect reduced overall requirements related to the planned permanent shutdowns of the
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Palisades, Pilgrim, Indian Point 2, and Indian Point 3 plants.2023. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. There are a number of possible supply alternatives that may be accessed to mitigate any supplier performance failure, including potentially drawing upon Entergy’s inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.
The effects of market price changes may be reduced and deferred by risk management strategies, such as negotiation of floor and ceiling amounts for long-term contracts, buying for inventory or entering into forward physical contracts at fixed prices when Entergy believes it is appropriate and useful. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance reliability of conversion, enrichment, and fabrication services providers. There are fewer of these providers than for uranium. For conversion and enrichment services, like uranium, Entergy diversifies its supply by supplier and country and may take special measures as needed to ensure supply of enriched uranium for the reliable fabrication of nuclear fuel. For fabrication services, each plant is dependent upon the effective performance of the fabricator of that plant’s nuclear fuel, therefore, Entergy provides additional monitoring, inspection, and oversight for the fabrication process to assure reliability and quality.
Entergy Arkansas, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the financial statements of Entergy and the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These credit facilities are subject to periodic renewal, and the notes are issued periodically, typically for terms between three and seven years.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with threeone interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with CenterpointCenterPoint Energy Services which guarantees Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The CenterpointCenterPoint Energy Service gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans also makes interruptible spot market purchases.
Entergy Louisiana purchased natural gas for resale in 20172020 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.
Federal Regulation of the Utility
State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.
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System Agreement (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Prior to each operating company’s termination of participation in the System Agreement (Entergy Arkansas in December 2013, Entergy Mississippi in November 2015, and Entergy Louisiana, Entergy New Orleans, and Entergy Texas each in August 2016), the Utility operating companies engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which was a rate schedule approved by the FERC. Under the terms of the System Agreement, generating capacity and other power resources were jointly operated by the Utility operating companies that were participating in the System Agreement. The System Agreement provided, among other things, that parties having generating reserves greater than their allocated share of reserves (long companies) would receive payments from those parties having generating reserves that were less than their allocated share of reserves (short companies). Such payments were at amounts sufficient to cover certain of the long companies’ costs for intermediate and peaking oil/gas-fired generation, including operating expenses, fixed charges on debt, dividend requirements on preferred equity, and a fair rate of return on common equity investment. Under the System Agreement, the rates used to compensate long companies were based on costs associated with the long companies’ steam electric generating units fueled by oil or gas and having an annual average heat rate above 10,000 Btu/kWh. In addition, for all energy exchanged among the Utility operating companies under the System Agreement, the companies purchasing exchange energy were required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs. Entergy Arkansas terminated its participation in the System Agreement in December 2013. Entergy Mississippi terminated its participation in the System Agreement in November 2015. The System Agreement terminated with respect to its remaining participants in August 2016.
Although the System Agreement has terminated, certain of the Utility operating companies’ and their retail regulators are pursuing litigation involving the System Agreement at the FERC and in federal courts. The proceedings include challenges to the allocation of costs as defined by the System Agreement and other matters. See Note 2 to the financial statements for discussion of legal proceedings at the FERC and in federal courts involving the System Agreement.
Transmission and MISO Markets
OnIn December 19, 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO doesdid not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities, MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and congestion management and provides schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the markets. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. Each Utility operating company has its own transmission pricing zone and a formula rate template (included as Attachment O to the MISO tariff) used to
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establish transmission rates within MISO. The terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets and the allocation of transmission upgrade costs, are subject to regulation by the FERC.
System Energy and Related Agreements
System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In December 1995, System Energy commencedJuly 2001 a rate proceeding commenced by System Energy at the FERC. In July 2001 the rate proceedingFERC in 1995 became final, with the FERC approving a prospective 10.94% return on equity. In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas’s and Entergy Mississippi’s acceleration of Grand Gulf purchased
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power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC. See Note 2 to the financial statements for discussion of a complaintcomplaints filed with the FERC in January 2017 regarding System Energy’s return on equity.
Unit Power Sales Agreement
The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.
In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf-related costs and recovers the remaining 78% of its share in rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas’s cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans that sell a portion of the output of Entergy Arkansas’s retained share of Grand Gulf to those companies, with the remainder of the retained share being sold to Entergy Mississippi through a separate life-of-resources purchased power agreement. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted rate relief with respect to costs associated with Entergy Louisiana’s share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Entergy Louisiana retains and does not recover from retail ratepayers 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause at 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC’s approval. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of the output of Entergy Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted rate relief for those purchases by the MPSC through its annual unit power cost rate mechanism.
Availability Agreement
The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the financing by System Energy
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of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges.
The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in
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the event of a shortfall of funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.
System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for its onetwo outstanding series of first mortgage bonds. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.
Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be made directly to the holders of indebtedness that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.
The obligations of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans to make payments under the Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to the FERC for approval with respect to the terms of such sale. No such filing with the FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability Agreement, the jurisdictional portions of the Availability Agreement would be submitted to the FERC for approval.
Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement and, therefore, no payments under the Availability Agreement have ever been required. If Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their Availability Agreement obligations exceed their Unit Power Sales Agreement obligations.
The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors.
Capital Funds Agreement
System Energy and Entergy Corporation have entered into the Capital Funds Agreement, whereby Entergy Corporation has agreed to supply System Energy with sufficient capital to (i) maintain System Energy’s equity capital at an amount equal to a minimum of 35% of its total capitalization (excluding short-term debt) and (ii) permit the continued commercial operation of Grand Gulf and pay in full all indebtedness for borrowed money of System Energy when due.
Entergy Corporation has entered into various supplements to the Capital Funds Agreement. System Energy has assigned its rights under such a supplement as security for its one outstanding series of first mortgage bonds. The supplement provides that permitted indebtedness for borrowed money incurred by System Energy in connection with the financing of Grand Gulf may be secured by System Energy’s rights under the Capital Funds Agreement on a pro rata basis (except for the Specific Payments, as defined below). In addition, in the supplements to the Capital Funds Agreement relating to the specific indebtedness being secured, Entergy Corporation has agreed to make cash capital
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contributions directly to System Energy sufficient to enable System Energy to make payments when due on such indebtedness (Specific Payments). However, if there is an event of default, Entergy Corporation must make those payments directly to the holders of indebtedness benefiting from the supplemental agreements. The payments (other than the Specific Payments) must be made pro rata according to the amount of the respective obligations benefiting from the supplemental agreements.
The Capital Funds Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, upon obtaining the consent, if required, of those holders of System Energy’s indebtedness then outstanding who have received the assignments of the Capital Funds Agreement. No such consent would be required to terminate the Capital Funds Agreement or the supplement thereto at this time.
Service Companies
Entergy Services, a corporationlimited liability company wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the Utility operating companies, but also provides services to Entergy Wholesale Commodities. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas
Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson Unit 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.
Entergy Texas purchases from Entergy Louisiana pursuant to a life-of-unit purchased power agreement a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend’s nuclear and environmental liabilities that is identical to the share of the plant’s output purchased by Entergy Texas under the purchased power agreement. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements.
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
On October 1, 2015, the businesses formerly conducted by Entergy Louisiana (Old Entergy Louisiana) and Entergy Gulf States Louisiana (Old Entergy Gulf States Louisiana) were combined into a single public utility. In order to effect the business combination, under the Texas Business Organizations Code (TXBOC), Old Entergy Louisiana allocated substantially all of its assets to a new subsidiary, Entergy Louisiana Power, LLC, a Texas limited liability company (New Entergy Louisiana), and New Entergy Louisiana assumed the liabilities of Old Entergy Louisiana, in a transaction regarded as a merger under the TXBOC. Under the TXBOC, Old Entergy Gulf States Louisiana allocated substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States
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Louisiana assumed the liabilities of Old Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. New Entergy Gulf States Louisiana then merged into New Entergy Louisiana with New Entergy Louisiana surviving the merger. Thereupon, Old Entergy Louisiana changed its name from “Entergy Louisiana, LLC” to “EL Investment Company, LLC” and New Entergy Louisiana changed its name from “Entergy Louisiana Power, LLC” to “Entergy Louisiana, LLC” (Entergy Louisiana). With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Old Entergy Louisiana and Old Entergy Gulf States Louisiana. See Note 2 to the financial statements for additional discussion
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Entergy New Orleans Internal Restructuring
In November 2017, pursuant to the agreement in principle, Entergy New Orleans, Inc. undertook a multi-step restructuring, including the following:
•Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.
•Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans, Inc. allocated substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power assumed substantially all of the liabilities of Entergy New Orleans, Inc. in a transaction regarded as a merger under the TXBOC. Entergy New Orleans, Inc. remained in existence and held the membership interests in Entergy New Orleans Power.
•Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The restructuring was accounted for as a transaction between entities under common control.
Earnings RatiosEntergy Arkansas Internal Restructuring
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of Registrant Subsidiariesapproximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The Registrant Subsidiaries’ ratiostransaction was accounted for as a transaction between entities under common control.
Entergy Mississippi Internal Restructuring
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of earningsapproximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to fixed charges and ratios of earnings to combined fixed charges and preferred dividends or distributions pursuant to Item 503 of SEC Regulation S-K are as follows:a Texas corporation.
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| Ratios of Earnings to Fixed Charges Years Ended December 31, |
| 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
Entergy Arkansas | 2.87 | | 3.32 | | 2.04 | | 3.08 | | 3.62 |
Entergy Louisiana | 3.85 | | 3.57 | | 3.36 | | 3.44 | | 3.30 |
Entergy Mississippi | 4.49 | | 3.96 | | 3.59 | | 3.23 | | 3.19 |
Entergy New Orleans | 4.50 | | 4.61 | | 4.90 | | 3.55 | | 1.85 |
Entergy Texas | 2.41 | | 2.92 | | 2.22 | | 2.39 | | 1.94 |
System Energy | 4.91 | | 5.39 | | 4.53 | | 4.04 | | 5.66 |
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•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC. |
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| Ratios of Earnings to Combined Fixed Charges and Preferred Dividends or Distributions Years Ended December 31, |
| 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
Entergy Arkansas | 2.81 | | 3.09 | | 1.85 | | 2.76 | | 3.25 |
Entergy Louisiana | 3.85 | | 3.57 | | 3.24 | | 3.28 | | 3.14 |
Entergy Mississippi | 4.36 | | 3.71 | | 3.34 | | 3.00 | | 2.97 |
Entergy New Orleans | 4.24 | | 4.30 | | 4.50 | | 3.26 | | 1.70 |
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
The Registrant Subsidiaries accrue interest expense related to unrecognized tax benefits in income tax expense and do not include it in fixed charges.
Entergy Wholesale Commodities
Entergy Wholesale Commodities includes the ownership, operation, and decommissioning of nuclear power plants, located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities revenues are primarily derived from sales of energy and generation capacity from these plants. Entergy Wholesale Commodities also provides operations and management services, including decommissioningdecommissioning-related services, to nuclear power plants owned by other utilitiesnon-affiliated entities in the United States. Entergy Wholesale Commodities also includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers.
On December 29, 2014, Entergy Wholesale Commodities’ Vermont Yankee plant was removed from the grid, after 42 years of operations. The decision to close and decommission Vermont Yankee, which was announced in August 2013, was due to numerous issues including sustained low natural gas and wholesale energy prices, the high cost structure of the plant, and lack of a market structure that adequately compensates merchant nuclear plants for their environmental and fuel diversity benefits in the Northeast region. In November 2016, Entergy entered into an agreement to sell 100% of its membership interest in Entergy Nuclear Vermont Yankee, LLC to a subsidiary of NorthStar. Entergy Nuclear Vermont Yankee is the owner of the Vermont Yankee plant. The sale of Entergy Nuclear Vermont Yankee to NorthStar will include the transfer of Entergy Nuclear Vermont Yankee’s nuclear decommissioning trust fund and the asset retirement obligation for spent fuel management and decommissioning of the plant. Entergy plans to transfer all spent nuclear fuel to dry cask storage by the end of 2018 in advance of the planned transaction close. Under the sale and related agreements to be entered into at the closing, NorthStar will commit to initiate decommissioning and site restoration by 2021 and complete those activities, along with partial restoration of the Vermont Yankee site, with the exception of the independent spent fuel storage installation and switchyard, by 2030. The original completion date, as outlined in Entergy’s Post Shutdown Decommissioning Activities Report filed with the NRC, was 2075. The transaction is contingent upon certain closing conditions, including approval by the NRC; approval by the State of Vermont Public Utility Commission, including approval of site restoration standards that will be proposed as part of the transaction; the transfer of all spent nuclear fuel to dry fuel storage on the independent spent fuel storage installation; and that the market value of the assets held in the decommissioning trust fund for the Vermont Yankee Nuclear Power Station, less the hypothetical income tax on the aggregate unrealized net gain of such assets at closing, is equal to or exceeds $451.95 million, subject to adjustments.
In October 2015, Entergy determined that it would close the FitzPatrick plant at the end of its fuel cycle in January 2017. In August 2016, Entergy entered into an agreement to sell the FitzPatrick plant to Exelon. The transaction was contingent upon, among other things, the expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, the receipt of necessary regulatory approvals from the FERC, the NRC, and the Public Service Commission of the State of New York (NYPSC), and the receipt of a private letter ruling from the IRS. Because certain specified conditions were satisfied in November 2016, including the continued effectiveness of the Clean Energy Standards/Zero Emissions Credit program (CES/ZEC), the establishment of certain long-term agreements on acceptable terms with the Energy Research and Development Authority of the State of New York in connection with the CES/ZEC program, and NYPSC approval of the transaction on acceptable terms, Entergy
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refueled the FitzPatrick plant in January and February 2017. The sale closed in March 2017 after obtaining all the necessary approvals.
In October 2015, Entergy determined that it would close the Pilgrim plant. The decision came after management’s extensive analysis of the economics and operating life of the plant following the NRC’s decision in September 2015 to place the plant in its “multiple/repetitive degraded cornerstone column” (Column 4) of its Reactor Oversight Process Action Matrix. The Pilgrim plant is expected to cease operations on May 31, 2019, after refueling in the spring of 2017 and operating through the end of that fuel cycle.
In December 2015, Entergy Wholesale Commodities closed on the sale of its 583 MW Rhode Island State Energy Center, in Johnston, Rhode Island. The base sales price, excluding adjustments, was approximately $490 million. Entergy Wholesale Commodities purchased the Rhode Island State Energy Center for $346 million in December 2011.
In December 2016, Entergy announced that it had reached an agreement with Consumers Energy to terminate the existing PPA for the Palisades plant on May 31, 2018. Pursuant to the agreement, Consumers Energy would pay Entergy $172 million for the early termination of the PPA. The PPA amendment agreement was subject to regulatory approvals, including approval by the Michigan Public Service Commission. Separately, Entergy intended to shut down the Palisades nuclear power plant permanently on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle. In September 2017 the Michigan Public Service Commission issued an order conditionally approving the PPA amendment transaction, but granting Consumers Energy recovery of only $136.6 million of the $172 million requested early termination payment. As a result, Entergy and Consumers Energy agreed to terminate the PPA amendment agreement. Entergy will continue to operate Palisades under the current PPA with Consumers Energy, instead of shutting down in the fall of 2018 as previously planned. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022.
In January 2017, Entergy reached a settlement with New York State, several State agencies, and Riverkeeper, Inc., under which Indian Point 2 and Indian Point 3 will cease commercial operation by April 30, 2020 and April 30, 2021, respectively, subject to certain conditions, including New York State’s withdrawal of opposition to Indian Point’s license renewals and issuance of contested permits and similar authorizations. See Note 14 to the financial statements for a discussion of the impairment and related charges associated with the settlement with New York State.
The Indian Point settlement required New York State agencies to issue environmental certifications needed for license renewal and a renewed water discharge permit based on current plant configuration. It also required the New York State Attorney General and Riverkeeper to withdraw their contentions pending before the Atomic Safety and Licensing Board (ASLB). In exchange, Entergy commits to cease commercial operation of Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021. These actions have been completed, all New York State approvals required for the NRC to issue renewed licenses have been granted, and the ASLB has terminated proceedings before it following the withdrawal of pending contentions. The NRC is not expected to issue renewed licenses earlier than third quarter 2018, as its staff must complete updates to the record on environmental and safety matters (a supplement to the final supplemental environmental impact statement and a supplement to the final safety evaluation report).
With the settlement concerning Indian Point, Entergy has announced plans for the disposition of all of the Entergy Wholesale Commodities nuclear power plants, including the sales of Vermont Yankee and FitzPatrick, and the earlier than previously expected shutdowns of Pilgrim, Palisades, Indian Point 2, and Indian Point 3. See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.discussion of the operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
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Property
Nuclear Generating Stations
Entergy Wholesale Commodities includes the ownership of the following nuclear power plants:
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Power Plant | | Market | | In Service Year | | Acquired | | Location | | Capacity - Reactor Type | | License Expiration Date |
Pilgrim (a) | | ISO-NE | | 1972 | | July 1999 | | Plymouth, MA | | 688 MW - Boiling Water | | 2032 (a) |
Indian Point 3 (b)(a) | | NYISO | | 1976 | | Nov. 2000 | | Buchanan, NY | | 1,041 MW - Pressurized Water | | 2015 (b)2025 (a) |
Indian Point 2 (b)(a) | | NYISO | | 1974 | | Sept. 2001 | | Buchanan, NY | | 1,028 MW - Pressurized Water | | 2013 (b)2024 (a) |
Vermont Yankee (c)Palisades (b) | | IS0-NEMISO | | 19721971 | | July 2002 | | Vernon, VT | | 605 MW - Boiling Water | | 2032 (c) |
Palisades (d) | | MISO | | 1971 | | Apr. 2007 | | Covert, MI | | 811 MW - Pressurized Water | | 2031 (d)(b) |
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(a) | In October 2015, Entergy determined that it would close the Pilgrim plant no later than June 1, 2019, as discussed above. |
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(b) | In January 2017, Entergy announced that it reached a settlement with New York State to shut down Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021, and resolve all New York State-initiated legal challenges to Indian Point’s operating license renewal. See below for discussion of Indian Point 2 and Indian Point 3 entering their “period of extended operation” after expiration of the plants’ initial license terms under “timely renewal.” |
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(c) | On December 29, 2014, the Vermont Yankee plant ceased power production. In November 2016, Entergy entered into an agreement to sell 100% of the membership interest in Entergy Nuclear Vermont Yankee, to NorthStar. Entergy Nuclear Vermont Yankee is the owner of the Vermont Yankee plant. |
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(d) | In December 2016, Entergy announced that it had reached an agreement with Consumers Energy to terminate the existing PPA for the Palisades plant in 2018. Separately, and assuming regulatory approvals are obtained for the PPA termination agreement, Entergy intended to shut down the Palisades nuclear power plant permanently on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle. In September 2017, as a result of the Michigan Public Service Commission’s order, Entergy and Consumers Energy agreed to terminate the PPA amendment agreement. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022. |
In October 2015,(a)Power operations ceased at the Indian Point 2 plant in April 2020. The fuel was permanently removed from the reactor vessel and placed in the spent fuel pool in May 2020. The Indian Point 3 plant is expected to cease operations on April 30, 2021. Entergy determined that it would closeand Holtec jointly filed a license transfer application with the FitzPatrick plant atNRC in November 2019, requesting approval for the endtransfer of the fuel cycle, in January 2017, but in August 2016,Indian Point plants, along with their nuclear decommissioning trusts and decommissioning liabilities, from Entergy entered into an agreementto Holtec. The NRC approved the license transfer application on November 23, 2020.
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(b)The Palisades plant is expected to cease operations on May 31, 2022. There is a contract to sell the FitzPatrick plant to Exelon,Holtec subject to NRC and other regulatory approvals.
See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the operation and planned shutdown and sale closed in March 2017.of each of the remaining Entergy Wholesale Commodities nuclear power plants.
Entergy Wholesale Commodities also includes the ownership of two non-operating nuclear facilities, Big Rock Point in Michigan and Indian Point 1 in New York that were acquired when Entergy purchased the Palisades and Indian Point 2 nuclear plants, respectively. These facilities are in various stages of the decommissioning process.
In April 2007, Entergy submitted to the NRC a joint application to renew the operating licenses for Indian Both Big Rock Point 2 and Indian Point 3 for an additional 20 years. The original expiration dates of the NRC operating licenses for Indian Point 2 and Indian Point 3 were September 28, 2013 and December 12, 2015, respectively. Authorization1 are under contract to operate Indian Point 2 and Indian Point 3 rests on Entergy’s having timely filed a license renewal application that remains pending before the NRC. Indian Point 2 and Indian Point 3 have now enteredbe sold with their “period of extended operation” after expiration of the plants’ initial license term under “timely renewal,” which is a federal statutory rule of general applicability providing for extension of a license for which a renewal application has been timely filed with the licensing agency until the license renewal process has been completed. The license renewal application for Indian Point 2 and Indian Point 3 qualifies for timely renewal protection because it met NRC regulatory standards for timely filing. The NRC is not expected to issue renewed licenses earlier than third quarter 2018. For additional discussion of the license renewal applications and the settlement with New York State, see “Entergy Wholesale Commoditiesrespective plants.
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Authorizations to Operate Indian Point” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
Non-nuclear Generating Stations
In November 2016, Entergy sold its 50% membership interest in Top Deer Wind Ventures, LLC, a wind-powered electric generation joint venture owned in the Entergy Wholesale Commodities segment and accounted for as an equity method investment. Entergy sold its 50% membership interest in Top Deer for $0.5 million and realized a pre-tax loss of $0.2 million.
Entergy Wholesale Commodities includes the ownership, or interests in joint ventures that own, the following non-nuclear power plants:
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Plant | | Location | | Ownership | | Net Owned Capacity (a) | | Type |
Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
RS Cogen; 425 MW (c) | | Lake Charles, LA | | 50% | | 213 MW | | Gas/Steam |
Nelson Unit 6; 550 MW | | Westlake, LA | | 11% | | 60 MW(b) | | Coal |
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(a) | “Net Owned Capacity” refers to the nameplate rating on the generating unit. |
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(b) | The owned MW capacity is the portion of the plant capacity owned by Entergy Wholesale Commodities. For a complete listing of Entergy’s jointly-owned generating stations, refer to “Jointly-Owned Generating Stations” in Note 1 to the financial statements.
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(c) | Indirectly owned through interests in unconsolidated joint ventures. |
(a)“Net Owned Capacity” refers to the nameplate rating on the generating unit.
(b)The owned MW capacity is the portion of the plant capacity owned by Entergy Wholesale Commodities. For a complete listing of Entergy’s jointly-owned generating stations, refer to “Jointly-Owned Generating Stations” in Note 1 to the financial statements.
(c)Indirectly owned through an interest in an unconsolidated joint venture. In December 2020, Entergy’s wholly-owned subsidiary with a direct interest in RS Cogen, LLC entered into a membership interest purchase agreement with a subsidiary of the other 50% equity partner to sell its 50% membership interest in the joint venture to the equity partner. The targeted closing date for the transaction is October 2022.
Independent System Operators
The Pilgrim plant falls under the authority of the Independent System Operator New England (ISO-NE) and the Indian Point plants fall under the authority of the New York Independent System Operator (NYISO). The Palisades plant falls under the authority of the MISO. The primary purpose of ISO-NE, NYISO and MISO is to direct the operations of the major generation and transmission facilities in their respective regions; ensure grid reliability; administer and monitor wholesale electricity markets; and plan for their respective region’s energy needs.
Energy and Capacity Sales
As a wholesale generator, Entergy Wholesale Commodities’ core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and also sells energy in the day ahead or spot markets. Entergy Wholesale Commodities also sells unforced capacity, which allows load-serving entities to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Entergy Wholesale Commodities’ forward physical power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Entergy Wholesale Commodities to deliver MWh of energy, make capacity available, or both.See “Market and Credit Risk Sensitive Instruments” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for additional information regarding these contracts.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
As part of the purchase of the Palisades plant in 2007, Entergy executed a 15-year PPA with the seller, Consumers Energy, for 100% of the plant’s output, excluding any future uprates. Under the purchased power agreement, Consumers Energy receives the value of any new environmental credits for the first ten years of the agreement. Palisades and Consumers Energy will share on a 50/50 basis the value of any new environmental credits for years 11 through 15 of the agreement. The environmental credits are defined as benefits from a change in law that causes capability of the plant as of the purchase date to become a tradable attribute (e.g., emission credit, renewable energy credit, environmental
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credit, “green” credit, etc.) or otherwise to have a market value. In December 2016, Entergy announced that it reached an agreement with Consumers Energy to terminate the existing PPA for the Palisades plant in 2018. Entergy intended to shut down the Palisades nuclear power plant permanently on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle. In September 2017, as a result of the Michigan Public Service Commission’s order, Entergy and Consumers Energy agreed to terminate the PPA amendment agreement. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022. See discussion above for additional details regarding the agreement.2022 and transfer to Holtec thereafter.
Customers
Entergy Wholesale Commodities’ customers for the sale of both energy and capacity from its nuclear plants include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. These customers include Consolidated Edison and Consumers Energy, companiesthe company from which Entergy purchased plants,the Palisades plant, and ISO-NE, NYISO and MISO. Substantially all of the credit exposure associated with the planned energy output under contract for Entergy Wholesale Commodities nuclear plants is with counterparties or their guarantors that have public investment grade credit ratings.
Competition
The ISO-NE and NYISO markets aremarket is highly competitive. Entergy Wholesale Commodities has numerous competitors in New England and New York including generation companies affiliated with regulated utilities, other independent power producers, municipal and co-operative generators, owners of co-generation plants and wholesale power marketers. Entergy Wholesale Commodities is an independent power producer, which means it generates power for sale to third parties at day ahead or spot market prices to the extent that the power is not sold under a fixed price contract. Municipal and co-operative generators also generate power but use most of it to deliver power to their municipal or co-operative power customers. Owners of co-generation plants produce power primarily for their own consumption. Wholesale power marketers do not own generation; rather they buy power from generators or other market participants and resell it to retail providers or other market participants. Competition in the New England and New York power marketsmarket is affected by, among other factors, the amount of generation and transmission capacity in these markets. MISO does not have a centralized clearing capacity market, but load serving entities do meet the majoritymost of their capacity needs through bilateral contracts and self-supply with a smaller portion coming through voluntary MISO auctions. The majorityAlmost all of Palisades’ current output is contracted to Consumers Energy through May 2022. Entergy Wholesale Commodities does not expect to be materially affected by competition in the MISO market in the near term.
Seasonality
Entergy Wholesale Commodities’ revenues and operating income are subject to fluctuations during the year due to seasonal factors, weather conditions, and contract pricing. Refueling outages are generally in the spring and fall, and cause volumetric decreases during those seasons. When outdoor and cooling water temperatures are low, generally during colder months, Entergy Wholesale Commodities nuclear power plants operate more efficiently, and consequently, generate more electricity. Many of Entergy Wholesale Commodities’ contracts provide for shaped pricing over the course of the year. As a result of these factors, Entergy Wholesale Commodities’ revenues are typically higher in the first and third quarters than in the second and fourth quarters.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Fuel Supply
Nuclear Fuel
See “Fuel Supply - Nuclear Fuel” in the Utility portion of Part I, Item 1 for a discussion of the nuclear fuel cycle and markets. Entergy Nuclear Fuels Company, a wholly-owned subsidiary, is responsible for contracts to acquire nuclear materials, except for fuel fabrication, for Entergy Wholesale Commodities nuclear power plants,
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while Entergy Nuclear Operations, Inc. acts as the agent for the purchase of nuclear fuel assembly fabrication services. All contracts for the disposal of spent nuclear fuel are between the DOE and each of the nuclear power plant owners. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment has been adjusted to reflect reduced overall requirements related to the planned permanent shutdowns of the Indian Point 3 and Palisades plants. Fuel procurement for the Entergy Wholesale Commodities segment was primarily limited to the requirements of the Palisades plant’s final refueling in 2020.
Other Business Activities
Entergy Nuclear Power Marketing, LLC (ENPM) was formed in 2005 to centralize the power marketing function for Entergy Wholesale Commodities nuclear plants. Upon its formation, ENPM entered into long-term power purchase agreements with the Entergy Wholesale Commodities subsidiaries that own nuclear power plants (generating subsidiaries). As part of a series of agreements, ENPM agreed to assume and/or otherwise service the existing power purchase agreements that were in effect between the generating subsidiaries and their customers. ENPM’s functions include origination of new energy and capacity transactions and generation scheduling.
Entergy Nuclear, Inc. can pursue service agreements with other nuclear power plant owners who seek the advantages of Entergy’s scale and expertise but do not necessarily want to sell their assets. Services provided by either Entergy Nuclear, Inc. or other Entergy Wholesale Commodities subsidiaries include engineering, operations and maintenance, fuel procurement, management and supervision, technical support and training, administrative support, and other managerial or technical services required to operate, maintain, and decommission nuclear electric power facilities. Entergy Nuclear, Inc. provided decommissioning services for the Maine Yankee nuclear power plant.
TLG Services, a subsidiary ofin the Entergy Nuclear, Inc.,Wholesale Commodities segment, offers decommissioning, engineering, and related services to nuclear power plant owners.
In September 2003, Entergy agreed to provideprovides plant operation support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. The original contract was to expire in 2014 corresponding to the original operating license life of the plant. In 2006 an Entergy subsidiary signed an agreement to provide license renewal services for the Cooper Nuclear Station. The Cooper Nuclear Station received its license renewal from the NRC in November 2010. In 2010 an Entergy subsidiary signed an agreement to extend the management support services to Cooper Nuclear Station by 15 years, through January 2029. In 2017 the contract was amended so that it could not be terminated prior to December 21, 2022.
Regulation of Entergy’s Business
Federal Power Act
The Federal Power Act provides the FERC the authority to regulate:
•the transmission and wholesale sale of electric energy in interstate commerce;
•the reliability of the high voltage interstate transmission system through reliability standards;
•sale or acquisition of certain assets;
•securities issuances;
•the licensing of certain hydroelectric projects;
•certain other activities, including accounting policies and practices of electric and gas utilities; and
•changes in control of FERC jurisdictional entities or rate schedules.
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Entergy Corporation, Utility operating companies, and System Energy
The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over some of the rates charged by Entergy Arkansas and Entergy Louisiana.Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the provisions ofUtility operating companies. In addition, the System Agreement, including the rates, and the provision of transmission service to wholesale market participants. The FERC also regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC regulation of the MISO RTO includes regulation of the design and implementation of the wholesale markets administered by the MISO RTO, as well as the rates, terms, and conditions of open access transmission service over the member systems and the allocation of costs associated with transmission upgrades.
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Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 70 MW of capacity.
State Regulation
Utility
Entergy Arkansas is subject to regulation by the APSC which includesas to the authority to:following:
oversee •utility service;
set •utility service areas;
•retail rates and charges, including depreciation rates;
determine reasonable•fuel cost recovery, including audits of the energy cost recovery rider;
•terms and adequateconditions of service;
control leasing;•service standards;
control •the acquisition, sale, or salelease of any public utility plant or property constituting an operating unit or system;
set rates of depreciation;
issue •certificates of convenience and necessity and certificates of environmental compatibility and public need;need, as applicable, for generating and transmission facilities;
regulate •avoided cost payments to Qualifying Facilities;
•net energy metering;
•integrated resource planning;
•utility mergers and acquisitions and other changes of control; and
•the issuance and sale of certain securities.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to recent legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory Authority only if it fails to treat its retail customers in Tennessee in the same manner as its retail customers in Arkansas. Additionally, Entergy Arkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to the retail rateratemaking or other regulatory schemejurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to:to the following:
•utility service;
•retail rates and charges;charges, including depreciation rates;
certification of generating facilities and certain transmission projects;
certification of power or capacity purchase contracts;
audit•fuel cost recovery, including audits of the fuel adjustment charge,clause and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•certification of certain transmission projects;
•certification of capacity acquisitions, both for owned capacity and purchase power contracts;
•procurement process to acquire over 50 MW;
•audits of the environmental adjustment charge, and avoided cost payment to Qualifying Facilities;Facilities, and energy efficiency rider;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control; andcontrol.
depreciation and other matters.
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Entergy Mississippi is subject to regulation by the MPSC as to the following:
•utility service;
•utility service areas;
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•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery mechanism;
•terms and conditions of service;
•service standards;
•certification of generating facilities and certain transmission projects;
retail rates;•avoided cost payments to Qualifying Facilities;
fuel cost recovery;•integrated resource planning;
depreciation rates;•net energy metering; and
•utility mergers, acquisitions, and other changes of control.
Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.
Entergy New Orleans is subject to regulation by the City Council as to the following:
•utility service;
•retail rates and charges;charges, including depreciation rates;
standards•fuel cost recovery, including audits of the fuel adjustment charge and purchased gas adjustment charge;
•terms and conditions of service;
depreciation and other matters;•service standards;
•audit of the environmental adjustment charge;
•certification of the construction or extension of any new plant, equipment, property, or facility that comprises more than 2% of the utility’s rate base;
•integrated resource planning;
•net energy metering;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other changes of control.
To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to:to the following:
•retail rates and charges, including depreciation rates, and terms and conditions of service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;
customer •fuel recovery, including reconciliations (audits) of the fuel adjustment charges;
•service standards;
•certification of certain transmission and generation projects; and
•utility service areas, including extensions of service into new areas.areas;
•avoided cost payments to Qualifying Facilities;
•net energy metering; and
•utility mergers, sales/acquisitions/leases of plants over $10 million, sales of greater than 50% voting stock of utilities, and transfers of controlling interest in or operation of utilities.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Regulation of the Nuclear Power Industry
Atomic Energy Act of 1954 and Energy Reorganization Act of 1974
Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose finescivil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC. Entergy subsidiaries in the Entergy Wholesale Commodities segment are subject to the NRC’s jurisdiction as the owners and operators of Pilgrim, Indian Point Energy Center, Vermont Yankee,Palisades, and Palisades. Substantial capital expenditures, increased operating expenses, and/or higher decommissioning costs at Entergy’s nuclear plants because of revised safety requirements of the NRC could be required in the future.Big Rock Point.
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Nuclear Waste Policy Act of 1982
Spent Nuclear Fuel
Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Entergy’s nuclear owner/licensee subsidiaries have been charged fees for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 20172020 of $183.3$192.0 million for the one-time fee. Entergy accepted assignment of the Pilgrim, FitzPatrick, and Indian Point 3, Indian Point 1 and Indian Point 2, Vermont Yankee, Palisades, and Big Rock Point spent fuel disposal contracts with the DOE held by their previous owners. The FitzPatrick spent fuel disposal contract was assigned to Exelon as part of the sale of the plant, completed in March 2017. The Vermont Yankee spent fuel disposal contract was assigned to NorthStar as part of the sale of the plant in January 2019. The Pilgrim spent fuel disposal contract was transferred to Holtec as part of the sale of Entergy Nuclear Generation Company in August 2019. The owners of these plants previous ownersto Entergy have paid or retained liability for the fees for all generation prior to the purchase dates of those plants. The fees payable to the DOE may be adjusted in the future to assure full recovery. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.6 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).
The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing (the DOE filed the license application in June 2008) and, after the license is granted by the NRC, proceed with the repository construction and commencement of receipt of spent fuel. Because the DOE has not begun accepting spent fuel, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts. The DOE continues to delay meeting its obligation. Specific steps were taken to discontinue the Yucca Mountain project, including a motion to the NRC to withdraw the license application with prejudice and the establishment of a commission to develop recommendations for alternative spent fuel storage solutions. In August 2013 the U.S. Court of Appeals for the D.C. Circuit ordered the NRC to continue with the Yucca Mountain license review, but only to the extent of funds previously appropriated by Congress for that purpose and not yet used. Although the NRC completed the safety evaluation report for the license review in 2015, the previously appropriated funds are not sufficient to complete the review, including required hearings. The government has taken no effective action to date related to the recommendations of the appointed spent fuel study commission. Accordingly, large uncertainty remains regarding the time frame under
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which the DOE will begin to accept spent fuel from Entergy’s facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at Entergy’s nuclear sites.
Following the defunding of the Yucca Mountain spent fuel repository program, the National Association of Regulatory Utility Commissioners and others sued the government seeking cessation of collection of the one mill per net kWh generated and sold after April 7, 1983 fee. In November 2013 the D.C. Circuit Court of Appeals ordered the DOE to submit a proposal to Congress to reset the fee to zero until the DOE complies with the Nuclear Waste Policy Act or Congress enacts an alternative waste disposal plan. In January 2014 the DOE submitted the proposal to Congress under protest, and also filed a petition for rehearing with the D.C. Circuit. The petition for rehearing was denied. The zero spent fuel fee went into effect prospectively in May 2014. Management cannot predict the potential timing or magnitude of future spent fuel fee revisions that may occur.
As a result of the DOE’s failure to begin disposal of spent nuclear fuel in 1998 pursuant to the Nuclear Waste Policy Act of 1982 and the spent fuel disposal contracts, Entergy’s nuclear owner/licensee subsidiaries have incurred and will continue to incur damages. These subsidiaries have been, and continue to be, involved in litigation to recover the damages caused by the DOE’s delay in performance. See Note 8 to the financial statements for discussion of final judgments recorded by Entergy in 2018, 2019, and 2020 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE.Through 2017,2020, Entergy’s subsidiaries won and collected on judgments against the government totaling over $500approximately $800 million.
Part I Item 1
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In April 2015 the U.S. Court of Federal Claims issued a judgment in the amount of $29 million in favor of Entergy Arkansas and against the DOE in the second round ANO damages case. Also in April 2015 the U.S. Court of Federal Claims issued a judgment in the amount of $44 million in favor of System Energy and against the DOE in the second round Grand Gulf damages case. In June 2015, Entergy Arkansas and System Energy appealed to the U.S. Court of Appeals for the Federal Circuit portions of those decisions relating to cask loading costs. In April 2016 the Federal Circuit issued a decision in both appeals in favor of Entergy Arkansas and System Energy, and remanded the cases back to the U.S. Court of Federal Claims. In June 2016 the U.S. Court of Federal Claims issued a final judgment in the amount of $49 million in favor of System Energy and against the DOE in the second round Grand Gulf damages case, and Entergy received the payment from the U.S. Treasury in August 2016. In July 2016 the U.S. Court of Federal Claims issued a final judgment in the amount of $31 million in favor of Entergy Arkansas and against the DOE in the second round ANO damages case, and Entergy received payment from the U.S. Treasury in October 2016.
In May 2015 the U.S. Court of Federal Claims issued a final partial summary judgment on a portion, $21 million, of the claims in the Palisades case. The DOE did not appeal that decision, and Entergy received the payment from the U.S. Treasury in October 2015.
In December 2015 the U.S. Court of Federal Claims issued a judgment in the amount of $81 million in favor of Entergy Nuclear Indian Point 3 and Entergy Nuclear FitzPatrick in the first round Indian Point 3/FitzPatrick damages case, and Entergy received the payment from the U.S. Treasury in June 2016.
In January 2016 the U.S. Court of Federal Claims issued a judgment in the amount of $49 million in favor of Entergy Louisiana and against the DOE in the first round Waterford 3 damages case. In April 2016, Entergy Louisiana appealed to the U.S. Court of Appeals for the Federal Circuit the portion of that decision relating to cask loading costs. After the ANO and Grand Gulf appeal was rendered, the U.S. Court of Appeals for the Federal Circuit remanded the Waterford 3 case back to the U.S. Court of Federal Claims for decision in accordance with the U.S. Court of Appeals ruling on cask loading costs. In August 2016 the U.S. Court of Federal Claims issued a final judgment in the Waterford 3 case in the amount of $53 million, and Entergy Louisiana received the payment from the U.S. Treasury in November 2016.
In April 2016 the U.S. Court of Federal Claims issued a partial judgment in the amount of $42 million in favor of Entergy Louisiana and against the DOE in the first round River Bend damages case, reserving the issue of cask loading costs pending resolution of the appeal on the same issues in the Entergy Arkansas and System Energy cases. Entergy Louisiana received payment from the U.S. Treasury in August 2016. In September 2016 the U.S. Court of Federal Claims issued a further judgment in the River Bend case in the amount of $5 million. Entergy Louisiana received the payment from the U.S. Treasury in January 2017. In May 2017 the U.S. Court of Federal Claims issued a final judgment in the first round River Bend damages case for $0.6 million, awarding certain cask loading costs that had not previously been adjudicated by the court.
In May 2016, Entergy Nuclear Vermont Yankee and the DOE entered into a stipulated agreement and the U.S. Court of Federal Claims issued a judgment in the amount of $19 million in favor of Entergy Nuclear Vermont Yankee and against the DOE in the second round Vermont Yankee damages case. Entergy received payment from the U.S. Treasury in June 2016.
In September 2016 the U.S. Court of Federal Claims issued a final judgment in the Entergy Nuclear Palisades case in the amount of $14 million. Entergy Nuclear Palisades received payment from the U.S. Treasury in January 2017.
In October 2016 the U.S. Supreme Court of Federal Claims issued a judgment in the second round Entergy Nuclear Indian Point 2 case in the amount of $34 million. Entergy Nuclear Indian Point 2 received payment from the U.S. Treasury in January 2017.
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Management cannot predict the timing or amount of any potential recoveries on other claims filed by Entergy subsidiaries, and cannot predict the timing of any eventual receipt from the DOE of the U.S. Court of Federal Claims damage awards.
Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at Palisades in 1993, at ANO in 1996, at FitzPatrick in 2002, at River Bend in 2005, at Grand Gulf in 2006, at Indian Point and Vermont Yankee in 2008, and at Waterford 3 in 2011, and at Pilgrim in 2015.2011. These facilities will be expanded as needed.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Louisiana, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, Waterford 3, and Grand Gulf, respectively. In addition, Entergy Louisiana and Entergy Texas are entitled to recover from customers through electric rates the estimated decommissioning costs for the portion of River Bend subject to retail rate regulation. The collections are deposited in trust funds that can only be used for future decommissioning costs.in accordance with NRC and other applicable regulatory requirements. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.
In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In October 2020, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and ANO 2 decommissioning trusts were adequately funded without further collections, and in December 2020, the APSC ordered zero collections for ANO 1 and ANO 2 decommissioning.
In July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend to address previously identified funding shortfalls. This LPSC decision contemplated that the level of decommissioning collections could be revisited should the NRC grant license extensions for both Waterford 3 and River Bend. In July 2019, following the NRC approval of license extensions for Waterford 3 and River Bend, Entergy Louisiana made a filing with the LPSC seeking to adjust decommissioning and depreciation rates for those plants, including one proposed scenario that would adjust Louisiana-jurisdictional decommissioning collections to zero for both plants (including an offsetting increase in depreciation rates). Because of the ongoing public health emergency arising from the COVID-19 pandemic and accompanying economic uncertainty, Entergy Louisiana determined that the relief sought in the filing was no longer appropriate, and in November 2020, filed an unopposed motion to dismiss the proceeding. Following that filing, in a December 2020 order, the LPSC dismissed the proceeding without prejudice.
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In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 20162018 the APSC ordered continuedPUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning for ANO 2, while finding that ANO 1’s decommissioningfund was adequately funded without continued collections. In December 2017 the APSC ordered continued collections for decommissioning for ANO 2, and again found that ANO 1’s decommissioning was adequately funded without continued collections. adequate following license renewal.
In September 2016 the NRC issued a 20-year operating license renewal for Grand Gulf. In a 2017 filing at the FERC, System Energy stated that with the renewed operating license, Grand Gulf’s decommissioning trust was sufficiently funded, and proposed, (amongamong other things)things, to cease decommissioning collections for Grand Gulf effective October 1, 2017. The FERC accepted the proposal subject to refund, and appointed a settlement judge to oversee settlement negotiationsincluding the proposed decommissioning revenue requirement by letter order in the case. August 2018.
Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.
In November 2016,January 2019, Entergy entered into an agreement to sellsold 100% of the membership interest in Entergy Nuclear Vermont Yankee to a subsidiary of NorthStar. Upon closingAs a result of the sale, NorthStar will assumeassumed ownership of Vermont Yankee and its decommissioning and site restoration trusts, together with complete responsibility for the facility’s decommissioning and site restoration. The sale is subject to certain closing conditions, including approval from the NRC and the State of Vermont Public Utility Commission. See Note 9 to the financial statements for further discussion of Vermont Yankee decommissioning costs and see “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the NorthStar transaction.
In August 2019, Entergy sold 100% of the equity interests in Entergy Nuclear Generation Company, LLC to a subsidiary of Holtec International. As a result of the sale, Holtec assumed ownership of Pilgrim and its decommissioning trust, together with complete responsibility for the facility’s decommissioning and site restoration. See Note 14 to the financial statements for further discussion of the sale.
For the Indian Point 3 and FitzPatrick plants purchased in 2000 from NYPA, NYPA retained the decommissioning trust funds and the decommissioning liabilities with the right to require the Entergy subsidiaries to assume each of the decommissioning liabilities provided that it assigns the corresponding decommissioning trust, up to a specified level, to the Entergy subsidiaries. In August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy, which was completed in January 2017. In March 2017, Entergy sold the FitzPatrick plant to Exelon, and as part of the transaction, the FitzPatrick decommissioning trust fund, along with the decommissioning obligation for that plant, was transferred to Exelon. The FitzPatrick spent fuel disposal contract was assigned to Exelon as part of the transaction. See Note 14 to the financial statements for discussion of the FitzPatrick sale.
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In March 20172020 filings with the NRC were made reporting on decommissioning funding for certainall of Entergy subsidiaries’ nuclear plants reporting on decommissioning funding.plants. Those reports showed that decommissioning funding for each of thosethe nuclear plants met the NRC’s financial assurance requirements.
Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 16 to the financial statements.
Price-Anderson Act
The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect the public in the event of a nuclear power plant accident. The costs of this insurance
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are borne by the nuclear power industry. Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025. The Price-Anderson Act limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $127.3$137.6 million per reactor (with 10297 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, System Energy, or an Entergy Wholesale Commodities company is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units is also purchased. The Price-Anderson Act and insurance applicable to the nuclear programs of Entergy are discussed in more detail in Note 8 to the financial statements.
NRC Reactor Oversight Process
The NRC’s Reactor Oversight Process is a program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response. The NRC evaluates plant performance by analyzing two distinct inputs: inspection findings resulting from the NRC’s inspection program and performance indicators reported by the licensee. The evaluations result in the placement of each plant in one of the NRC’s Reactor Oversight Process Action Matrix columns: “licensee response column,” or Column 1, “regulatory response column,” or Column 2, “degraded cornerstone column,” or Column 3, and “multiple/repetitive degraded cornerstone column,” or Column 4. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject to progressively increasing levels of inspection by the NRC with, in general, progressively increasing levels of associated costs. Waterford 3, River Bend, Indian Point 2, Indian Point 3,The nuclear generating plants owned and Palisadesoperated by Entergy’s Utility and Entergy Wholesale Commodities businesses are currently in Column 1.1, except for Grand Gulf, which is currently in Column 2.
In November 2020 the NRC placed Grand Gulf in Column 2 based on the incidence of three unplanned plant scrams during the second and third quarters of 2020.Two of the scram events related to new turbine control system components that failed, and a third related to a feedwater valve positioner that failed, all of which had been replaced in a refueling outage that ended in May 2020. The NRC plans to conduct a supplemental inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 2. ANO 1 and 2 areAs a consequence of two additional Grand Gulf scrams during the fourth quarter 2020, System Energy expects Grand Gulf to be placed into NRC Column 3 based on plant performance indicators for the four quarters ended December 31, 2020. This will involve an additional supplemental NRC inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 4, and are subject to an extensive set of required NRC inspections. Pilgrim is also in Column 4 and is subject to an extensive, but limited, set of required NRC inspections. See Note 8 to the financial statements for further discussion of the placement of ANO 1 and 2, and Pilgrim in Column 4 of the NRC’s matrix.3.
Environmental Regulation
Entergy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy’s businesses are in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted below. Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely estimated. Except to the extent discussed below, at this time compliance with federal, state, and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Entergy’s businesses and is not expected to have a material effect on their competitive position, results of operations, cash flows, or financial position.
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Clean Air Act and Subsequent Amendments
The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a lesser extent, certain operations at nuclear and other facilities. Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements. These programs include:
•New source review and preconstruction permits for new sources of criteria air pollutants, greenhouse gases, and significant modifications to existing facilities;
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• | Acid rain program for control of sulfur dioxide (SO2) and nitrogen oxides (NOx);
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•Acid rain program for control of sulfur dioxide (SO2) and nitrogen oxides (NOx);
•Nonattainment area programs for control of criteria air pollutants, which could include fee assessments for air pollutant emission sources under Section 185 of the Clean Air Act if attainment is not reached in a timely manner;
•Hazardous air pollutant emissions reduction programs;
•Interstate Air Transport;
•Operating permit programs and enforcement of these and other Clean Air Act programs;
•Regional Haze programs; and
•New and existing source standards for greenhouse gas and other air emissions.
New Source Review (NSR)
Preconstruction permits are required for new facilities and for existing facilities that undergo a modification that results in a significant net emissions increase and is not classified as routine repair, maintenance, or replacement. Units that undergo certain non-routine modifications must obtain a permit modification and may be required to install additional air pollution control technologies. In December 2020 the EPA amended the NSR regulations to clarify when a physical change or change in the method of operation will constitute such a modification. Entergy has an established process for identifying modifications requiring additional permitting approval and followsis monitoring the regulations and associated guidance provided by the states and the federal government with regard to the determination of routine repair, maintenance, and replacement. In recentSeveral years ago, however, the EPA has begunimplemented an enforcement initiative, aimed primarily at coal plants, to identify modifications that it does not consider routine for which the unit did not obtain a modified permit. Various courts and the EPA have been inconsistent in their judgments regarding modifications that are considered routine and on other legal issues that affect this program.
In February 2011, Entergy received a request from the EPA for several categories of information concerning capital and maintenance projects at the White Bluff and Independence facilities, both located in Arkansas, in order to determine compliance with the Clean Air Act, including NSR requirements and air permits issued by the Arkansas Department of Energy and Environment, Division of Environmental Quality.Quality (ADEQ). In August 2011, Entergy’s Nelson facility, located in Louisiana, received a similar request for information from the EPA. In September 2015 a subsequentan additional request for similar information was received for the White Bluff facility. Entergy responded to all requests. None of these EPA requests for information alleged that the facilities were in violation of law.
In January 2018 and February 2018, Entergy Arkansas, Entergy Mississippi, Entergy Power, and other co-owners received 60-day notice of intent to sue letters from the Sierra Club and the National Parks Conservation Association concerning allegations of violations of new source review and permitting provisions of the Clean Air Act at the Independence and White Bluff coal-burning units, respectively. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims as well as other issues facing Entergy Arkansas’s fossil generation plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, is reviewing these claims and will respond accordingly.
subject to approval by the U.S. District Court for the Eastern District of Arkansas. In October 2019 the District Court requested supplemental briefing on several issues to be resolved prior to addressing the motion to approve the
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settlement; that briefing was completed in May 2020. For further information about the settlement, see “Regional Haze” discussed below.
Ozone Nonattainment
National Ambient Air Quality Standards
Entergy Texas operates one fossil-fueled generating facility (Lewis Creek) and is in
The Clean Air Act requires the process of permitting and constructing one fossil-fueled facility (Montgomery Count Power Station) in a geographic area that is not in attainment with the currently-enforced national ambient air quality standardsEPA to set National Ambient Air Quality Standards (NAAQS) for ozone. The nonattainmentozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide, and requires periodic review of those standards. When an area that affects Entergy Texasfails to meet an ambient standard, it is the Houston-Galveston-Brazoria area. Areasconsidered to be in nonattainment areand is classified as “marginal,” “moderate,” “serious,” or “severe.” When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.
The Houston-Galveston-BrazoriaOzone Nonattainment
Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area was originally classified as “moderate” nonattainment under the 1997 8-hour ozone standard with an attainment date of June 15, 2010. In June 2007 the Texas governor petitioned the EPA to reclassify Houston-Galveston-Brazoria from “moderate” to “severe” and the EPA granted the request in October 2008. In February 2015 the Texas Commission on Environmental Quality (TCEQ) submitted a request to the EPA for a finding that the Houston-Galveston-Brazoria area is not in attainment with the 1997 8-hourapplicable NAAQS for ozone. The ozone standard. The EPA issued this finding in December 2015. In April 2015 the EPA revoked the 1997 ozone NAAQS and in May 2016, the EPA issued a proposed rule approving a substitute fornonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. This redesignation indicates thatBoth Lewis Creek and the Montgomery County Power Station hold all necessary permits for construction and operation and comply with applicable air quality program regulations. Measures enacted to return the area has attained the revoked 1997 8-hourto ozone NAAQS due to permanent and enforceable emission reductions and that it will maintain that NAAQS for 10 years from the date of the approval. Final approval, which was effective in December 2016, resulted in the area no longer being subject to any remaining anti-backsliding or non-attainment new source review requirements associated with the revoked 1997 NAAQS.
In March 2008 the EPA revised the NAAQS for ozone, creating the potential for additional counties and parishes in which Entergy operates to be placed in nonattainment status. In April 2012 the EPA released its final non-attainment designations for the 2008 ozone NAAQS. In Entergy’s utility service area, the Houston-Galveston-Brazoria, Texas; Baton Rouge, Louisiana; and Memphis, Tennessee/Mississippi/Arkansas areas were designated as in “marginal” nonattainment. In August 2015 and January 2016, the EPA proposed determinations that the Baton Rouge and Memphis areas had attained the 2008 standard. In May 2016 the EPA finalized those determinations and extended the Houston-Galveston-Brazoria area’s attainment date for the 2008 Ozone standard to July 20, 2016 and reclassified the Baton Rouge area as attainment for ozone under the 2008 8-hour ozone standard. In December 2016 the EPA determined that the Houston-Galveston-Brazoria area had failed to attain the 2008 ozone standard by the 2016 attainment date. This finding reclassifies the Houston-Galveston-Brazoria area from marginal to “moderate.”
In October 2015 the EPA issued a final rule lowering the primary and secondary NAAQS for ozone to a level of 70 parts per billion. States were required to assess their attainment status and recommend designations to the EPA. In January 2018 the EPA proposed that the following counties and parishes in Entergy’s service territory be listed as in non-attainment: in Louisiana, Ascension Parish, East Baton Rouge Parish, West Baton Rouge Parish, Iberville Parish, and Livingston Parish; in Texas, Montgomery County. In addition to Lewis Creek in Montgomery County, Texas, Entergy owns or operates fossil-fueled generating units in East Baton Rouge Parish (Louisiana Station) and in Iberville Parish (Willow Glen), Louisiana. The EPA’s final designations are pending.could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and non-attainmentnonattainment with the new standard and, where necessary, in planning for compliance. Following designations by the EPA, states will be required to develop plans intended to return non-attainment areas to a condition of attainment. The timing for that action depends largely on the severity of non-attainment in a given area.ozone NAAQS.
Potential SO2Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. The EPA designations for counties in attainment and nonattainment were originally due in June 2012, but the EPA indicated that it would delay designations except for those areas with existing monitoring data from 2009 to 2011 indicating violations of the new standard. In August 2013 the EPA issued final designations for these areas. In Entergy’s utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana isare designated as non-attainment for the SO2
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1-hour national ambient air quality standard of 75 parts per billion. Entergy does not have a generation asset in that parish. In July 2016 the EPA finalized another round of designations for areas with newly monitored violations of the 2010 standard and those with stationary sources that emit over a threshold amount of SO2. Counties and parishes in which Entergy owns and operates fossil generating facilities that were included in this round of designations include Independence County and Jefferson County, Arkansas and Calcasieu Parish, Louisiana. Independence County and Calcasieu Parish were designated “unclassifiable,” and Jefferson County was designated “unclassifiable/attainment.” In August 2015 the EPA issued a final data requirement rule for the SO2 1-hour standard. This rule will guide the process to be followed by the states and the EPA to determine the appropriate designation for the remaining unclassified areas in the country.nonattainment. In August 2017 the EPA issued a letter indicating that East Baton Rouge and St. Charles parishes would be designated by December 31, 2020, as monitors were installed to determine compliance. In January 2018December 2020 the EPA published adesignated East Baton Rouge, St. Charles, St. James, and West Baton Rouge parishes in Louisiana as attainment/unclassifiable, and, in Texas, Jefferson County as attainment/unclassifiable and Orange County as unclassifiable. Challenges to these final rule designating a third rounddesignations must be filed within 60 days of attainment and non-attainment areas. Evangeline Parish, Louisiana, was designated non-attainment. publication in the Federal Register. Entergy does not have a generation asset in that parish. Additional capital projects or operational changes may be requiredcontinues to continue operating Entergy facilities in areas eventually designated as in non-attainment of the standard or designated as contributing to non-attainment areas.monitor this situation.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2020 the EPA finalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. The final appropriate and necessary finding does not revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. Entergy will continue to monitor this situation.
Cross-State Air Pollution
In March 2005 the EPA finalized the Clean Air Interstate Rule (CAIR), which was intended to reduce SO2 and NOx emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule required a combination of capital investment to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy.
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Based on several court challenges, CAIR and its subsequent versions, now known as the Cross StateCross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions. In July 2015 the D.C. Circuit invalidated the allowance budgets created by the EPA for several states, including Texas, and remanded that portion of the rule to the EPA for further action. The court did not stay or vacate the rule in the interim. CSAPR remains in effect.
The CSAPR Phase 1 implementation became effective January 1, 2015. Entergy has developed a compliance plan that could, over time, include both installation of controls at certain facilities and an emission allowance procurement strategy.
In September 2016 the EPA finalized the CSAPR Update Rule to address interstate transport for the 2008 ozone NAAQS. Starting in 2017 the final rule will requirerequires reductions in summer nitrogen oxides (NOx) emissions. Several states, including Arkansas and Texas, filed a challenge to the Update Rule. In September 2019 the D.C. Circuit upheld the EPA’s underlying approach to the Update Rule, whichbut determined that it was inconsistent with the Clean Air Act because it failed to include deadlines consistent with downwind states’ deadlines for attainment. The court remanded the rule to the EPA for further consideration, but did not vacate so the rule remains pending.in effect pending the EPA’s further review. In October 2020 the EPA issued its proposal intended to address the D.C. Circuit’s remand. The draft rule proposes to finalize interstate transport obligations for 21 states. For nine states, including Arkansas, Mississippi, and Texas, the EPA proposes that additional emission reductions are not necessary. For 12 states, however, including Louisiana, the EPA proposes additional emission reductions through proposed reductions in the number of NOx emission allowances allocated to each state. Entergy, through its various trade associations, filed comments on the proposal and will continue to monitor the rulemaking and its potential impact on its facilities in Louisiana. If the October 2020 proposal is finalized, ozone season NOx emissions may become more expensive in Louisiana.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could result in a requirement to install SO2 and NOx pollution control technology as Best Available Retrofit Control Technology (BART) to continue operating certain of Entergy’s fossil generation units. The rule leaves certain CAVR determinations to the states.
In Arkansas, the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ) prepared a state implementation plan (SIP) for Arkansas facilities to implement its obligations under the CAVR. In April 2012 the EPA finalized a decision
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addressing the Arkansas Regional Haze SIP, in which it disapproved a large portion of the Arkansas plan, including the emission limits for NOx and SO2 at White Bluff. In April 2015 the EPA published a proposed federal implementation plan (FIP) for Arkansas, taking comment on requiring installation of scrubbers and low NOx burners to continue operating both units at the White Bluff plant and both units at the Independence plant and NOx controls to continue operating the Lake Catherine plant. Entergy filed comments by the deadline in August 2015. Among other comments, including opposition to the EPA’s proposed controls on the Independence units, Entergy proposed to meet more stringent SO2 and NOx limits at both White Bluff and Independence within three years of the effective date of the final FIP and to cease the use of coal at the White Bluff units at a later date.
In September 2016 the EPA published the final Arkansas Regional Haze FIP. In most respects, the EPA finalized its original proposal but shortened the time for compliance for installation of the NOx controls. The FIP required an emission limitation consistent with SO2 scrubbers at both White Bluff and Independence by October 2021 and NOx controls by April 2018. The EPA declined to adopt Entergy’s proposals related to ceasing coal use as an alternative to SO2 scrubbers for White Bluff SO2 BART. In November 2016, Entergy and other interested parties, including the State of Arkansas, filed petitions for administrative reconsideration and stay at the EPA as well as petitions for judicial review in the U.S. Court of Appeals for the Eighth Circuit. The Eighth Circuit continues to review its prior grant ofgranted the government’s motion to hold the appeal litigation in abeyancestay pending settlement discussions and pending the State’s development of a SIP that, if approved by the EPA, would replace the FIP. The state hashad proposed its replacement SIP in two parts: Part I considers NOx requirements, and Part II considers SO2 requirements. The EPA approved the Part I NOx SIP in January 2018. The Part I SIP requires that Entergy address NOx impacts on visibility via compliance with the Cross-State Air Pollution Rule ozone-season emission trading program. Arkansas has proposedfinalized a Part II SIP which has been approved by the EPA but is still under considerationcurrently pending a state court appeal. That appeal has been stayed pending the outcome of a federal court case, which may resolve many of the issues on appeal. The final Part II SIP requires that Entergy achieve SO2 emission reductions via the use of low-sulfur coal at both White Bluff and Independence within three years. The
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Part II SIP also requires that Entergy cease to use coal at White Bluff by December 31, 2028 and notes the current planning assumption that Entergy’s Independence units will cease to use coal by December 31, 2030.
In January and February 2018, Entergy Arkansas, Entergy Mississippi, Entergy Power, and other co-owners received 60-day notice of intent to sue letters from the Sierra Club and the National Parks Conservation Association concerning allegations of violations of new source review and permitting provisions of the Clean Air Act at the state level. The public comment period onIndependence and White Bluff coal-burning units, respectively. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims and reducing the risk that Entergy Arkansas, as operator of Independence and White Bluff, might be compelled under the Clean Air Act’s regional haze program to install costly emissions control technologies. Consistent with the terms of the settlement and in many cases also the Part II endedSIP, Entergy Arkansas, along with co-owners, will begin using only low-sulfur coal at Independence and White Bluff by mid-2021; cease to use coal at White Bluff and Independence by the end of 2028 and 2030, respectively; cease operation of the remaining gas unit at Lake Catherine by the end of 2027; reserve the option to develop new generating sources at each plant site; and commit to install or propose to regulators at least 800 MWs of renewable generation by the end of 2027, with at least half installed or proposed by the end of 2022 (which includes two existing Entergy Arkansas projects) and with all qualifying co-owner projects counting toward satisfaction of the obligation. Under the settlement, the Sierra Club and the National Parks Conservation Association also waive certain potential existing claims under federal and state environmental law with respect to specified generating plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, is subject to approval by the U.S. District Court for the Eastern District of Arkansas. The EPA, which is allowed to comment on February 2, 2018.such a settlement agreement, has stated that it has no objections to the settlement. In November 2020 the court denied motions by the Arkansas Attorney General and the Arkansas Affordable Energy Coalition to intervene and to stay the proceedings. The proposed intervenors did not appeal the ruling. Still pending before the court is a motion by the plaintiffs to approve the settlement, in support of which Entergy made a filing. The Arkansas Attorney General also filed an application before the APSC in December 2018 seeking an investigation into the effects of the settlement. The Arkansas Affordable Energy Coalition filed to support the Arkansas Attorney General’s application, and Entergy Arkansas filed a motion to dismiss it. The application remains pending before the APSC. In October 2019 the District Court requested supplemental briefing on several issues prior to addressing the motion to approve the settlement; that briefing concluded in May 2020.
In Louisiana, Entergy has worked with the Louisiana Department of Environmental Quality (LDEQ) and the EPA to revise the Louisiana SIP for regional haze, which washad been disapproved in part in 2012. The LDEQ submitted a revised SIP in February 2017. In May 2017 the EPA proposed to approve a majority of the revisions. In September 2017 the EPA issued a proposed SIP approval for the Nelson plant, requiring an emission limitation consistent with the use of low-sulfur coal, with a compliance date three years from the effective date of the finalJanuary 22, 2021. The EPA approval. The EPA’sissued final approval decision was issued in December 2017 and is on appeal2017. The EPA approval was appealed to the U.S. Court of Appeals for the Fifth Circuit. In October 2019 the Fifth Circuit affirmed the EPA’s SIP approval. A petition for rehearing filed by plaintiffs was denied by the Fifth Circuit. Plaintiffs did not petition for further review by the Supreme Court.
The second planning period (2018-2028) for the regional haze program requires states to examine sources for impacts on visibility and to prepare SIPs by 2021. Entergy received information collection requests from Arkansas and Louisiana requesting an evaluation of technical and economic feasibility of various NOx and SO2 control technologies for Independence, Nelson 6, and Ninemile. Responses to the information requests have been submitted to the respective state agencies.
New and Existing Source Performance Standards for Greenhouse Gas Emissions
As a part of a climate plan announced in June 2013,In July 2019 the EPA was directedreleased the Affordable Clean Energy Rule (ACE), which applies only to (i) reissue proposed carbon pollution standardsexisting coal-fired electric generating units. The ACE determines that heat rate improvements are the best system of emission reductions and lists six candidate technologies for new power plantsconsideration by September 20, 2013, with finalization of the rules to occur in a timely manner; (ii) issue proposed carbon pollution standards, regulations, or guidelines, as appropriate, for modified, reconstructed,states at each coal unit. The rule and existing power plants no later than June 1, 2014; (iii) finalize those rulesassociated rulemakings by no later than June 1, 2015; and (iv) include in the guidelines addressing existing power plants a requirement that states submit to the EPA replace the implementation plans required under Section 111(d) of the Clean Air Act and its implementing regulations by no later than June 30, 2016. In January 2014 the EPA issued the proposed New Source Performance Standards rule for new sources. In June 2014 the EPA issued proposed standards for existing power plants. Entergy was actively engaged in the rulemaking process, and submitted comments to the EPA in December 2014. The EPA issued the final rules for both new and existing sources in August 2015, and they were published in the Federal Register in October 2015. The existing source rule, also called theObama administration’s Clean Power Plan, requires states to develop plans for compliance with the EPA’s emission standards. In February 2016 the U.S. Supreme Court issued a stay halting the effectiveness of the rule until the rule is reviewed by the D.C. Circuit and by the U.S. Supreme Court, if further review is granted. In March 2017 the current administration issued an executive order entitled “Promoting Energy Independence and Economic Growth” instructing the EPA to review and then to suspend, revise, or rescind the Clean Power Plan, if appropriate. The EPA subsequently asked the D.C. Circuit to hold the challenges to the Clean Power Plan and the greenhouse gas new source performance standards in abeyance and signed a notice of withdrawal of the proposed federal plan, model trading rules, and the Clean Energy Incentive Program. The court placed the litigation in abeyance in April 2017. The EPA Administrator also sent a letter to the affected governors explaining that states are not currently required to meet Clean Power Plan deadlines, some of which have passed. In October 2017 the EPA proposed a new rule that would repeal the Clean Power Plan on the grounds that it exceeds the EPA’s statutory authority under the Clean Air Act. In December
established
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2017national emissions performance rates for existing fossil-fuel fired steam electric generating units and combustion turbines. The ACE rule provides states discretion in determining how the best system for emission reductions applies to individual units, including through the consideration of technical feasibility and the remaining useful life of the facility. The ADEQ and the LDEQ have issued information collection requests to Entergy facilities to help the states collect the information needed to determine the best system of emission reductions for each facility. Entergy responded to the requests and will continue to monitor litigation challenging the rule. In January 2021 the U.S. Court of Appeals for the D.C. Circuit vacated ACE. The court held that ACE relied on an incorrect interpretation of the Clean Air Act that the statute expressly forecloses emission reduction approaches, such as emissions trading and generating shifting, that cannot be applied at and to the individual source. The court remanded ACE to the EPA issued an advanced noticefor further consideration and also vacated the repeal of proposed rulemaking regarding section 111(d), seeking comment on the form and content of a replacement for the Clean Power Plan, if onePlan. The vacatur will not be effective until the court issues its mandate which is promulgated.being held until after disposition of any petitions for rehearing. Entergy will continueis currently reviewing the court’s opinion.
In 2018 the EPA proposed a revision to be engagedthe new source performance standard on greenhouse gas emissions that primarily impacts new coal units and, therefore, should not impact Entergy. In January 2021 the EPA finalized a pollutant-specific contribution finding for greenhouse gas emissions from new, modified, and reconstructed electric generating units. The rule establishes a three percent threshold for determining when a pollutant significantly contributes to air pollution and reaffirms the EPA’s position that the Clean Air Act Section 111(b) requires the EPA to make pollutant-specific significant contribution findings before promulgation of a new source performance standard. The EPA did not, however, finalize the new source performance standard on greenhouse gas emissions and intends to address the 2018 proposal in this rulemaking process.a future action.
Potential Legislative, Regulatory, and Judicial Developments
In addition to the specific instances described above, there are a number of legislative and regulatory initiatives concerning air emissions, as well as other media, that are under consideration at the federal, state, and local level. Because of the nature of Entergy’s business, the imposition of any of these initiatives could affect Entergy’s operations. Entergy continues to monitor these initiatives and activities in order to analyze their potential operational and cost implications. These initiatives include:
•designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;
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• | introduction of bills in Congress and development of regulations by the EPA proposing further limits on NOx, SO2, mercury, and carbon dioxide and other air emissions. New legislation or regulations applicable to stationary sources could take the form of market-based cap-and-trade programs, direct requirements for the installation of air emission controls onto air emission sources, or other or combined regulatory programs;
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•introduction of bills in Congress and development of regulations by the EPA proposing further limits on NOx, SO2, mercury, and carbon dioxide and other air emissions. New legislation or regulations applicable to stationary sources could take the form of market-based cap-and-trade programs, direct requirements for the installation of air emission controls onto air emission sources, or other or combined regulatory programs;
•efforts in Congress or at the EPA to establish a mandatory federal carbon dioxide emission tax, control structure, or unit performance standards;
•revisions to the estimates of the Social Cost of Carbon and its use for regulatory impact analysis of Federalfederal laws and regulations;
•implementation of the Regional Greenhouse Gas Initiative by several states in the northeastern United States and similar actions in other regions of the United States;
•efforts on the local, state, and federal level to codify renewable portfolio standards, a clean energy standard,standards, or a similar mechanism requiring utilities to produce or purchase a certain percentage of their power from defined renewable energy sources or energy sources with lower emissions;
•efforts to develop more stringent state water quality standards, effluent limitations for Entergy’s industry sector, stormwater runoff control regulations, and cooling water intake structure requirements;
•efforts to restrict the previously-approved continued use of oil-filled equipment containing certain levels of PCBs;polychlorinated biphenyls (PCBs);
•efforts by certain external groups to encourage reporting and disclosure of carbon dioxide emissionsenvironmental, social, and governance risk;
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•the listing of additional species as threatened or endangered, the protection of critical habitat for these species, and developments in the legal protection of eagles and migratory birds; and
•the regulation of the management, disposal, and beneficial reuse of coal combustion residuals.residuals; and
•the regulation of the management and disposal and recycling of equipment associated with renewable and clean energy sources such as used solar panels, wind turbine blades, hydrogen usage, or battery storage.
Entergy continues to support national legislation that would increase planning certainty for electric utilities while addressing carbon dioxide emissions in aan economy-wide, responsible, and flexible manner. By virtue of its proportionally large investment in low-emitting gas-fired and nuclear generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, in the future, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included establishment of a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. Total carbon dioxide emissions representing Entergy’s ownership share of power plants in the United States were approximately 53.2 million tons in 2000 and 35.6 million tons in 2005. In 2006, Entergy changed its method of calculating emissions to includestarted including emissions from controllable power purchases as well asin addition to its ownership share of generation. Entergygeneration and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020. In 2020, Entergy succeeded in achieving its initial climate commitment to reduce carbon dioxide cumulative emissions by 20% from 2000 levels. Total carbon dioxide emissions representing Entergy’s ownership share of power plants and controllable power purchases in the United States were approximately 46.139.1 million tons in 2011, 45.52020 and 40.7 million tons in 2012, 46.2 million tons2019. Since its original commitment in 2013, 42.4 million tons in 2014, 39.5 million tons in 2015, 42.5 million tons in 2016, and 39.9 million tons in 2017. The decrease2001, Entergy’s cumulative emissions are approximately 7.6% below its 2020 goal.
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Entergy Corporation, Utility operating companies,voluntarily conducted a climate scenario analysis and System Energy
published a comprehensive report in this number from 2014 to 2015 was largely attributable toMarch 2019. The report follows the impact on the calculation methodologyframework and recommendations of the Utility operating companies’ transition into the MISO system. Participation in this systemTask Force on Climate-related Disclosures, describing climate-related governance, strategy, risk management, and metrics and targets. Scenario analyses resulted in fewer power purchases being classified as “controllable”Entergy developing and thus included inpublishing a new goal of reducing the calculation of theUtility’s emission rate by 50 percent from 2000 levels by 2030. In September 2020, Entergy committed to achieving net-zero carbon emissions total.by 2050, while continuing its commitment to grid reliability and affordability for customers. In December 2020, Entergy published a report regarding this long-term commitment that describes its approach and technology point-of-view. Technology research and development, innovation, and advancement are critical to Entergy’s ability to meet this climate commitment.
Entergy participates in the M.J. Bradley & Associates’ Annual Benchmarking Air Emissions Report, an annual analysis of the 100 largest U.S. electric power producers. The report is available on the M.J. Bradley website. Entergy’s annual CO2greenhouse gas emissions auditinventory is also third-party verified, and that certification is made available on the American Carbon Registry website. Entergy participates annually in the Dow Jones Sustainability Index and in 20172020 was listed on the North American Index. Entergy has been listed on the World or North American Index, or both, for nineteen consecutive years. Entergy also participated in the 2020 CDP and CDP Water evaluations, receiving a ‘B’ for both responses.
Clean Water Act
The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act) provide the statutory basis for the National Pollutant Discharge Elimination System (NPDES) permit program, section 402, and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The Clean Water Act requires virtually all discharges of pollutants to waters of the United States to be permitted. Section 316(b) of the Clean Water Act regulates cooling water intake structures, section 401 of the Clean Water Act requires a water quality certification from the state in support of certain federal actions and approvals, and section 404 regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.
NPDES Permits and Section 401 Water Quality Certifications
NPDES permits are subject to renewal every five years. Consequently, Entergy is currently in various stages of the data evaluation and discharge permitting process for its power plants.
For thirteen years, Entergy participated in an administrative permitting process with the New York State Department of Environmental Conservation (NYSDEC) for renewal of the Indian Point 2 and Indian Point 3 discharge permit. That proceeding recently was settled along with other ongoing proceedings. For a discussion of the recent Indian Point settlement, see “Entergy Wholesale Commodities Authorization to Operate Indian Point” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
316(b) Cooling Water Intake Structures
The EPA finalized regulations in July 2004 governing the intake of water at large existing power plants employing cooling water intake structures. The rule sought to reduce perceived impacts on aquatic resources by requiring covered facilities to implement technology or other measures to meet EPA-targeted reductions in water use and corresponding perceived aquatic impacts. Entergy, other industry members and industry groups, environmental groups, and a coalition of northeastern and mid-Atlantic states challenged various aspects of the rule. After litigation, the EPA issued a new final 316(b) rule in August 2014. Entergy is developing a compliance plan for each affected facility in accordance with the requirements of the final rule.
Entergy filed a petition for review of the final rule as a co-petitioner with the Utility Water Act Group. The U.S. Court of Appeals for the Second Circuit heard oral argument in September 2017. A decision is expected in 2018.
Coastal Zone Management Act
Before a federal licensing agency (such as the NRC) may issue a major license or permit for an activity within the federally designated coastal zone, the agency must be satisfied that the requirements of the Coastal Zone Management Act (CZMA), as applicable, have been met. In many cases, CZMA requirements are satisfied by the state’s written concurrence with a “consistency determination” filed by the federal license applicant explaining why the activity proposed to be federally licensed is consistent with the state’s coastal management program. For a discussion of the recent Indian Point settlement, including the CZMA proceedings related to Indian Point license renewal, see “Entergy
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Steam Electric Effluent Guidelines
Wholesale Commodities Authorizations
The 2015 Steam Electric Effluent Limitations Guidelines (ELG) rule required, among other things, that there be no discharge of bottom ash transport water. In October 2020 the EPA issued its final rule revision on bottom ash transport water allowing the discharge of up to Operate Indian Point”10% system volume for certain purge waters, including storm events and non-routine operations. The final rule requires compliance as soon as possible beginning October 31, 2021, but no later than December 31, 2025. Several challenges to the final rule have been filed. Additionally, the Fifth Circuit Court of Appeals previously vacated and remanded the provisions of the rule related to legacy wastewater and leachate, which the EPA plans to address in a separate rulemaking. Despite the final rule and pending challenges, Entergy Corporationis implementing projects at its White Bluff and Subsidiaries Management’s Financial DiscussionIndependence plants to convert to zero-discharge systems to comply with the ELG rule and Analysis.the coal combustion residuals restrictions on impoundments. Additionally, the Nelson Unit 6 facility is implementing operational and maintenance measures to minimize the potential for discharge of bottom ash transport water from the existing bottom ash handling system at the site, and is reviewing the effectiveness of these changes for compliance with the requirements of the October 2020 final rule.
Federal Jurisdiction of Waters of the United States
In September 2013February 2019 the EPA and the U.S. Army Corpspublished its proposed revised definition of Engineers announced the intention to propose a rule to clarify federal Clean Water Act jurisdiction over waters of the United States. The announcement was made in conjunction with the EPA’s release of a draft scientific report on the “connectivity” of waters that the agency said would inform the rulemaking. This report was finalized in January 2015. The final rule was published in the Federal Register in June 2015. The rule could significantly increase the number and types of waters included in the EPA’s and the U.S. Army Corps of Engineers’ jurisdiction, which in turn could pose additional permitting and pollutant management burdens on Entergy’s operations. The final rule has been challenged in various federal courts by several parties, including most states. In August 2015 the District Court for North Dakota issued a preliminary injunction staying the new rule in 13 states, including Arkansas. In October 2015 the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the rule. In February 2017 the current administration issued an executive order instructing the EPA and the U.S. Army Corps of Engineers to review the Waters of the United States, which proposes to narrow the scope of Clean Water Act jurisdiction, as compared to a 2015 definition which had been stayed by several federal courts. The final rule was released in January 2020 and to revise or rescind, as appropriate.effective in June 2020. In June 2017October 2019 the EPA and the U.S. Army Corps of Engineers released a proposed rule that rescinds the June 2015 rule and recodifies the definition of “waters of the U.S.” that was in effect prior to the 2015 rule. The administration is expected to propose a definition of “waters of the U.S.” at a later date. In January 2018 the Supreme Court determined that the Sixth Circuit lacked jurisdiction over the petition to reviewrepealed the 2015 rule and thatre-codified the pre-existing regulations. That rule was effective late December 2019. Numerous challenges should be heard in the federal district court. The matter hashave been remanded to the Sixth Circuit, which is expected to lift the nationwide stay. After the Supreme Court decision, the EPA and the U.S. Army Corps of Engineers finalized a rule delaying the applicability date of the 2015 rule to early 2020. In February 2018 the states of Louisiana, Mississippi, and Texas filed suit in Texas federal district court seeking a preliminary injunction of the 2015 rule. Entergy will continue to monitor this rulemaking and litigation.against both rules.
Groundwater at Certain Nuclear Sites
The NRC requires nuclear power plants to monitor and report regularly the presence of radioactive material in the environment. Entergy joined other nuclear utilities and the Nuclear Energy Institute in 2006 to develop a voluntary groundwater monitoring and protection program. This initiative began after detection of very low levels of radioactive material, primarily tritium, in groundwater at several plants in the United States. Tritium is a radioactive form of hydrogen that occurs naturally and is also a byproduct of nuclear plant operations. In addition to tritium, other radionuclides have been found in site groundwater at nuclear plants.
As part of the groundwater monitoring and protection program, Entergy has: (1) performed reviews of plant groundwater characteristics (hydrology) and historical records of past events on site that may have potentially impacted groundwater; (2) implemented fleet procedures on how to handle events that could impact groundwater; and (3) installed groundwater monitoring wells and began periodic sampling. The program also includes protocols for notifying local officials if contamination is found. To date, radionuclides such as tritium have been detected at Arkansas Nuclear One, Indian Point, Palisades, Pilgrim, Grand Gulf, Vermont Yankee, and River Bend. Each of these sites has installed groundwater monitoring wells and implemented a program for testing groundwater at the sites for the presence of tritium and other radionuclides. Based on current information, the concentrations and locations of radionuclides detected at these plants pose no threat to public health or safety, but each site continues to evaluate the results from its groundwater monitoring program.
In February 2016, Entergy disclosed that elevated tritium levels had been detected in samples from several monitoring wells that are part of Indian Point’s groundwater monitoring program. Investigation of the source of elevated tritium has determined that the source is related to a temporary system to process water in preparation for the regularly scheduled refueling outage at Indian Point 2. The system was secured and is no longer in use and additional measures have been taken to prevent reoccurrence should the system be needed again. In June 2016, Indian Point detected trace amounts of cobalt 58 in a single well. This was associated with the draining and disassembly of a temporary heat
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
exchanger operated in support of the Indian Point 2 outage. Oversight by NRC and other federal/state government bodies continues. The NRC has issued a green notice of violation related to the adequacy of Entergy’s controls to prevent the introduction of radioactivity into the site groundwater. Entergy has completed all required corrective actions and expects the NRC to close the notice of violation by March 2018.
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint, and several liability on responsible parties. Many states have adopted programs similar to CERCLA. Entergy subsidiaries in the Utility and Entergy Wholesale Commodities businesses have sent waste materials to various
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
disposal sites over the years, and releases have occurred at Entergy facilities.facilities including nuclear facilities that have been or will be sold to decommissioning companies. In addition, environmental laws now regulate certain of Entergy’s operating procedures and maintenance practices that historically were not subject to regulation. Some disposal sites used by Entergy subsidiaries have been the subject of governmental action under CERCLA or similar state programs, resulting in site clean-up activities. Entergy subsidiaries have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs. The affected Entergy subsidiaries have established provisions for the liabilities for such environmental clean-up and restoration activities. Details of potentially material CERCLA and similar state program liabilities are discussed in the “Other Environmental Matters” section below.
Coal Combustion Residuals
In June 2010 the EPA issued a proposed rule on coal combustion residuals (CCRs) that contained two primary regulatory options: (1) regulating CCRs destined for disposal in landfills or received (including stored) in surface impoundments as so-called “special wastes” under the hazardous waste program of RCRAResource Conservation and Recovery Act (RCRA) Subtitle C; or (2) regulating CCRs destined for disposal in landfills or surface impoundments as non-hazardous wastes under Subtitle D of RCRA. Under both options, CCRs that are beneficially reused in certain processes would remain excluded from hazardous waste regulation. In April 2015 the EPA published the final CCR rule with the material being regulated under the second scenario presented above - as non-hazardous wastes regulated under RCRA Subtitle D.
The final regulations create new compliance requirements including modified storage, new notification and reporting practices, product disposal considerations, and CCR unit closure criteria. Entergy believes that on-site disposal options will be available at its facilities, to the extent needed for CCR that cannot be transferred for beneficial reuse. As of December 31, 2017, Entergy’s2020, Entergy has recorded asset retirement obligations related to CCR management of $8.6 million, including $3.9 million at Entergy Arkansas, $1.8 million at Entergy Louisiana, $1.1 million at Entergy Mississippi, and $1.3 million at Entergy Texas.$20.1 million.
In December 2016 the Water Infrastructure Improvements for the Nation Act (WIIN Act) was signed into law, which authorizes states to regulate coal ash rather than leaving primary enforcement to citizen suit actions. States may submit to the EPA proposals for a permit programs. In September 2017program.
Pursuant to the EPA agreedRule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to reconsiderdate has detected concentrations of certain provisions oflisted constituents in the CCR rule in light of the WIIN Act. The EPAarea, but has not yet initiated a new round of rulemakingindicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and did not extenddetection monitoring will continue as the existing mid-October 2017 groundwater monitoring deadline. Entergy met the existing monitoring deadline, is monitoring state agency actions, and will participate in the regulatory development process.
rule requires. In late-2017, Entergy determined that certain in-ground wastewater treatment system recycle ponds at its White Bluff and Independence facilities require management under the new EPA regulations. EntergyConsequently, in order to move away from using the recycle ponds, White Bluff and Independence each have installed a new permanent bottom ash handling system that does not fall under the CCR rule. As of November 2020, both sites are operating the new system and no longer are sending waste to the recycle ponds. Each site has commenced closure of one of its two recycle ponds, with the remaining pond being held in reserve during initial operation of the new bottom ash handling system. Closure of the remaining recycle pond at each site will commence as soon as possible, but no later than April 11, 2021, which is taking actionthe deadline under the finalized CCR rule to address the operational and regulatory managementcommence closure of these facilities. Entergy also has monitored levels of constituents in the groundwater monitoring system surrounding its coal combustion residual landfills at these locations that require reporting and additional monitoring. Reporting has occurred as required, and monitoring will continue.any unlined recycle ponds. Any potential
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requirements for corrective action or operational changes under the new EPACCR rule are currently beingcontinue to be assessed. Moreover,Notably, ongoing litigation has resulted in the rule is currently underEPA’s continuing review atof the EPA for potential changes, andrule. Consequently, the nature and cost of anyadditional corrective action requirements may depend, in part, on the outcome of the EPA’s review.
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Entergy Corporation, Utility operating companies, and System Energy
Other Environmental Matters
Entergy Louisiana and Entergy Texas
Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, currently is involved in the second phase of the remedial investigation of the Lake Charles Service Center site, located in Lake Charles, Louisiana. A manufactured gas plant (MGP) is believed to have operated at this site from approximately 1916 to 1931. Coal tar, a by-product of the distillation process employed at MGPs, apparently was routed to a portion of the property for disposal. The same area also has been used as a landfill. In 1999, Entergy Gulf States, Inc. signed a second administrative consent order with the EPA to perform a removal action at the site. Removal actions addressed contaminated source material, soil, and sediment and included capping certain soil on and off-site. In 2002 approximately 7,400 tons of contaminated soil and debris were excavated and disposed of from an area within the service center. In 2003 a cap was constructed over the remedial area to prevent the migration of contamination to the surface. In August 2005 an administrative order was issued by the EPA requiring that a 10-year groundwater study be conducted at this site. The groundwater monitoring study commenced in January 2006 and is continuing.2006. The EPA released the second Five Year Review in 2015. TheIn that review, the EPA indicated that the current remediation technique was insufficient and that Entergy would need to utilize other remediation technologies on the site. In July 2015, Entergy submitted a Focused Feasibility Study to the EPA outlining the potential remedies and suggesting installation of the new remedial method, a waterloo barrier. The estimated cost for this remedy is approximately $2 million.million, to be allocated between Entergy is awaiting commentsLouisiana and direction from the EPA on the Focused Feasibility Study and potential remedy selection.Entergy Texas. In early 2017 the EPA indicated that the new remedial method, a waterloo barrier may not be necessary and requested revisions to the Focused Feasibility Study. The EPA plans to provide comments onreleased the revised 2017 Focused Feasibility Study in the nextthird Five Year Review in 2020. Entergylate-2019 confirming that a new remedial method is continuing discussions withnot necessary but requiring continuation of the current groundwater monitoring. The site’s remedy includes monitored natural attenuation of groundwater, and institutional controls to restrict groundwater and land use. The EPA regardinghas determined that no additional actions are needed for the ongoing actions atremedy to be protective over the site.long-term, and the remedy is protective of human health and the environment.
Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas
The Texas Commission on Environmental Quality (TCEQ) notified Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas that the TCEQ believes those entities are potentially responsible parties (PRPs) concerning contamination existing at the San Angelo Electric Service Company (SESCO) facility in San Angelo, Texas. The facility operated as a transformer repair and scrapping facility from the 1930s until 2003. Both soil and groundwater contamination existsexisted at the site. Entergy subsidiaries sent transformers to this facility. Entergy Arkansas, Entergy Louisiana, and Entergy Texas responded to an information request from the TCEQ and continue to cooperate in this investigation.TCEQ. Entergy Louisiana and Entergy Texas joined a group of PRPs responding to site conditions in cooperation with the State of Texas, creating cost allocation models based on review of SESCO documents and employee interviews, and investigating contribution actions against other PRPs. Entergy Louisiana and Entergy Texas have agreed to contribute to the remediation of contaminated soil and groundwater at the site in a measure proportionate to those companies’ involvement at the site, while Entergy Arkansas likely will pay a de minimis amount.site. Current estimates, although variable depending on ultimate remediation design and performance, indicate that Entergy’s total share of remediation costs likely will be approximately $1.5 million to $2 million. Remediation activities continueGroundwater monitoring wells at the site.site were plugged and abandoned in December 2019 following receipt of a certificate of completion issued by the TCEQ. Site decommissioning activities are complete and final disposition of the property will be determined at a later time.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas
The EPA notified Entergy that the EPA believes Entergy is a PRP concerning PCB contamination at the F.J. Doyle Salvage facility in Leonard, Texas. The facility operated as a scrap salvage business during the 1970s to the 1990s. In May 2018 the EPA investigated the site surface and sub-surface soils and, in November 2018 the EPA conducted a removal action, including disposal of PCB contaminated soils. Entergy responded to the EPA’s information requests in May and July 2019. In November 2020 the EPA sent Entergy and other PRPs a demand
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letter seeking reimbursement for response costs totaling $4 million expended at the site. The demand letter is being evaluated and liability and PRP allocation of response costs are yet to be determined.
Entergy Texas
In December 2016 a transformer inside the Hartburg, Texas Substation had an internal fault resulting in a release of approximately 15,000 gallons of non-PCB mineral oil. Cleanup ensued immediately; however, rain caused much of the oil to spread across the substation yard and into a nearby wetland. The Texas Commission on Environmental Quality (TCEQ)TCEQ and the National Response Center were immediately notified, and the TCEQ responded to the site approximately two hours after the cleanup was initiated. The remediation liability is estimated at $2.2 million; however, this number could fluctuate depending on the remediation extent and wetland mitigation requirements. In July 2017,
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Entergy entered into the Voluntary Cleanup Program with the TCEQ. Additional direction is expected from TCEQ regarding final remediation requirements forIn November 2017, additional soil sampling was completed in the site.
Entergy
In May 2015wetland area and, in February 2018, a transformer at the Indian Point facility failed, resulting in a fire and the releasesite summary report of non-PCB oilfindings was submitted to the ground surface.TCEQ. The fire was extinguished byTCEQ responded in June 2018 and requested an ecological exclusion criteria checklist/Tier II screening-level ecological risk assessment, and additional site assessment, additional soil samples, groundwater samples, and some additional diagrams and maps. In October 2018, Entergy submitted the facility’s fire deluge system. No injuries occurred duerequested information to the transformer failure or company response. An estimated 3,000 gallons of oil were released intoTCEQ. In January 2019 the facility’s discharge canalTCEQ responded with another request for information. In March 2019, Entergy submitted the requested information to the TCEQ. In August 2019 the TCEQ responded with a request for additional information including an Affected Property Assessment Report (APAR) and water well survey. The TCEQ has agreed that the environment surrounding the transformer and discharge canal, including the Hudson River, as a resultnecessity of the failure, fire,water well survey is dependent on the results of the groundwater resampling that will occur. Groundwater sampling was completed in December 2019 and fire suppression. Once the fire was extinguished, Indian Point personnel and contractors began recovering free-product from the damaged transformer, the transformer containment moat, and the area surrounding the transformer. The United States Coast Guard designated Entergy as the responsible party under the Oil Pollution Act of 1990 and assessed a $1,000 civil penalty for the discharge of oil into navigable waters. As required, Entergy established a claims process including a voluntary hotline. Entergy received no reportsresults were submitted to the voluntary hotline or claims underTCEQ for review. Based on the established claims process. In September 2016, Indian Point personnel identifiedgroundwater sampling results, the TCEQ confirmed in February 2020 that a water well survey is not necessary and requested the APAR and an oil sheen inEcological Risk Assessment by August 2020. Due to COVID-19 delays, the discharge canal. Further investigation revealed that an estimated 600 gallons of lubricating oil had leaked fromTCEQ extended the Indian Point 3 turbine system. The leaking component has been taken out of serviceAPAR and no oil has been discovered in the Hudson River. In October 2016 the New York Department of Environmental Conservation issued two notices of violation, one for each of these events, and a proposed order on consent for the 2015 event. In January 2017,Ecological Risk Assessment submittal dates to December 2020, which Entergy and the New York Department of Environmental Conservation resolved this matter with an order on consent. Pursuant to the order, Entergy paid approximately $600 thousand in civil penalties, natural resource damages, and oversight costs. Additionally, Entergy repaired a section of the discharge canal wall and will conduct daily visual inspections of the discharge canal wall to help identify additional material erosion or material structural deficiencies. Entergy has completed all compliance obligations under the consent order and the Department of Environmental Conservation closed the matter in December 2017.timely met.
Litigation
Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but certain states in which Entergy operates have proven to be unusually litigious environments. Judges and juries in Louisiana, Mississippi, and Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. The litigation environment in these states poses a significant business risk to Entergy.
Ratepayer and Fuel Cost Recovery Lawsuits (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Mississippi Attorney General Complaint
See Note 2 to the financial statements for a discussion of this proceeding.
Asbestos Litigation(Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)
See Note 8 to the financial statements for a discussion of this litigation.
Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
See Note 8 to the financial statements for a discussion of these proceedings.
Part I Item 1
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Human Capital
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2017,2020, Entergy subsidiaries employed 13,50413,400 people.
|
| | | | |
Utility: | |
|
Entergy Arkansas | 1,2781,244 |
|
Entergy Louisiana | 1,7131,654 |
|
Entergy Mississippi | 737750 |
|
Entergy New Orleans | 274303 |
|
Entergy Texas | 616658 |
|
System Energy | — |
|
Entergy Operations | 3,3613,529 |
|
Entergy Services | 3,2643,859 |
|
Entergy Nuclear Operations | 2,2111,356 |
|
Other subsidiaries | 5047 |
|
Total Entergy | 13,50413,400 |
|
Approximately 4,6003,900 employees are represented by the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the International Brotherhood of Teamsters, the United Government Security Officers of America, and the International Union, Security, Police, and Fire Professionals of America.
Below is the breakdown of Entergy’s employees by gender and race/ethnicity:
| | | | | | | | | | | |
Gender (%) | 2020 | | 2019 |
Female | 21 | | 20 |
Male | 79 | | 80 |
| 100 | | 100 |
| | | | | | | | | | | |
Race/Ethnicity (%) | 2020 | | 2019 |
White | 78 | | 79 |
Black/African American | 15 | | 15 |
Hispanic/Latino | 3 | | 2 |
Asian | 2 | | 2 |
Other | 2 | | 2 |
| 100 | | 100 |
Entergy’s Approach to Human Resources
Entergy’s people and culture enable its success; that is why acquiring, retaining, and developing talent are important components of Entergy’s human resources strategy. Entergy focuses on an approach that includes, among other things, governance and oversight; safety; organizational health, including diversity, inclusion and belonging; and talent management.
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Governance and Oversight
Ensuring that workplace processes support the desired culture and strategy begins with the Board of Directors and the Office of the Chief Executive. The Personnel Committee establishes priorities and reviews performance on a range of topics. It oversees Entergy’s incentive plan design and administers its executive compensation plans to incentivize the behaviors and outcomes that support achievement of Entergy’s corporate objectives. Annually, it reviews executive performance, development and succession plans to align a high performing executive team with Entergy’s priorities. The Personnel Committee also oversees Entergy’s performance through regular briefings on a wide variety of human resources topics including Entergy’s safety culture and performance; organizational health; and diversity, inclusion, and belonging initiatives and performance.
Other committees of the Board oversee other key aspects of Entergy’s culture. For example, the Audit Committee reviews reports on ethics and compliance training and performance, as well as regular reports on calls made to Entergy’s ethics line and related investigations. To maximize the sharing of information and facilitate the participation of all Board members in these discussions, the Board schedules its regular committee meetings in a manner such that all directors can attend.
The Office of the Chief Executive, which includes the Senior Vice President and Chief Human Resources Officer, ensures annual business plans are designed to support Entergy’s talent objectives, reviews workforce-related metrics, and regularly discusses the development, succession planning, and performance of their direct reports and other company officers.
Safety
Entergy’s safety objective is: Everyone Safe. All Day. Every Day. While the COVID-19 pandemic and historical hurricane season presented significant challenges, Entergy’s safety strategy and commitment to excellence showed results in 2020. Entergy employees achieved a total recordable incident rate of 0.40 in 2020 compared to 0.56 in 2019 and 0.48 in 2018. The recordable incident rate equals the number of recordable incidents per 100 full-time equivalents. Recordable incidents include fatalities, lost-time accidents, restricted-duty accidents, and medical attentions and is not inclusive of potential work-related COVID-19 cases. This marked improvement in total recordable incident rate placed Entergy in top-decile in safety performance when benchmarked amongst peers within the Edison Electric Institute.
Organizational Health, including Diversity, Inclusion and Belonging
Entergy believes that organizational health fosters an engaged and productive culture that positions Entergy to deliver sustainable value to its stakeholders. Entergy measures its progress through an organizational health survey coordinated by an external third party. Since initially administering the survey in 2014, Entergy improved from an initial score of 49 (fourth quartile) to a score in 2020 of 72 (near top quartile). In addition to significantly improved scores, initial employee participation of 66 percent in 2014 rose to and remains at 90 percent in 2018-2020.
Entergy believes that a culture focused on diversity, inclusion, and belonging drives foundational engagement. Entergy is committed to developing and retaining a workforce that reflects the rich diversity of the communities it serves. In 2019, Entergy embarked on a three-year phased approach to enhance inclusion for individuals and teams. Among other actions, the primary focus of its 2020 actions was taking a stand against social injustice, reinforcing expectations, training and leading by example, starting at the top of the organization and cascading through management ranks.
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Talent Management
Entergy’s focus on talent management is organized in three areas: developing and attracting a diverse pool of talent, equipping its leaders to develop the organization, and building premier utility capability through employee performance management and succession programs. Entergy believes that developing a diverse pool of local talent equipped with the skills needed, today and in the future, and reflecting the communities Entergy serves will give it a long-term competitive advantage. The focus of Entergy’s leadership development programs is to equip managers with the skills needed to effectively develop their teams and improve the leader-employee relationship. Entergy’s talent development infrastructure, which includes a combination of business function-specific and enterprise-wide learning and development programs, is designed to ensure Entergy has qualified staff with the skills, experiences, and behaviors needed to perform today and prepare for the future. Entergy strives to achieve its strategic priorities by aligning and enhancing team and individual performance with business objectives, effectively deploying talent through succession planning, and managing workforce transitions.
Availability of SEC filings and other information on Entergy’s website
Entergy electronically files reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies, and amendments to such reports. The public may read and copy any materials that Entergy files with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. Copies of the reports that Entergy files with the SEC can be obtained at the SEC’s website.
Entergy uses its website, http://www.entergy.com, as a routine channel for distribution of important information, including news releases, analyst presentations and financial information. Filings made with the SEC are posted and available without charge on Entergy’s website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These filings include annual and quarterly reports on Forms 10-K and 10-Q (including related filings in Inline XBRL format) and current reports on Form 8-K; proxy statements; and any amendments to those reports or statements. All such postings and filings are available on Entergy’s Investor Relations website free of charge. Entergy is providing the address to its internet site solely for the information of investors and does not intend the address to be an active link. The contents of the website are not incorporated into this report.
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RISK FACTORS
See “RISK FACTOR SUMMARY” in Part I Item 1 for a summary of Entergy’s and the Registrant Subsidiaries’ risk factors.
Investors should review carefully the following risk factors and the other information in this Form 10-K. The risks that Entergy faces are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect Entergy’s financial condition, results of operations, and liquidity. See “FORWARD-LOOKING INFORMATION.”
Utility Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The impacts of the COVID-19 pandemic and responsive measures taken on Entergy’s and its Utility operating companies’ business, results of operations, and financial condition are highly uncertain and cannot be predicted.
In December 2019 a novel strain of coronavirus was reported to have surfaced in Wuhan, China. Since then, COVID-19 has spread throughout most countries in the world, including the United States. Public health officials in the United States have both recommended and mandated wearing of masks, precautions to mitigate the spread of COVID-19, including prohibitions on congregating in heavily-populated areas, mandated closure or limitations on the functions of non-essential business, and shelter-in-place orders or similar measures, including throughout Entergy’s service areas. While some of these mitigation measures have been lifted, it is unclear how long certain forms of mitigation measures will remain in place, whether they will be reinstated in the future, and how they will ultimately impact the general economy, Entergy’s customers, and its operations.
Entergy and its Utility operating companies have experienced a decline in commercial and industrial sales and an increase in arrearages and bad debt expense due to non-payment by customers, and expect such reduced levels of sales and increased arrearages and bad debt expense to continue, the extent and duration of which management cannot predict. The Utility operating companies temporarily suspended disconnecting customers for non-payment of bills, and the suspension remains in place at Entergy Arkansas, has been re-instituted at Entergy New Orleans, and could be re-instituted at the other Utility operating companies should their regulators mandate. While they are working with regulators to ensure ultimate recovery for those and other COVID-19 related costs, the amount, method, and timing of such recovery is unknown. Entergy and its Registrant Subsidiaries also could experience, and in some cases have experienced, among other challenges, supply chain, vendor, and contractor disruptions; delays in completion of capital or other construction projects, maintenance, and other operations activities, including prolonged or delayed outages; delays in regulatory proceedings; workforce availability, health or safety issues; increased storm recovery costs; increased cybersecurity risks as a result of many employees telecommuting; increased late or uncollectible customer payments; volatility in the credit or capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available credit facilities); or other adverse impacts on their ability to execute on business strategies and initiatives.
A sustained or further economic decline could adversely impact Entergy’s and the Utility operating companies’ liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, or increased bad debt expense. The Utility operating companies also may experience regulatory outcomes that require them to postpone planned investment and otherwise reduce costs due to the impact of the COVID-19 pandemic on their customers. In addition, if the COVID-19 pandemic continues to create disruptions or turmoil in the credit or financial markets, or adversely impacts Entergy’s credit metrics or ratings, such developments could adversely affect its ability to access capital on favorable terms and continue to meet its
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liquidity needs, or cause a decrease in the value of its defined benefit pension trust funds, as well as its nuclear decommissioning trust funds, all of which are highly uncertain and cannot be predicted.
Entergy cannot predict the extent or duration of the outbreak, the impact of new variants of COVID-19, the timing, availability, distribution or effectiveness of a vaccine, anti-viral or other treatments for COVID-19, governmental responsive measures, or the extent of the effects or ultimate impacts on the global, national or local economy, the capital markets, or its customers, suppliers, operations, financial condition, results of operations, or cash flows.
The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that can be lengthy and subject to appeal, that could resultpotentially resulting in delays in effecting rate changes, lengthy litigation and uncertainty as to ultimate results.
The Utility operating companies are regulated on a cost-of-service and rate of return basis and are subject to statutes and regulatory commission rules and procedures. The rates that the Utility operating companies and System Energy charge reflect their capital expenditures, operations and maintenance costs, allowed rates of return, financing costs, and related costs of service. These rates significantly influence the financial condition, results of operations, and liquidity of Entergy and each of the Utility operating companies and System Energy. These rates are determined in regulatory proceedings and are subject to periodic regulatory review and adjustment, including adjustment upon the initiative of a regulator or affected stakeholders.
In addition, regulators may initiate proceedings to investigate the prudence of costs in the Utility operating companies’ and System Energy’s base rates and examine, among other things, the reasonableness or prudence of the companies’ operation and maintenance practices, level of expenditures (including storm costs and costs associated with capital projects), allowed rates of return and rate base, proposed resource acquisitions, and previously incurred capital expenditures that the operating companies seek to place in rates. The regulators may disallow costs subject to their jurisdiction found not to have been prudently incurred or found not to have been incurred in compliance with applicable tariffs, creating some risk to the ultimate recovery of those costs. Regulatory proceedings relating to rates and other matters typically involve multiple parties seeking to limit or reduce rates. Traditional base rate proceedings, as opposed to formula rate plans, generally have long timelines, are primarily based on historical costs, and may or may not be limited in scope or duration by statute. The length of these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates.rates, such that the Utility operating companies may not fully recover all costs during the rate effective period and the Utility operating companies may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings.
The Utility operating companies have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including the operation of their assets and infrastructure or the quality of their service. Criticism or adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view the applicable operating company in a favorable light and could potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements.
The base rates of Entergy Texas are established largely in traditional base rate case proceedings. Apart fromBetween base rate proceedings, Entergy Texas has also filed to useavailable rate riders to recover the revenue requirements associated with certain authorized historicalincremental costs. For example, Entergy Texas has recovered distribution-related capital investments through theThese riders include a distribution cost recovery factor rider mechanism transmission-relatedfor the recovery of distribution-related capital investmentsinvestment and certain non-fuel MISO charges, through thea transmission cost recovery factor rider mechanism for the recovery of transmission-related capital investments, a generation cost recovery rider mechanism for the recovery of generation-related capital investments, and a fixed fuel factor mechanism for the recovery of MISO fuel and energy-related costs through the fixed fuel factor mechanism. costs.Entergy Texas also is also required to make a filing every three years,
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at a minimum, reconciling its fuel and purchased power costs and fuel factor revenues.In the course of this reconciliation, the PUCT determines whether eligible fuel and fuel-related expenses and revenues are necessary and reasonable, and makes a prudence finding for each of the fuel-related contracts for the reconciliation period.Entergy Texas also is required to file full base rate case proceedings every four years and within eighteen months of utilizing its generation cost recovery rider for investments above $200 million.
Between base rate cases, Entergy Arkansas and Entergy Mississippi are able to adjust base rates annually through formula rate plans that utilize a forward test year (Entergy Arkansas) or forward-looking features (Entergy Mississippi).In response to Entergy Arkansas’s application for a general change in rates in 2015, the APSC approved the formula rate plan tariff proposed by Entergy Arkansas including its use of a projected year test period and an initial five-year term.The initial five-year term expires in 2021 unless2021. Entergy Arkansas requests, and thehas requested APSC approves,approval of the extension of the formula rate plan tariff for an additional five years through 2026. In the event thatIf Entergy Arkansas’s formula rate plan iswere terminated or is not extended beyond the initial term, Entergy Arkansas could file an
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application for a general change in rates that may include a request for continued regulation under a formula rate review mechanism.If Entergy Mississippi’s formula rate plan is terminated, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan.Entergy Arkansas and Entergy Mississippi recover fuel and purchased energy and certain non-fuel costs through other APSC-approved and MPSC-approved tariffs, respectively.
Entergy Louisiana historically sets electric base rates annually through a formula rate plan using an historic test year.The form of the formula rate plan, on a combined basis, was approved in connection with the business combination of Entergy Louisiana and Entergy Gulf States Louisiana and largely followed the formula rate plans that were approved by the LPSC in connection with the full electric base rate cases filed by those companies in February 2013.The formula rate plan was approved for continued usemost recently extended through the test year 2016 filing2019; certain modifications were made in that extension, including a decrease to the allowed return on equity and included a cap in cost of service increases at a cumulative total of $30 million through the formula rate plan cycle, which cap was not reached. The LPSC also approved in the business combination Entergy Louisiana’s continuationaddition of a mechanism to recover non-fuel MISO-related costs, which are calculated separately from the formula rate plan requirements, but embedded in the formula rate plan factor applied on customer bills. Thistransmission cost recovery mechanism expired following the 2015 test year, but was renewed for the 2016 test year. MISO fuel and energy-related costs are recoverable in Entergy Louisiana’s fuel adjustment clause. mechanism.The formula rate plan includescontinues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities as well asand purchase power agreements approved by the LPSC and as noted, for certain transmission investment, among other items. In August 2017, MISO fuel and energy-related costs are recoverable in Entergy Louisiana’s fuel adjustment clause.Entergy Louisiana filedhas a pending request to extend theits formula rate plan for an additional three years and to reset rates to the authorized mid-point return on equity of 9.95%. The filing also seekswith certain modifications, to the formula rate plan, including a narrower, 80 basis points earnings sharing bandwidth and implementation of a rider to recover certain transmission-related investments, when those investments begin delivering benefits to customers. distribution investment recovery mechanism and use of end of period rate base.In the event that the electric formula rate plan is not renewed or extended, Entergy Louisiana would revert to the more traditional rate case environment.
Entergy New Orleans previously operated under a formula rate plan that ended with the 2011 test year. Currently, basedBased on a settlement agreement approved by the City Council, with limited exceptions, no action may be taken with respect tothe base rates of Entergy New Orleans’s base ratesOrleans were frozen until rates arewere implemented from ain connection with the base rate case that must be filed for its electric and gas operationsby Entergy New Orleans in 2018.In November 2019 the City Council issued a resolution resolving the rate case, with rates to become effective retroactive to August 2019.The limited exceptions include implementationresolution allows Entergy New Orleans to implement a three-year formula rate plan, beginning with the 2019 test year as adjusted for forward-looking known and measurable changes.In November 2020 the City Council issued a resolution approving a settlement of the final year2018 rate case.As part of a four-year phased-in rate increase for its Algiers operations in the Fifteenth Ward of the City ofthis settlement, Entergy New Orleans agreed to postpone the filing of its first test year formula rate plan to 2021 and, certain exceptional cost increases or decreases in its base revenue requirement.return, to be provided an additional test year for the three-year cycle.See Note 2 to the financial statements for further discussion.
The rates of System Energy are established by the FERC, and the costs allowed to be charged pursuant to these rates are, in turn, passed through to the participating Utility operating companies through the Unit Power Sales Agreement, which allowshas monthly adjustments tobillings that reflect the current operating costs of, and investment in, Grand Gulf. Retail regulators and other parties may seek to initiate proceedings at FERC to investigate the prudence of costs included in the rates charged under the Unit Power Sales Agreement and examine, among other things, the
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reasonableness or prudence of the operation and maintenance practices, level of expenditures, allowed rates of return and rate base, and previously incurred capital expenditures. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a separate request for FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings nor can it predict whether any outcome could have a material effect on Entergy’s or System Energy’s results of operations, financial condition or liquidity. See Note 2 to the financial statements for further discussion of the proceedings. System Energy has received FERC acceptance for billing protocols to provide retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
The Utility operating companies and System Energy, and the energy industry as a whole, have experienced a period of rising costs and investments, and an upward trend in spending, especially with respect to infrastructure investments, which is likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms. For information regarding rate case proceedings and formula rate plans applicable to the Utility operating companies, see Note 2 to the financial statements.
Changes to state or federal legislation or regulation affecting electric generation, electric and natural gas transmission, distribution, and related activities could adversely affect Entergy and the Utility operating companies’ financial position, results of operations, or cash flows and their utility businesses.
If legislative and regulatory structures evolve in a manner that erodes the Utility operating companies’ exclusive rights to serve their regulated customers, they could lose customers and sales and their results of operations, financial position, or cash flows could be materially affected. Additionally, technological advances in energy efficiency and distributed energy resources are reducing the costs of these technologies and together with ongoing state and federal subsidies, the increasing penetration of these technologies could result in reduced sales by the Utility operating companies. Such loss of sales could put upward pressure on rates, resulting in adverse regulatory actions to mitigate such effects on rates. Entergy and the Utility operating companies cannot predict if or when they may be subject to changes in legislation or regulation, or the extent and timing of reductions of the cost of distributed energy resources, nor can they predict the impact of these changes on their results of operations, financial position, or cash flows.
The Utility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings.
The Utility operating companies recover their fuel, purchased power, and associated costs from their customers through rate mechanisms subject to periodic regulatory review and adjustment. Because regulatory review can result in the disallowance of incurred costs found not to have been prudently incurred, including the cost of replacement power purchased when generators experience outages or when planned outages are extended, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs, particularly when there are substantial or sudden increases in such costs. Regulators also may also initiate proceedings to investigate the continued usage or the adequacy and operation of the fuel and purchased power recovery clauses of the Utility operating companies and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.
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The Utility operating companies’ cash flows can be negatively affected by the time delays between when gas, power, or other commodities are purchased and the ultimate recovery from customers of the costs in rates. On occasion, when the level of incurred costs for fuel and purchased power rises very dramatically, some of the Utility operating companies may agree to defer recovery of a portion of that period’s fuel and purchased power costs for recovery at a later date, which could increase the near-term working capital and borrowing requirements of those companies. For a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power costs recovery, see Note 2 to the financial statements.
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There remains uncertainty regarding the effect of the termination of the System Agreement on the Utility operating companies.
The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating resources and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that had been approved by the FERC. The System Agreement terminated in its entirety on August 31, 2016.
There remains uncertainty regarding the long-term effect of the termination of the System Agreement on the Utility operating companies because of the significant effect of the agreement on the generation and transmission functions of the Utility operating companies and the significant period of time (over 30 years) that it had been in existence. In the absence of the System Agreement, there remains uncertainty around the effectiveness of governance processes and the potential absence of federal authority to resolve certain issues among the Utility operating companies and their retail regulators.
In addition, although the System Agreement terminated in its entirety in August 2016, there are a number offew outstanding System Agreement proceedings at the FERC and at the D.C. Circuit that may require future adjustments, including challenges to the level and timing of payments made by Entergy Arkansas under the System Agreement. The outcome and timing of these FERC proceedings and resulting recovery and impact on rates cannot be predicted at this time.
For further information regarding the regulatory proceedings relating to the System Agreement, see Note 2 to the financial statements.
The Utility operating companies are subject to economic risks associated with participation in the MISO markets and the allocation of transmission upgrade costs. The operation of the Utility operating companies’ transmission system pursuant to the MISO RTO tariff and their participation in the MISO RTO’s wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
On December 19, 2013, the Utility operating companies integrated into the MISO RTO. MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. The Utility operating companies are subject to economic risks associated with participation in the MISO markets. MISO tariff rules and system conditions, including transmission congestion, could affect the Utility operating companies’ ability to sell powercapacity, energy, and/or ancillary services in certain regions and/or the economic value of such sales, or the cost of serving the Utility operating companies’ respective loads, and MISO market rules may change in ways that cause additional risk.
The Utility operating companies participate in the MISO regional transmission planning process and are subject to risks associated with planning decisions that MISO makes in the exercise of control over the planning of the Utility operating companies’ transmission assets that are under MISO’s functional control. The Utility operating companies pay transmission rates that reflect the cost of transmission projects that the Utility operating companies do not own, which could increase cash or financing needs. MISO is currently evaluating through its stakeholder process potential changes in the transmission project criteria in MISO. These changes, if adopted, could potentially result in a larger
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volume of competitively bid and regionally cost allocated transmission projects. In addition to the cash and financing-related risks arising from the potential additional cost allocation to the Utility operating companies from thesetransmission projects of others, there is a risk that the Utility operating companies’ business and financial position could be harmed as a result of lost investment opportunities and other effects that flow from an increased number of competitive projects being approved and constructed that are interconnected with their transmission systems. Further, the terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets, the
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allocation of transmission upgrade costs, the MISO-wide allowed base rate of return on equity, and any required MISO-related charges and credits are subject to regulation by the FERC. The operation of the Utility operating companies’ transmission system pursuant to the MISO tariff and their participation in the MISO wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements. In addition, orders from each of the Utility operating companies’ respective retail regulators generally require that the Utility operating companies make periodic filings, or generally allow the retail regulator to direct the making of such filings, setting forth the results of analysis of the costs and benefits realized from MISO membership as well as the projected costs and benefits of continued membership in MISO and/or requesting approval of their continued membership in MISO. These filings have been submitted periodically by each of the Utility operating companies as required by their respective retail regulators, and the outcome of the resulting proceedings may affect the Utility operating companies’ continued membership in MISO.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather (including from Hurricane Laura, Hurricane Delta, and Hurricane Zeta), or the impact on customer bills of permitted storm cost recovery, could have material effects on Entergy and thoseits Utility operating companies affected by severe weather.companies.
Entergy’s and its Utility operating companies’ results of operations, liquidity, and financial condition can be materially affected by the destructive effects of severe weather. Severe weather can also result in significant outages for the customers of the Utility operating companies and, therefore, reduced revenues for the Utility operating companies during the period of the outages. A delay or failure in recovering amounts for storm restoration costs incurred or revenues lost as a result of severe weather could have a material effect on Entergy and those Utility operating companies affected by severe weather. In addition, the recovery of major storm restoration costs from customers could effectively limit our ability to make planned capital or other investments due to the impact of such storm cost recovery on customer bills.
In August and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of the Utility’s service territories in Louisiana, including New Orleans, Texas, and to a lesser extent, in Arkansas and Mississippi. The storms resulted in widespread power outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild. Total restoration costs for the repair and/or replacement of the electrical system damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta are currently estimated to be approximately $2.4 billion. Because Entergy has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Nuclear Operating, Shutdown, and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)
Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities must consistently operate their nuclear power plants at high capacity factors in order to be successful, and lower capacity factors could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Nuclear capacity factors significantly affect the results of operations of certain Utility operating companies, System Energy, and Entergy Wholesale Commodities. Nuclear plant operations involve substantial fixed operating
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costs. Consequently, to be successful, a plant owner must consistently operate its nuclear power plants at high capacity factors, consistent with safety requirements. For the Utility operating companies that own nuclear plants, lower capacity factors can increase production costs by requiring the affected companies to generate additional energy, sometimes at higher costs, from their fossilowned or contractually controlled facilities or purchase additional energy in the spot or forward markets in order to satisfy their supply needs. For the Entergy Wholesale Commodities nuclear plants, lower capacity factors directly affect revenues and cash flow from operations. Entergy Wholesale Commodities’ forward sales are comprised of various hedge products, many of which have some degree of operational-contingent price risk. Certain unit-contingent contracts guarantee specified minimum capacity factors. In the event plants with these contracts were operating below the guaranteed capacity factors, Entergy would be subject to price risk for the undelivered power. Further, Entergy Wholesale Commodities’ nuclear forward sales contracts can also be on a firm LD basis, which subjects Entergy to increasing price risk as capacity factors decrease. Many of these firm hedge products have damages risk, capped through the use of risk management products.risk.
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Certain of the Utility operating companies and System Energy and the Entergy Wholesale Commodities nuclear plant owners periodically shut down their nuclear power plants to replenish fuel. Plant maintenance and upgrades are often scheduled during such refueling outages. If refueling outages last longer than anticipated or if unplanned outages arise, Entergy’s and their results of operations, financial condition, and liquidity could be materially affected.
Outages at nuclear power plants to replenish fuel require the plant to be “turned off.” Refueling outages generally are planned to occur once every 18 to 24 months and average approximately 30 days in duration.months. Plant maintenance and upgrades are often scheduled during such planned outages.outages, which typically extends the planned outage duration. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease, and maintenance costs may increase. Lower than forecasted capacity factors may cause Entergy Wholesale Commodities to experience reduced revenues and may also create damages risk with certain hedge products as previously discussed.
Certain of the Utility operating companies and System Energy and Entergy Wholesale Commodities face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication). These risks could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Based upon currently planned fuel cycles, Entergy’s nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable prices through most of 2018. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment is being adjusted to reflect reduced overall requirements related to the planned permanent shutdown of the Palisades, Pilgrim, Indian Point 22020 and Indian Point 3 plants over the next two to five years.beyond. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. While there are a number of possible alternate suppliers that may be accessed to mitigate any supplier performance failure, the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S. Market prices for nuclear fuel have been extremely volatile from time to time in the past.past and may be subject to increased volatility due to the imposition of tariffs, domestic purchase requirements or limitations on importation of uranium or uranium products from foreign countries, or shifting trade arrangements between countries. Although Entergy’s nuclear fuel contract portfolio provides a degree of hedging against market risks for several years, costs for nuclear fuel in the future cannot be predicted with certainty due to normal inherent market uncertainties, and price changes could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy, and Entergy Wholesale Commodities.Energy.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance and reliability of conversion, enrichment, and fabrication services providers. These service providers are fewer in number than uranium suppliers. For conversion and enrichment services, Entergy diversifies its supply by supplier and country and may take special measures to ensure a reliable supply of enriched uranium for fabrication into nuclear fuel. For fabrication services, each plant is dependent upon the performance of the fabricator of that plant’s nuclear fuel; therefore, Entergy relies upon additional monitoring, inspection, and oversight of the fabrication process to assure reliability and quality of its nuclear fuel. Certain of the suppliers and service providers are located in or dependent upon countries, such as Russia, in which deteriorating economic conditions or international sanctions or tariffs could further restrict the ability of such
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suppliers to continue to supply fuel or provide such services.services at acceptable prices or at all. The inability of such suppliers or service providers to perform such obligations could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy, and Entergy Wholesale Commodities.Energy.
Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business face the risk that the NRC will change or modify its regulations, suspend not renew, or revoke their licenses, or increase oversight of their nuclear plants, which could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Under the Atomic Energy Act and Energy Reorganization Act, the NRC regulates the operation of nuclear power plants. The NRC may modify, suspend, not renew, or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations, or the terms of the licenses for
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nuclear facilities. The license renewal process in some cases may be the subject of significant public debate and legislative review and scrutiny at the federal and, in some cases, state level, though the decision whether to renew is subject to the exclusive jurisdiction of the NRC. Interested parties may also intervene which could result in prolonged proceedings. A change in the Atomic Energy Act, other applicable statutes, or the applicable regulations or licenses, or the NRC’s interpretation thereof, may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially affect the results of operations, liquidity, or financial condition of Entergy (through Entergy Wholesale Commodities), its Utility operating companies, or System Energy. A change in the classification of a plant owned by one of these companies under the NRC’s Reactor Oversight Process, which is the NRC’s program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response, also could cause the owner of the plant to incur material additional costs as a result of the increased oversight activity and potential response costs associated with the change in classification.For additional information concerning the current classification of the plants owned by Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business, see “Regulation of Entergy’s Business- Regulation of the Nuclear Power Industry - NRC Reactor Oversight Process” in Part I, Item 1 and Note 8 to the financial statements.1.
Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate actions to modify, suspend, or revoke licenses, shut down a nuclear facility, or impose civil penalties. As a result, if an incident were to occur at any nuclear generating unit, whether an Entergy nuclear generating unit or not, it could materially affect the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, System Energy, or Entergy Wholesale Commodities.
Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities are exposed to risks and costs related to operating and maintaining their nuclear power plants, and their failure to maintain operational efficiency at their nuclear power plants could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
The nuclear generating units owned by certain of the Utility operating companies, System Energy,and the Entergy Wholesale Commodities business began commercial operations in the 1970s-1980s. Older equipment may require more capital expenditures to keep each of these nuclear power plants operating safely and efficiently. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages, or any unanticipated capital expenditures, could result in increased costs, some of which costs may not be fully recoverable by the Utility operating companies and System Energy in regulatory proceedings.proceedings should there be a determination of imprudence. Operations at any of the nuclear generating units owned and operated by Entergy’s subsidiaries could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. A decision may be made to close a unit rather than incur the expense of restarting it or returning the unit to full capacity. For the Utility operating companies and System Energy, this could result in certain costs being stranded and potentially not fully recoverable in regulatory proceedings. For Entergy Wholesale Commodities, this could result in lost revenue and increased fuel and purchased power expense to meet
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supply commitments and penalties for failure to perform under their contracts with customers. In addition, the operation and maintenance of Entergy’s nuclear facilities require the commitment of substantial human resources that can result in increased costs.
The nuclear industry continues to address susceptibility to the effects of stress corrosion cracking and other corrosion mechanisms on certain materials within plant systems. The issue is applicable at all nuclear units to varying degrees and is managed in accordance with industry standard practices and guidelines that include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.
Moreover, Entergy is becoming more dependent on fewer suppliers for key parts of Entergy’s nuclear power plants that may need to be replaced or refurbished.refurbished, and in some cases, parts are no longer available and have to be reverse-engineered for replacement. In addition, certain major parts have long lead-times to manufacture
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if an unplanned replacement is needed. This dependence on a reduced number of suppliers and long lead-times on certain major parts for unplanned replacements could result in delays in obtaining qualified replacement parts and, therefore, greater expense for Entergy.
The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities nuclear power plants, as well as the costs of and their ability to fully decommission their nuclear power plants, could be significantly affected by the timing of the opening of a spent nuclear fuel disposal facility, as well as interim storage and transportation requirements.
Certain of the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities nuclear plants incur costs for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the disposal of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, or any interim storage facility, and the timing of such facility opening, will significantly affect the costs associated with on-site storage of spent nuclear fuel. For example, while the DOE is required by law to proceed with the licensing of Yucca Mountain and, after the license is granted by the NRC, to construct the repository and commence the receipt of spent fuel, the NRC licensing of the Yucca Mountain repository is effectively at a standstill. These actions are prolonging the time before spent fuel is removed from Entergy’s plant sites. Because the DOE has not accomplished its objectives, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts, and Entergy has sued the DOE for such breach. Furthermore, Entergy is uncertain as to when the DOE will commence acceptance of spent fuel from its facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at the companies’ nuclear sites and maintenance costs on existing storage facilities, including aging management of fuel storage casks, may increase. The costs of on-site storage are also affected by regulatory requirements for such storage. In addition, the availability of a repository or other off-site storage facility for spent nuclear fuel may affect the ability to fully decommission the nuclear units and the costs relating to decommissioning. For further information regarding spent fuel storage, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs – Spent Fuel Disposal” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 8 to the financial statements.
Certain of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities nuclear plant owners may be required to pay substantial retrospective premiums imposed under the Price-Anderson Act in the event of a nuclear incident, and losses not covered by insurance could have a material effect on Entergy’s and their results of operations, financial condition, or liquidity.
Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere. The Price-Anderson Act limits each reactor owner’s public liability (off-site) for a single nuclear incident to the payment of retrospective premiums into a secondary insurance pool, ofwhich is referred to as Secondary Financial Protection, up to approximately $127.3$137.6 million per reactor. With 10297 reactors currently
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
participating, this translates to a total public liability cap of approximately $13$14 billion per incident. The limit is subject to change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As required by the Price-Anderson Act, the Utility operating companies, System Energy, and Entergy Wholesale Commodities carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers, (whichwhich is $450 million for each operating site as of January 1, 2018).site. Claims for any nuclear incident exceeding that amount are covered under the retrospective premiums paid into the secondary insurance pool.Secondary Financial Protection. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the primary insurance coverage, each owner of a nuclear plant reactor, including Entergy’s Utility operating companies, System Energy, and the Entergy Wholesale Commodities plant owners, regardless of fault or proximity to the incident, will be required to pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary insurance level, up to a maximum of approximately $127.3$137.6 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.146$1.101 billion). The retrospective premium payment is currently limited to approximately $19$21 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $127.3$137.6 million cap.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
NEIL is a utility industry mutual insurance company, owned by its members, including the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities plants. All member plants could be subject to an annual assessment (retrospective premium of up to 10 times current annual premium for all policies) should the NEIL surplus (reserve) be significantly depleted due toinsured losses. As of December 31, 2017,2020, the maximum annual assessment amounts total $112.2$104 million for the Utility plants. Retrospective premium insurance available through NEIL’s reinsurance treaty can cover the potential assessments and the Entergy Wholesale Commodities plants currently maintain the retrospective premium insurance to cover those potential assessments.
As an owner of nuclear power plants, Entergy participates in industry self-insurance programs and could be liable to fund claims should a plant owned by a different company experience a major event. Any resulting liability from a nuclear accident may exceed the applicable primary insurance coverage and require contribution of additional funds through the industry-wide program that could significantly affect the results of operations, financial condition, or liquidity of Entergy, certain of the Utility operating companies, System Energy, or the Entergy Wholesale Commodities subsidiaries.
The decommissioning trust fund assets for the nuclear power plants owned by the Utility operating companies, System Energy, and the Entergy Wholesale Commodities nuclear plant owners may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts, if one or more of Entergy’s nuclear power plants is retired earlier than the anticipated shutdown date, if the plants cost more to decommission than estimated, or if current regulatory requirements change, which then could require significant additional funding.
Owners of nuclear generating plants have an obligation to decommission those plants. Certain of the Utility operating companies, System Energy, and owners of the Entergy Wholesale Commodities nuclear power plants maintain decommissioning trust funds for this purpose. Certain of the Utility operating companies collect funds from their customers, which are deposited into the trusts covering the units operated for or on behalf of those companies. Those rate collections, as adjusted from time to time by rate regulators, are generally based upon operating license lives and trust fund balances as well as estimated trust fund earnings and decommissioning costs. Assets in these trust funds are subject to market fluctuations, will yield uncertain returns that may fall below projected return rates, and may result in losses resulting from the recognition of impairments of the value of certain securities held in these trust funds.
In connection with the acquisition of certain nuclear plants, the Entergy Wholesale Commodities plant owners acquired decommissioning trust funds that are funded in accordance with NRC regulations. Under NRC regulations, Entergy Wholesale Commodities’ nuclear subsidiariesplant owners are permitted to project the NRC-required decommissioning amount, based on an NRC formula or a site-specific estimate, and the amount that will be available in each of the Entergy Wholesale Commodities nuclear power plant’s decommissioning trusts combined with any other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used, for each of these nuclear power plants. As a result, ifused. If the projected amount of each individual plants’plant’s decommissioning trusts exceeds the NRC-required decommissioning amount, then its NRC license termination decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs the applicable Entergy subsidiaries would be required to incur to decommission these nuclear power plants, or funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources or commitments would be required. Furthermore, depending upon the level of funding available in the trust funds, the NRC may not permit the trust funds to be used to pay for related costs such as the management of spent nuclear fuel that are not included in the NRC’s formula. The NRC may also require a plan for the provision of separate funding for spent fuel management costs. In addition to NRC requirements, there are other decommissioning-related obligations for certain of the Entergy Wholesale Commodities nuclear power plants, which management believes it will be able to satisfy.
Further, federal or state regulatory changes, including mandated increases in decommissioning funding or changes in the methods or standards for decommissioning operations, may also increase the funding requirements of,
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
or accelerate the timing for funding of, the obligations related to the decommissioning of the Utility operating companies, System Energy, or Entergy Wholesale Commodities nuclear power plants or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. Such changes also could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. As a result, under any of these circumstances, Entergy’s results of operations, liquidity, and financial condition could be materially affected.
An early plant shutdown (either generally or relative to current expectations), poor investment results, or higher than anticipated decommissioning costs (including as a result of changing regulatory requirements) could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that the Utility operating companies, System Energy, or the Entergy Wholesale Commodities nuclear plant owners may be required to provide significant additional funds or credit support to satisfy regulatory requirements for decommissioning, which, with respect to the Utility operating companies, may not be recoverable from customers in a timely fashion or at all.
For further information regarding nuclear decommissioning costs, management’s decision to exit the merchant power business, and the impairment charges that resulted from such decision, and the planned sales of Palisades and Indian Point Energy Center (which, in each case, will include the transfer of the associated decommissioning trusts), see the “Critical Accounting Estimates- Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy, the “Entergy Wholesale Commodities Exit from the Merchant Power Business” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries, and Notes 9 and 14 to the financial statements.
Changes in NRC regulations or other binding regulatory requirements may cause increased funding requirements for nuclear plant decommissioning trusts.
NRC regulations require certain minimum financial assurance requirements for meeting obligations to decommission nuclear power plants. Those financial assurance requirements may change from time to time, and certain changes may result in a material increase in the financial assurance required for decommissioning the Utility operating companies’, System Energy’s, and owners of Entergy Wholesale Commodities nuclear power plants. Such changes could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. For further information regarding nuclear decommissioning costs, see the “Critical Accounting Estimates– Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 9 to the financial statements.
New or existing safety concerns regarding operating nuclear power plants and nuclear fuel could lead to restrictions upon the operation and decommissioning of Entergy’s nuclear power plants.
New and existing concerns are being expressed in public forums about the safety of nuclear generating units and nuclear fuel, in particular in the northeastern United States, which is where most of the current fleet of Entergy Wholesale Commodities nuclear power plants is located.fuel. These concerns have led to, and are expected tomay continue to lead to, various proposals to Federal regulators and governing bodies in some localities where Entergy’s subsidiaries own nuclear generating units for legislative and regulatory changes that couldmight lead to the shutdown of nuclear units, denial of license renewal applications, additional requirements or restrictions related to spent nuclear fuel on-site storage and eventual disposal, or other adverse effects on owning, operating, and decommissioning nuclear generating units. Entergy vigorously responds to these concerns and proposals. If any of the existing proposals, or any proposals that may arise in the future with respect to legislative and regulatory changes, become effective, they could have a material effect on Entergy’s results of operations and financial condition, and liquidity.condition.
(Entergy Corporation)
A failure to obtain renewed licenses or other approvals required for the continued operation of the Entergy Wholesale Commodities’ Indian Point nuclear power plants could have a material effect on Entergy’s results of operations, financial condition, and liquidity and could lead to an acceleration of the timing for the funding of decommissioning obligations.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
(Entergy Corporation)
The license renewal and related processes for the Entergy Wholesale Commodities’ Indian Point nuclear power plants have been and may continue to be the subject of significant public debate and regulatory and legislative review and scrutiny at the federal and, in certain cases, state level. The original expiration date of the operating license for Indian Point 2 was September 2013 and the original expiration date of the operating license for Indian Point 3 was December 2015. Because these plants filed timely license renewal applications, the NRC’s rules provide that these plants may continue to operate under their existing operating licenses until their renewal applications have been finally determined.
In January 2017, Entergy announced that it plans to shut down Indian Point 2 in 2020 and Indian Point 3 in 2021. The early and orderly shutdown is part of a settlement under which New York State has agreed to drop legal challenges and support renewal of the operating licenses for Indian Point. For additional discussion of the settlement agreement with New York State, see the “Entergy Wholesale Commodities Authorizations to Operate Indian Point” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
If the NRC were to deny the applications for the renewal of operating licenses for the Indian Point nuclear power plants, or if Indian Point fails to obtain other approvals, Entergy’s results of operations, financial condition, and liquidity could be materially affected by loss of revenue and cash flow associated with the plant or plants until the proposed shutdown date, potential impairments of the carrying value of the plants, increased depreciation rates, and an accelerated need for decommissioning funds, which could require additional funding. In addition, Entergy may incur increased operating costs depending on any conditions that may be imposed in connection with license renewal. For further discussion regarding the license renewal processes for the Indian Point nuclear power plants, see the “Entergy Wholesale Commodities Authorizations to Operate Indian Point” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
Entergy Wholesale Commodities nuclear power plants are exposed to price risk.
Entergy and its subsidiaries do not have a regulator-authorized rate of return on their capital investments in non-utility businesses. As a result, the sale of capacity and energy from the Entergy Wholesale Commodities nuclear power plants, unless otherwise contracted, is subject to the fluctuation of market power prices. In order to reduce future price risk to desired levels, Entergy Wholesale Commodities utilizes contracts that are unit-contingent and Firm LD and various products such as forward sales, options, and collars. As of December 31, 2017,2020, Entergy Wholesale Commodities’ nuclear power generation plants had sold forward 98% in 2018, 91% in 2019, 51% in 2020, 74% in 2021 and 67%99% in 2022 of its generation portfolio’s planned energy output, reflecting the planned shutdown orand sale of the remaining Entergy Wholesale Commodities nuclear power plants by mid-2022.
Market conditions such as product cost, market liquidity, and other portfolio considerations influence the product and contractual mix. The obligations under unit-contingent agreements depend on a generating asset that is operating; if the generation asset is not operating, the seller generally is not liable for damages. For some unit-contingent obligations, however, there is also a guarantee of availability that provides for the payment to the power purchaser of contract damages, if incurred, in the event the unit owner fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. Firm LD sales transactions may be exposed to substantial operational price risk, a portion of which may be capped through the use of risk management products, to the extent that the plants do not run as expected and market prices exceed contract prices.
Market prices may fluctuate substantially, sometimes over relatively short periods of time, and at other times experience sustained increases or decreases. Demand for electricity and its fuel stock can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply, prices might be depressed. Also, from time to time there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, credit requirements, bidding rules, and other mechanisms to address volatility and other issues in these markets.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The effects of sustained low natural gas prices and power market structure challenges have resulted in lower market prices for electricity in the power regions where the Entergy Wholesale Commodities nuclear power plants are located. In addition, currently the market design under which the plants operate does not adequately compensate merchant nuclear plants for their environmental and fuel diversity benefits in the region. These conditions were primary factors leading to Entergy’s decision to shut down (or sell) Entergy Wholesale Commodities’ nuclear power plants before the end of their operating licenses (or requested operating licenses for Indian Point 2 and Indian Point 3).licenses.
The price that different counterparties offer for various products including forward sales is influenced both by market conditions as well as the contract terms such as damage provisions, credit support requirements, and the number of available counterparties interested in contracting for the desired forward period. Depending on differences between market factors at the time of contracting versus current conditions, Entergy Wholesale Commodities’ contract portfolio may have average contract prices above or below current market prices, including at the expiration of the contracts, which may significantly affect Entergy Wholesale Commodities’ results of operations, financial condition, or liquidity. New hedges are generally layered into on a rolling forward basis, which tends to drive hedge over-performance to market in a falling price environment, and hedge underperformance to market in a rising price environment; however, hedge timing, product choice, and hedging costs will also affect these results. See the “Market and Credit Risk Sensitive Instruments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries. Since Entergy Wholesale Commodities has announced the closure (or sale) of its nuclear plants, Entergy Wholesale Commodities may enter into fewer forward sales contracts for output from such plants.
Among the factors that could affect market prices for electricity and fuel, all of which are beyond Entergy’s control to a significant degree, are:
prevailing market prices for natural gas, uranium (and its conversion, enrichment, and fabrication), coal, oil, and other fuels used in electric generation plants, including associated transportation costs, and supplies of such commodities;
seasonality and realized weather deviations compared to normalized weather forecasts;
availability of competitively priced alternative energy sources and the requirements of a renewable portfolio standard;
changes in production and storage levels of natural gas, lignite, coal and crude oil, and refined products;
liquidity in the general wholesale electricity market, including the number of creditworthy counterparties available and interested in entering into forward sales agreements for Entergy’s full hedging term;
the actions of external parties, such as the FERC and local independent system operators and other state or Federal energy regulatory bodies, that may impose price limitations and other mechanisms to address some of the volatility in the energy markets;
electricity transmission, competing generation or fuel transportation constraints, inoperability, or inefficiencies;
the general demand for electricity, which may be significantly affected by national and regional economic conditions;
weather conditions affecting demand for electricity or availability of hydroelectric power or fuel supplies;
the rate of growth in demand for electricity as a result of population changes, regional economic conditions, and the implementation of conservation programs or distributed generation;
regulatory policies of state agencies that affect the willingness of Entergy Wholesale Commodities customers to enter into long-term contracts generally, and contracts for energy in particular;
increases in supplies due to actions of current Entergy Wholesale Commodities competitors or new market entrants, including the development of new generation facilities, expansion of existing generation facilities, the disaggregation of vertically integrated utilities, and improvements in transmission that allow additional supply to reach Entergy Wholesale Commodities’ nuclear markets;
union and labor relations;
changes in Federal and state energy and environmental laws and regulations and other initiatives, such as the Regional Greenhouse Gas Initiative, including but not limited to, the price impacts of proposed emission controls;
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Entergy Corporation, Utility operating companies, and System Energy
changes in law resulting from federal or state energy legislation or legislation subjecting energy derivatives used in hedging and risk management transactions to governmental regulation; and
natural disasters, terrorist actions, wars, embargoes, and other catastrophic events.
The Entergy Wholesale Commodities business is subject to substantial governmental regulation and may be adversely affected by legislative, regulatory, or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
The Entergy Wholesale Commodities business is subject to extensive regulation under federal, state, and local laws. Compliance with the requirements under these various regulatory regimes may cause the Entergy Wholesale Commodities business to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines, and/or civil or criminal liability.
Public utilities under the Federal Power Act are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Each of the owners of the Entergy Wholesale Commodities nuclear power plants that generates electricity, as well as Entergy Nuclear Power Marketing, LLC, is a “public utility” under the Federal Power Act by virtue of making wholesale sales of electric energy and/or owning wholesale electric transmission facilities. The FERC has granted these generating and power marketing companies the authority to sell electricity at market-based rates. The FERC’s orders that grant the Entergy Wholesale Commodities’ generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that the Entergy Wholesale Commodities business can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, the Entergy Wholesale Commodities’ market-based sales are subject to certain market behavior rules, and if any of its generating and power marketing companies were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority and potential penalties of up to $1$1.29 million per day per violation. If the Entergy Wholesale Commodities’ generating or power marketing companies were to lose their market-based rate authority, such companies would be required to obtain the FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates the Entergy Wholesale Commodities business charges for power from its facilities.
The Entergy Wholesale Commodities business is also affected by legislative and regulatory changes, as well as changes to market design, market rules, tariffs, cost allocations, and bidding rules imposed by the existing Independent System Operators. The Independent System Operators that oversee most of the wholesale power markets may impose, and in the future may continue to impose, mitigation, including price limitations, offer caps and other mechanisms, to address some of the volatility and the potential exercise of market power in these markets. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of the Entergy Wholesale Commodities business’ generation facilities that sell energy and capacity into the wholesale power markets. Further, the New York Independent System Operator could determine that the timing of the shutdown of the Indian Point units could be inconsistent with its market power rules, and impose certain penalties that could affect Entergy Wholesale Commodities. For further information regarding federal, state, and local laws and regulation applicable to the Entergy Wholesale Commodities business, see the “Regulation of Entergy’s Business” section in Part I, Item 1.
The regulatory environment applicable to the electric power industry is subject to changes as a result of restructuring initiatives at both the state and federal levels. Entergy cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on the Entergy Wholesale Commodities business. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism, have raised claims that the competitive marketplace is not working because energy prices in wholesale markets exceed the marginal cost of operating nuclear power plants, and have made proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process, which
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
could require material changes to business planning models. If competitive restructuring of the electric power markets is reversed, modified, discontinued, or delayed, the Entergy Wholesale Commodities business’ results of operations, financial condition, and liquidity could be materially affected.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The power plants owned by the Entergy Wholesale Commodities business are subject to impairment charges in certain circumstances, which could have a material effect on Entergy’s results of operations, financial condition, or liquidity.
Entergy reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from the operations of such assets. Projected net cash flows depend on the expected operating life of the assets, the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy and capacity over the remaining life of the assets. In particular, the remaining assets of the Entergy Wholesale Commodities business are subject to further impairment in connection with the closure orand sale of the plants discussed below.its nuclear power plants. Moreover, prior to the closure orand sale of these plants, the failure of the Entergy Wholesale Commodities business to achieve forecasted operating results and cash flows, an unfavorable change in forecasted operating results or cash flows, a reduction in the expected remaining useful life of a unit, (including if the operating licenses for the Indian Point power plants are not renewed by the NRC), or a decline in observable industry market multiples could all result in potential additional impairment charges for the affected assets.
On August 27, 2013, Entergy announced its plan to close and decommission Vermont Yankee. Vermont Yankee ceased power production in the fourth quarter 2014 at the end of a fuel cycle. This decision was approved by the Board in August 2013, and resulted in the recognition of impairment charges in 2013 and 2014. In October 2015, Entergy determined that it will close the Pilgrim and FitzPatrick plants. The Pilgrim plant will cease operations no later than June 1, 2019. FitzPatrick was expected to shut down at the end of its current fuel cycle, planned for January 27, 2017, but in March 2017, Entergy sold the FitzPatrick plant to Exelon Generation Company, LLC which continues to operate the plant. During the third quarter 2015, Entergy recorded impairment and other related charges to write down the carrying values of the FitzPatrick and Pilgrim plants and related assets to their fair values. In addition, in the fourth quarter 2015, Entergy recorded impairment and other related charges to write down the carrying value of the Palisades plant and related assets to their fair value. In December 2016, Entergy reached an agreement with Consumers Energy to terminate the PPA for the Palisades plant and to shut down the plant in 2018, but the agreement was terminated in September 2017 after the Michigan Public Service Commission decided that Consumers Power could not recover costs incurred under the agreement. Entergy intends to shut down the Palisades plant permanently on May 31, 2022. In January 2017, Entergy announced that it reached a settlement with New York State and plans to close the Indian Point 2 plant in 2020 and the Indian Point 3 plant in 2021. As a result, in the fourth quarter of 2016, Entergy recorded impairment and other related charges to write down the carrying values of the Palisades and Indian Point 2 and Indian Point 3 plants and related assets to their fair value. In addition to the impairments and other related charges, Entergy has incurred severance and employee retention costs and expects to incur additional charges through 2022 relating to the decisions to shut down Vermont Yankee, Palisades, Pilgrim, Indian Point 2 and Indian Point 3, and the sale of FitzPatrick.
If Entergy concludes that any of its nuclear power plants is unlikely to operate through its planned shutdown date, which conclusion would be based on a variety of factors, such a conclusion could result in a further impairment of part or all of the carrying value of the plant. Any impairment charge taken by Entergy with respect to its long-lived assets, including the remaining power plants owned by the Entergy Wholesale Commodities business, would likely be material in the quarter that the charge is taken and could otherwise have a material effect on Entergy’s results of operations, financial condition, or liquidity. For further information regarding evaluating long-lived assets for impairment, see the “Critical Accounting Estimates - Impairment of Long-lived Assets and Trust Fund Investments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries and for further discussion of the impairment charges, see Note 14 to the financial statements.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
General BusinessProduction Cost Allocation Rider
(Entergy Arkansas has in place an APSC-approved production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of System Agreement proceedings.
Entergy Louisiana
Fuel Recovery
Entergy Louisiana’s rate schedules include a fuel adjustment clause designed to recover the cost of fuel and purchased power costs. The fuel adjustment clause contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers, including carrying charges. See Note 2 to the financial statements for a discussion of proceedings related to audits of Entergy Louisiana’s fuel adjustment clause filings.
To help stabilize electricity costs, Entergy Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Louisiana historically hedged approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity was reviewed on an annual basis. In January 2018, Entergy Louisiana filed an application with the LPSC to suspend these seasonal hedging programs and implement financial hedges with terms up to five years for a portion of its natural gas exposure, which was approved in November 2018.
Entergy Louisiana’s gas rates include a purchased gas adjustment clause based on estimated gas costs for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
Retail Rates - Gas
In accordance with the settlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of the upper end of the earnings band as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.
Other
In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and the second is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the LPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax obligation at the parent level of a consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020.
Entergy Mississippi
Fuel Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.
To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.
Formula Rate Plan
In August 2012 the MPSC opened inquiries to review whether the current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan was still appropriate or could be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan proceeding. In March 2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans. The docket remains open.
Entergy New Orleans
Fuel Recovery
Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.
Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of its natural gas hedging program consistent with the City Council’s stated policy objectives. The program uses financial instruments to hedge exposure to volatility in the wholesale price of natural gas purchased to serve Entergy New Orleans gas customers. Entergy New Orleans hedges up to 25% of actual gas sales made during the winter months.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy New Orleans’s efforts to recover storm-related costs.
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Energy Efficiency Programs
A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. The rate settlement provided an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provided a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. In January 2015 the City Council approved funding for the Energy Smart program from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In April 2017 the City Council approved an implementation plan for the Energy Smart program from April 2017 through December 2019. The City Council directed that the $11.8 million balance reported for Energy Smart funds be used to continue funding the program for Entergy New Orleans’s legacy customers and that the Energy Smart Algiers program continue to be funded through the Algiers fuel adjustment clause, until additional customer funding is required for the legacy customers. In September 2017, Entergy New Orleans filed a supplemental plan and proposed several options for an interim cost recovery mechanism necessary to recover program costs during the period between when existing funds directed to Energy Smart programs are depleted and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect. In December 2017 the City Council approved an energy efficiency cost recovery rider as an interim funding mechanism for Energy Smart, subject to verification that no additional funding sources exist. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. See Note 2 to the financial statements for discussion of Entergy New Orleans’s application with the City Council seeking approval of an implementation plan for the Energy Smart program from April 2020 through December 2022.
Entergy Texas
Fuel Recovery
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included in base rates. Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. The PUCT fuel cost proceedings are discussed in Note 2 to the financial statements.
At the PUCT’s April 2013 open meeting, the PUCT Commissioners discussed their view that a purchased power capacity rider was good public policy. The PUCT issued an order in May 2013 adopting the rule allowing for a purchased power capacity rider, subject to an offsetting adjustment for load growth. The rule, as adopted, also includes a process for obtaining pre-approval by the PUCT of purchased power agreements. Entergy Texas has not exercised the option to recover its capacity costs under the new rider mechanism, but will continue to evaluate the benefits of utilizing the new rider to recover future capacity costs.
Electric Industry Restructuring
In June 2009, a law was enacted in Texas that required Entergy Texas to cease all activities relating to Entergy Texas’s transition to competition. The law allows Entergy Texas to remain a part of the SERC Reliability Corporation (SERC) Region, although it does not prevent Entergy Texas from joining another power region. The law provides that proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding
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exist. Under the law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT’s certification of Entergy Texas’s power region.
The law also contains provisions that allow Entergy Texas to take advantage of a cost recovery mechanism that permits annual filings for the recovery of reasonable and necessary expenditures for transmission infrastructure improvement and changes in wholesale transmission charges. This mechanism was previously available to other non-ERCOT Texas utility companies, but not to Entergy Texas.
The law further amended already existing law that had required Entergy Texas to propose for PUCT approval a tariff to allow eligible customers the ability to contract for competitive generation. The amending language in the law provides, among other things, that: 1) the tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers who choose not to participate in the tariff; 2) Entergy Texas shall “purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer;” and 3) Entergy Texas shall provide and price transmission service and ancillary services under that tariff at a rate that is unbundled from its cost of service. The law directs that the PUCT may not issue an order on the tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction.
The PUCT determined that unrecovered costs that may be recovered through the rider consist only of those costs necessary to implement and administer the competitive generation program and do not include lost revenues or embedded generation costs. The amount of customer load that may be included in the competitive generation service program is limited to 115 MW.
In September 2011 the PUCT adopted a proposed rule implementing a distribution cost recovery factor to recover capital and capital-related costs related to distribution infrastructure. The distribution cost recovery factor permits utilities once per year to implement an increase or decrease in rates above or below amounts reflected in base rates to reflect depreciation expense, federal income tax and other taxes, and return on investment. The distribution cost recovery factor rider may be changed a maximum of four times between base rate cases.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery factor rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas franchises are considered to be contracts and, therefore, are terminable pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.
Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
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Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas, and holds non-exclusive franchises to provide electric service in approximately 68 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire over the period 2020-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
Property and Other Generation Resources
Owned Generating Stations
The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2020, is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Owned and Leased Capability MW(a) |
Company | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
Entergy Arkansas | | 5,175 | | | 2,091 | | | 1,817 | | | 1,194 | | | 73 | | | — | |
Entergy Louisiana | | 11,317 | | | 8,827 | | | 2,144 | | | 346 | | | — | | | — | |
Entergy Mississippi | | 3,347 | | | 2,929 | | | — | | | 416 | | | — | | | 2 | |
Entergy New Orleans | | 665 | | | 638 | | | — | | | — | | | — | | | 27 | |
Entergy Texas | | 2,260 | | | 2,005 | | | — | | | 255 | | | — | | | — | |
System Energy | | 1,256 | | | — | | | 1,256 | | | — | | | — | | | — | |
Total | | 24,020 | | | 16,490 | | | 5,217 | | | 2,211 | | | 73 | | | 29 | |
(a)“Owned and Leased Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.
Summer peak load for the Utility has averaged 21,591 MW over the previous decade.
The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 8,801 MW of new long-term resources and the deactivation of about 4,664 MW of legacy generation. As MISO market participants, the Utility operating companies also participate in MISO’s Day Ahead and Real Time Energy and Ancillary Services markets to economically dispatch generation and purchase energy to serve customers reliably and at the lowest reasonable cost.
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Other Generation Resources
RFP Procurements
The Utility operating companies from time to time issue requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies. The RFPs issued by the Utility operating companies have sought resources needed to meet near-term MISO reliability requirements as well as long-term requirements through a broad range of wholesale power products, including limited-term (1 to 3 years) and long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
•Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine J. Wayne Leonard Power Station (previously referred to as the St. Charles generating facility) at its existing Little Gypsy electric generating station. The facility began commercial operation in May 2019;
•Entergy Texas’s construction of the 993 MW, combined-cycle, gas turbine Montgomery County Power Station at its existing Lewis Creek electric generating station. The facility began commercial operation in January 2021;
•Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station site. The facility began commercial operation in March 2020;
•In October 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the facility is scheduled to be in service by early 2022;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020 and the facility is scheduled to be in service by the end of 2021;
•Entergy New Orleans received regulatory approval in August 2019 to construct the New Orleans Solar Station (a 20 MW self-build solar project) located at the NASA Michoud Facility.The facility was placed in service in December 2020;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Lee County, Arkansas. In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2022;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2023; and
•In June 2020, Entergy Texas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 1,200 acres in Liberty County near Dayton, Texas.In September 2020, Entergy Texas filed a petition with the PUCT seeking a finding that the transaction is in the public interest and requesting all necessary approvals.Closing is expected to occur by the end of 2023.
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The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:
•River Bend’s 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
•Entergy Arkansas’s wholesale base load capacity life-of-unit PPAs executed in 2003 totaling approximately 220 MW between Entergy Arkansas and Entergy Louisiana (110 MW) and between Entergy Arkansas and Entergy New Orleans (110 MW) related to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which had not been included in Entergy Arkansas’s retail rates);
•In May 2011, Entergy Texas and Calpine Energy Services, L.P. executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. Entergy Louisiana purchases 50% of the facility’s capacity and energy from Entergy Texas. In July 2014, LS Power purchased the Carville Energy Center and replaced Calpine Energy Services as the counterparty to the agreement;
•In September 2012, Entergy Gulf States Louisiana executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 MW when available, from Rain CII Carbon LLC’s petroleum coke calcining facility in Sulphur, Louisiana. The facility began commercial operation in May 2013. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with the facility;
•In March 2013, Entergy Gulf States Louisiana executed a 20-year agreement for 8.5 MW from Agrilectric Power Partners, LP’s refurbished rice hull-fueled electric generation facility located in Lake Charles, Louisiana. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with Agrilectric;
•In September 2013, Entergy Louisiana executed a 10-year agreement with TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, to purchase approximately 3 MW from its landfill gas-fueled power generation facility located in Cleveland, Texas;
•Entergy Mississippi’s cost-based purchase, beginning in January 2013, of 90 MW from Entergy Arkansas’s share of Grand Gulf (only 60 MW of this PPA came through the RFP process). Cost recovery for the 90 MW was approved by the MPSC in January 2013;
•In April 2015, Entergy Arkansas and Stuttgart Solar, LLC executed a 20-year agreement for 81 MW from a solar photovoltaic electric generation facility located near Stuttgart, Arkansas. The APSC approved the project and deliveries pursuant to that agreement commenced in June 2018;
•In November 2016, Entergy Louisiana and LS Power executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. The transaction received regulatory approval and will begin in June 2022;
•In November 2016, Entergy Louisiana and Occidental Chemical Corporation executed a 10-year agreement for 500 MW from the Taft Cogeneration facility located in Hahnville, Louisiana. The transaction received regulatory approval and began in June 2018;
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
•In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021;
•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a five-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
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•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021; and
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a solar photovoltaic electric generating facility located in Polk County, Texas.The PPA is expected to start when the facility reaches commercial operation in 2023.
In April 2020, Entergy Services, on behalf of Entergy Texas, issued an RFP for combined-cycle gas turbine capacity and energy resources. The RFP was seeking up to 1,000 MW - 1,200 MW of capacity, capacity-related benefits, energy, other electric products, and environmental attributes, if any, from a single generation resource located in the “Eastern Region” of Entergy Texas’s service area. In December 2020, Entergy Texas posted notice that it has elected to proceed with the self-build alternative, Orange County Power Station. The self-build alternative will be conditioned on receipt of required internal and regulatory approvals.
In June 2020, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic resources. The RFP was seeking 300 MW of energy, capacity, capacity-related benefits, other electric products, and environmental attributes from eligible new-build solar photovoltaic generation resources. In December 2020, Entergy Louisiana concluded evaluations of the RFP. Three proposals have been placed on the primary selection list and two proposals have been placed on the secondary selection list. Negotiations are currently in progress.
In January 2021, Entergy Texas provided notice that it intends to issue an RFP for solar generation resources. The RFP is seeking a minimum of 200 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Texas customers.
Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process, including Entergy Mississippi’s January 2006 acquisition of the 480 MW, combined-cycle, gas-fired Attala power plant; Entergy Gulf States Louisiana’s March 2008 acquisition of the 322 MW, simple-cycle, gas-fired Calcasieu Generating Facility; Entergy Louisiana’s April 2011 acquisition of the 580 MW, combined-cycle, gas-fired Acadia Energy Center Unit 2; Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) March 2016 acquisitions of the 1,980 MW (summer rating), natural gas-fired, combined-cycle gas turbine Union Power Station power blocks, each rated at 495 MW (summer rating); and Entergy Mississippi’s October 2019 acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The Utility operating companies have also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.
The Washington Parish Energy Center is a 361 MW natural gas-fired peaking power plant approximately 60 miles north of New Orleans on a site Entergy Louisiana purchased from Calpine in 2019. In May 2018, Entergy Louisiana received LPSC approval of its certification application for this simple-cycle power plant to be developed pursuant to an agreement between Calpine and Entergy Louisiana. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020.
The Hardin County Peaking Facility is an existing 147 MW simple-cycle gas-fired peaking power plant in Kountze, Texas, owned by East Texas Electric Cooperative. Entergy Texas is currently seeking regulatory certification to move forward with the purchase of the facility. The facility has been in operation since January 2010.
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Power Through Program
In December 2020, Entergy Texas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation that is to be installed at commercial and industrial customer premises. If approved, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.”
Interconnections
The Utility operating companies’ generating units are interconnected to a transmission system operating at various voltages up to 500 kV. These generating units consist of steam-electric production facilities, combustion-turbine generators, pressurized and boiling water nuclear reactors, and inverter-based technologies operating in the MISO energy and ancillary services market. Entergy’s Utility operating companies are MISO market participants and are interconnected with many neighboring utilities. MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. As a Regional Transmission Organization, MISO assures consumers of unbiased regional grid management and open access to the transmission facilities under MISO’s functional supervision. In addition, the Utility operating companies are members of SERC Reliability Corporation (SERC). SERC is a nonprofit corporation responsible for promoting and improving the reliability, adequacy, and critical infrastructure of the bulk power supply systems in all or portions of 16 central and southeastern states.SERC serves as a regional entity with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing Bulk Electric System reliability standards within the SERC Region.
Gas Property
As of December 31, 2020, Entergy New Orleans distributed and transported natural gas for distribution within New Orleans, Louisiana, through approximately 2,600 miles of gas pipeline. As of December 31, 2020, the gas properties of Entergy Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Louisiana’s financial position.
Title
The Utility operating companies’ generating stations are generally located on properties owned in fee simple. Most of the substations and transmission and distribution lines are constructed on private property or public rights-of-way pursuant to easements, servitudes, or appropriate franchises. Some substation properties are owned in fee simple. The Utility operating companies generally have the right of eminent domain, whereby they may perfect title to, or secure easements or servitudes on, private property for their utility operations.
Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are subject to the liens of mortgages securing bonds issued by those companies. The Lewis Creek generating station of Entergy Texas was acquired by merger with a subsidiary of Entergy Texas and is currently not subject to the lien of the Entergy Texas indenture.
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Fuel Supply
The sources of generation and average fuel cost per kWh for the Utility operating companies and System Energy for the years 2018-2020 were:
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| | Natural Gas | | Nuclear | | Coal | | Purchased Power | | MISO Purchases |
Year | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh |
2020 | | 47 | | | 1.92 | | | 29 | | | 0.57 | | | 3 | | | 2.54 | | | 8 | | | 4.36 | | | 13 | | | 2.48 | |
2019 | | 40 | | | 2.33 | | | 28 | | | 0.73 | | | 6 | | | 2.31 | | | 8 | | | 4.86 | | | 18 | | | 2.71 | |
2018 | | 39 | | | 2.84 | | | 27 | | | 0.84 | | | 9 | | | 2.24 | | | 8 | | | 5.23 | | | 17 | | | 3.71 | |
Actual 2020 and projected 2021 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:
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| Natural Gas | | Nuclear | | Coal | | Purchased Power (d) | | MISO Purchases (e) |
| 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 |
Entergy Arkansas (a) | 24 | % | | 35 | % | | 60 | % | | 51 | % | | 10 | % | | 13 | % | | 1 | % | | 1 | % | | 5 | % | | — | |
Entergy Louisiana | 51 | % | | 59 | % | | 26 | % | | 27 | % | | 1 | % | | 2 | % | | 9 | % | | 12 | % | | 13 | % | | — | |
Entergy Mississippi (b) | 73 | % | | 69 | % | | 14 | % | | 22 | % | | 4 | % | | 9 | % | | — | | | — | | | 9 | % | | — | |
Entergy New Orleans (b) | 55 | % | | 56 | % | | 33 | % | | 40 | % | | 1 | % | | 2 | % | | 2 | % | | 2 | % | | 9 | % | | — | |
Entergy Texas | 39 | % | | 60 | % | | 11 | % | | 13 | % | | 2 | % | | 6 | % | | 23 | % | | 21 | % | | 25 | % | | — | |
System Energy (c) | — | | | — | | | 100 | % | | 100 | % | | — | | | — | | | — | | | — | | | — | | | — | |
Utility (a) (b) | 47 | % | | 55 | % | | 29 | % | | 31 | % | | 3 | % | | 6 | % | | 8 | % | | 8 | % | | 13 | % | | — | |
(a)Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2020 and is expected to provide less than 1% of its generation in 2021.
(b)Solar power provided less than 1% of Entergy Mississippi’s and Entergy New Orleans's generation in 2020 and is expected to provide less than 1% of each of Entergy Mississippi’s and Entergy New Orleans's generation in 2021.
(c)Capacity and energy from System Energy’s interest in Grand Gulf is allocated as follows under the Unit Power Sales Agreement: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%. Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.
(d)Excludes MISO purchases.
(e)In December 2013, Entergy integrated its transmission system into the MISO RTO. Entergy offers all of its generation into the MISO energy market on a day-ahead and real-time basis and bids for power in the MISO energy market to serve the demand of its customers, with MISO making dispatch decisions. The MISO purchases metric provided for 2020 is not projected for 2021.
Some of the Utility’s gas-fired plants are also capable of using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in 2021, it is possible that various operational events including weather or pipeline maintenance may require the use of fuel oil.
Natural Gas
The Utility operating companies have long-term firm and short-term interruptible gas contracts for both supply and transportation. Over 50% of the Utility operating companies’ power plants maintain some level of long-
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term firm transportation. Short-term contracts and spot-market purchases satisfy additional gas requirements. Entergy Texas owns a gas storage facility that provides reliable and flexible natural gas service to certain generating stations.
Many factors, including wellhead deliverability, storage, pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
Coal
Entergy Arkansas has committed to seven one- to three-year contracts that will supply approximately 85% of the total coal supply needs in 2021. These contracts are staggered in term so that not all contracts have to be renewed the same year. The remaining 15% of total coal requirements will be satisfied by contracts with a term of less than one year. Based on continued improved Powder River Basin (PRB) coal deliveries by rail and the high cost of alternate sources and modes of transportation, no alternative coal consumption is expected at Entergy Arkansas during 2021. Coal will be transported to Arkansas via an existing transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2021.
Entergy Louisiana has committed to five one- to three-year contracts that will supply approximately 90% of Nelson Unit 6 coal needs in 2021. If needed, additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as for Entergy Arkansas’s plants, no alternative coal consumption is expected at Nelson Unit 6 during 2021. Coal will be transported to Nelson primarily via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2021.
For the year 2020, coal transportation delivery rates to Entergy Arkansas-and Entergy Louisiana-operated coal-fired units were adequate to meet supply needs and obligations, and it is expected that delivery times in 2021 will continue to be consistent. Both Entergy Arkansas and Entergy Louisiana control a sufficient number of railcars to satisfy the rail transportation requirement.
The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2021. Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.
Nuclear Fuel
The nuclear fuel cycle consists of the following:
•mining and milling of uranium ore to produce a concentrate;
•conversion of the concentrate to uranium hexafluoride gas;
•enrichment of the uranium hexafluoride gas;
•fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and
•disposal of spent fuel.
The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated
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uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the owner of a nuclear power plant.
Based upon currently planned fuel cycles, the Utility nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through most of 2023. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. There are a number of possible supply alternatives that may be accessed to mitigate any supplier performance failure, including potentially drawing upon Entergy’s inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.
The effects of market price changes may be reduced and deferred by risk management strategies, such as negotiation of floor and ceiling amounts for long-term contracts, buying for inventory or entering into forward physical contracts at fixed prices when Entergy believes it is appropriate and useful. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance reliability of conversion, enrichment, and fabrication services providers. There are fewer of these providers than for uranium. For conversion and enrichment services, like uranium, Entergy diversifies its supply by supplier and country and may take special measures as needed to ensure supply of enriched uranium for the reliable fabrication of nuclear fuel. For fabrication services, each plant is dependent upon the effective performance of the fabricator of that plant’s nuclear fuel, therefore, Entergy provides additional monitoring, inspection, and oversight for the fabrication process to assure reliability and quality.
Entergy Arkansas, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the financial statements of Entergy and the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These credit facilities are subject to periodic renewal, and the notes are issued periodically, typically for terms between three and seven years.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with one interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with CenterPoint Energy Services which guarantees Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The CenterPoint Energy Service gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans also makes interruptible spot market purchases.
Entergy Louisiana purchased natural gas for resale in 2020 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.
Federal Regulation of the Utility
State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.
System Agreement (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Prior to each operating company’s termination of participation in the System Agreement (Entergy Arkansas in December 2013, Entergy Mississippi in November 2015, and Entergy Louisiana, Entergy New Orleans, and Entergy Texas each in August 2016), the Utility operating companies dependengaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which was a rate schedule approved by the FERC. Under the terms of the System Agreement, generating capacity and other power resources were jointly operated by the Utility operating companies that were participating in the System Agreement. The System Agreement provided, among other things, that parties having generating reserves greater than their allocated share of reserves (long companies) would receive payments from those parties having generating reserves that were less than their allocated share of reserves (short companies). Such payments were at amounts sufficient to cover certain of the long companies’ costs for intermediate and peaking oil/gas-fired generation, including operating expenses, fixed charges on accessdebt, dividend requirements on preferred equity, and a fair rate of return on common equity investment. Under the System Agreement, the rates used to compensate long companies were based on costs associated with the capital markets and, at times, may face potential liquidity constraints, which could make it more difficult to handle future contingencies such as natural disasterslong companies’ steam electric generating units fueled by oil or substantial increases in gas and fuel prices. Disruptions inhaving an annual average heat rate above 10,000 Btu/kWh. In addition, for all energy exchanged among the capital and credit markets may adversely affect Entergy’s and its subsidiaries’ abilityUtility operating companies under the System Agreement, the companies purchasing exchange energy were required to meet liquidity needs, access capital and operate and grow their businesses, andpay the cost of capital.fuel consumed in generating such energy plus a charge to cover other associated costs.
Entergy’s business is capital intensive and dependent upon its ability to access capital at reasonable rates and other terms. At times there are also spikes inAlthough the price for natural gas and other commodities that increase the liquidity requirementsSystem Agreement has terminated, certain of the Utility operating companiescompanies’ and Entergy Wholesale Commodities. their retail regulators are pursuing litigation involving the System Agreement at the FERC and in federal courts. The proceedings include challenges to the allocation of costs as defined by the System Agreement and other matters. See Note 2 to the financial statements for discussion of legal proceedings at the FERC and in federal courts involving the System Agreement.
Transmission and MISO Markets
In addition, Entergy’s and the Utility operating companies’ liquidity needs could significantly increase in the event of a hurricane or other weather-related or unforeseen disaster similar to that experienced in Entergy’s service territory with Hurricane Katrina and Hurricane Rita in 2005, Hurricane Gustav and Hurricane Ike in 2008, and Hurricane Isaac in 2012. The occurrence of one or more contingencies, including a delay in regulatory recovery of fuel or purchased power costs or storm restoration costs, higher than expected pension contributions, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, or other unknown events, could cause the financing needs of Entergy and its subsidiaries to increase. In addition, accessing the debt capital markets more frequently in these situations may result in an increase in leverage. Material leverage increases could negatively affect the credit ratings of Entergy andDecember 2013 the Utility operating companies which in turn could negativelyintegrated into the MISO RTO. Although becoming a member of MISO did not affect access to the capital markets.
The inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses. Events beyond Entergy’s control may create uncertainty that could increase its cost of capital or impair its ability to access the capital markets, including the ability to draw on its bank credit facilities. Entergy and its subsidiaries are unable to predict the degree of success they will have in renewing or replacing their credit facilities as they come up for renewal. Moreover, the size, terms, and covenants of any new credit facilities may not be comparable to, and may be more restrictive than, existing facilities. If Entergy and its subsidiaries are unable to access the credit and capital markets on terms that are reasonable, they may have to delay raising capital, issue shorter-term securities and/or bear an unfavorable cost of capital, which, in turn, could impact their ability to grow their businesses, decrease earnings, significantly reduce financial flexibility and/or limit Entergy Corporation’s ability to sustain its current common stock dividend level.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
A downgrade in Entergy Corporation’s or its subsidiaries’ credit ratings could negatively affect Entergy Corporation’s and its subsidiaries’ ability to access capital and/or could require Entergy Corporation or its subsidiaries to post collateral, accelerate certain payments, or repay certain indebtedness.
There are a number of factors that rating agencies evaluate to arrive at credit ratings for each of Entergy Corporation and the Registrant Subsidiaries, including each Registrant’s regulatory framework, ability to recover costs and earn returns, diversification and financial strength and liquidity. If one or more rating agencies downgrade Entergy Corporation’s, any ofownership by the Utility operating companies’,companies of their transmission facilities or System Energy’s ratings, particularly below investment grade, borrowing costs would increase, the potential poolresponsibility for maintaining those facilities, MISO maintains functional control over the combined transmission systems of investorsits members and funding sources would likely decrease,administers wholesale energy and cash or letterancillary services markets for market participants in the MISO region, including the Utility operating companies. MISO also exercises functional control of credit collateral demands may be triggered bytransmission planning and congestion management and provides schedules and pricing for the termscommitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the markets. The Utility operating companies sell capacity, energy, and ancillary services on a numberbilateral basis to certain wholesale customers and offer available electricity production of commodity contracts, leases,their generating facilities into the MISO day-ahead and other agreements.
real-time energy markets pursuant to the MISO tariff and market rules. Each Utility operating company has its own transmission pricing zone and a formula rate template (included as Attachment O to the MISO tariff) used to
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establish transmission rates within MISO. The terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets and the allocation of transmission upgrade costs, are subject to regulation by the FERC.
Most
System Energy and Related Agreements
System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In July 2001 a rate proceeding commenced by System Energy at the FERC in 1995 became final, with the FERC approving a prospective 10.94% return on equity. In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of Entergy Corporation’s and its subsidiaries’ large customers, suppliers, and counterparties require sufficient creditworthiness to enter into transactions. If Entergy Corporation’s or its subsidiaries’ ratings decline, particularly below investment grade, or if certain counterparties believe Entergy Corporation or the Utility operating companies are losing creditworthiness and demand adequate assurance under fuel, gas, andtheir Grand Gulf purchased power contracts, the counterparties may require postingobligations. Entergy Arkansas’s and Entergy Mississippi’s acceleration of collateral in cash or letters of credit, prepayment for fuel, gas orGrand Gulf purchased power or accelerated payment, or counterparties may decline business with Entergy Corporation or its subsidiaries. At December 31, 2017, based on power prices at that time, Entergy had liquidity exposure of $167 million under the guarantees in place supporting Entergy Wholesale Commodities transactionsobligations ceased effective July 2001 and $8 million of posted cash collateral. In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power pricesJuly 2003, respectively, as of December 31, 2017, Entergy would have been required to provide approximately $98 million of additional cash or letters of credit under some of the agreements. In the event of a decrease in the credit ratings of Entergy’s Utility operating companies to below investment grade, those companies collectively could be required to provide up to $50 million of additional cash or letters of credit to MISO. As of December 31, 2017, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously received collateral from counterparties, would increase by $372 million for a $1 per MMBtu increase in gas prices in both the short- and long-term markets.
Recent U.S. tax legislation may materially adversely affect Entergy’s financial condition, results of operations, cash flows, and credit ratings.
The recently enacted H.R. 1, also known as the Tax Cuts and Jobs Act of 2017, will significantly change the U.S. Internal Revenue Code, including taxation of U.S. corporations, by, among other things, reducing the federal corporate income tax rate, limiting interest deductions, and altering the expensing of capital expenditures. The legislation is unclear in certain respects and will require interpretations and implementing regulationsapproved by the IRS, as well as state tax authorities, and the legislation could be subject to potential amendments and technical corrections, any of which could lessen or increase certain impacts of the legislation. In addition, the regulatory treatment of the impacts of this legislation, particularly on companies like Entergy and the Registrant Subsidiaries, will be subject to the discretion of federal, state, and local public utility regulators.
As further described inFERC. See Note 32 to the financial statements for discussion of complaints filed with the FERC regarding System Energy’s return on equity.
Unit Power Sales Agreement
The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy recordedArkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a reductionfull cost-of-service basis regardless of certainthe quantity of energy delivered. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.
In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its net deferred income tax assets (including36% share of Grand Gulf-related costs and recovers the valueremaining 78% of its net operating loss carryforwards) and regulatory liabilities, resultingshare in rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a charge against earnings in the fourth quarter 2017 of $526 million, including a $34 million net-of-tax reduction of regulatory liabilities,price equal to its avoided cost, which is currently less than Entergy Arkansas’s cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans that sell a portion of the output of Entergy Arkansas’s retained share of Grand Gulf to those companies, with the remainder of the retained share being sold to Entergy Mississippi through a separate life-of-resources purchased power agreement. In a series of LPSC orders, court decisions, and the Utility operating companies recorded a reductionagreements from late 1985 to mid-1988, Entergy Louisiana was granted rate relief with respect to costs associated with Entergy Louisiana’s share of approximately $3.7 billion on a consolidated basis incapacity and energy from Grand Gulf, subject to certain terms and conditions. Entergy Louisiana retains and does not recover from retail ratepayers 18% of its net deferred tax liabilities and a corresponding increase in net regulatory liabilities. Depending on the outcome14% share of the ratemaking process, IRS examinations, or tax positionscosts of Grand Gulf capacity and elections thatenergy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause at 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may elect,sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC’s approval. Entergy and the Registrant Subsidiaries may be requiredArkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to record additional charges or credits to income tax expense. Further, the amount and timingsell a portion of the returnoutput of Entergy Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted rate relief for those purchases by the deferred taxes to customers is dependent upon the regulatory treatment received, and, if the Registrant Subsidiaries are unsuccessful in receiving balanced regulatory treatment, Entergy’s or the Utility operating companies’ cash flow could be materially adversely affected. Further, there may be other material effects resulting from the legislation that have not been identified. While Entergy plans to financeMPSC through its cash needs that result from the Act through a combination of Registrant Subsidiary debtannual unit power cost rate mechanism.
Availability Agreement
The Availability Agreement among System Energy and Entergy Corporation debtArkansas, Entergy Louisiana, Entergy Mississippi, and equity, there can be no assurance that Entergy orNew Orleans was entered into in 1974 in connection with the Registrant Subsidiaries will obtain debt or equity financing on terms that are satisfactory or consistent with their current expectations.
In addition, while Moody’s changed the ratings outlooks for Entergy Corporation to negative from stable in reaction to the legislation, it is unclear when or how capital markets, other credit rating agencies, the FERC or state or local regulators may respond to this legislation. Entergy expects that certain financial metrics used by credit rating agencies will be negatively affected as a result of the return of excess deferred taxes to customers, increased debt, and the decrease in the Registrant Subsidiaries’ revenue requirements, and related decrease in operating cash flows, expected as a consequence of the lower federal corporate income tax rate while, at the same time, the loss of the bonus depreciation tax deduction will increase taxable income in the future. Also, the timing of the return of excess deferred income taxes
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of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to customers willpay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges.
The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.
System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for its two outstanding series of first mortgage bonds. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not exactly matchbe allowed to repay these subordinated advances so long as it remained in default under the lower taxesrelated indebtedness or in other similar circumstances.
Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be paying which will result in cash outflows to customers. It is also uncertain how other credit rating agencies will treat the impacts of this legislation on their credit ratings and metrics, and whether additional avenues will evolve for companies to manage the adverse aspects of this legislation. These avenues,made directly to the extent availableholders of indebtedness that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.
The obligations of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and if successfully applied, could lessenEntergy New Orleans to make payments under the impacts on certain credit metrics, although there canAvailability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to the FERC for approval with respect to the terms of such sale. No such filing with the FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability Agreement, the jurisdictional portions of the Availability Agreement would be submitted to the FERC for approval.
Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement and, therefore, no assurance in this regard.
Entergy believes that interpretations and implementing regulations bypayments under the IRS, as well as potential amendments and technical corrections, could result in lessening the impacts of certain aspects of this legislation.Availability Agreement have ever been required. If Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to successfully pursue avenues to manage the effects of the new tax legislation, or if additional interpretations, regulations, amendments, or technical corrections exacerbate the effects of the legislation, the legislationobtain funds from other sources, Entergy Louisiana and Entergy New Orleans could have a material effect on Entergy’s results of operations, financial condition, and cash flows, and could result in additional credit rating agency actions. Any such actions by credit rating agencies may make it more difficult and costly for Entergy to issue debt securities and certain other types of financing and could increase borrowing costs under its credit facilities.
For further information regarding the effects of the Act, see the “Income Tax Legislation” section of Management’s Financial Discussion and Analysis for Entergy. Also, Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses proceedings commenced or other responses by Entergy’s regulators to the Act.
Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s, the Utility operating companies’, and System Energy’s results of operations, financial condition and liquidity.
Entergy and its subsidiaries make judgments regarding the potential tax effects of various transactions and results of operations to estimate their obligations to taxing authorities. These tax obligations include income, franchise, real estate, sales and use, and employment-related taxes. These judgments include provisions for potential adverse outcomes regarding tax positions that have been taken. Entergy and its subsidiaries also estimate their ability to utilize tax benefits, including those in the form of carryforwards for which the benefits have already been reflected in the financial statements. Changes in federal, state, or local tax laws, adverse tax audit results or adverse tax rulings on positions taken by Entergy and its subsidiaries could negatively affect Entergy’s, the Utility operating companies’, and System Energy’s results of operations, financial condition, and liquidity. For further information regarding Entergy’s income taxes, see Note 3 to the financial statements.
Entergy and its subsidiaries’ ability to successfully complete strategic transactions, including merger, acquisition, divestiture, joint venture, restructuring or other strategic transactions, is subject to significant risks, including the risk that required regulatory or governmental approvals may not be obtained, risks relating to unknown or undisclosed problems or liabilities, and the risk that for these or other reasons, Entergy and its subsidiaries may be unable to achieve some or all of the benefits that they anticipate from such transactions.
From time to time, Entergy and its subsidiaries have pursued and may continue to pursue strategic transactions including merger, acquisition, divestiture, joint venture, restructuring or other strategic transactions. For example, in November 2016, Entergy announced that it had entered into a purchase and sale agreement with NorthStar for the sale of 100% of the membership interests in Entergy Nuclear Vermont Yankee, which owns the Vermont Yankee plant. In addition, as part of Entergy’s plan to exit the merchant power business, it plans to shut down its remaining merchant nuclear power plants by mid-2022. These transactions and plans are or may become subject to regulatory approvalclaims or demands by System Energy or its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their Availability Agreement obligations exceed their Unit Power Sales Agreement obligations.
The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other material conditions or contingencies. The failure to complete these transactions or plans or any future strategic transaction successfully or on a timely basis could have an adverse effect on Entergy’s financial condition, results of operations and the market’s perception of Entergy’s ability to execute its strategy. Further, these transactions, and any completed or future strategic transactions, involve substantial risks, including the following:
creditors.
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the disposition of a business or asset may involve continued financial involvement in the divested business, such as through continuing equity ownership, transition service agreements, guarantees, indemnities, or other current or contingent financial obligations;Service Companies
Entergy may encounter difficulty in finding buyers or executing alternative exit strategies on acceptable terms inServices, a timely manner when it decideslimited liability company wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to sell an asset or a business, which could delay the accomplishment of its strategic objectives. Alternatively, Entergy may dispose of a business or asset at a price or on terms that are less than what it had anticipated, or with the exclusion of assets that must be divested or run off separately;
the disposition of a business could result in impairments and related write-offs of the carrying values of the relevant assets;
acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;
acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate;
Entergy and/or its subsidiaries may assume liabilities that were not disclosed to them, that exceed their estimates, or for which their rights to indemnification from the seller are limited;
the disposition of a business, including Entergy’s planned exit from the merchant power business, could divert management’s attention from other business concerns;
Entergy and/or its subsidiaries may be unable to obtain the necessary regulatory or governmental approvals to close a transaction, such approvals may be granted subject to terms that are unacceptable to them, or Entergy or its subsidiaries otherwise may be unable to achieve anticipated regulatory treatment of any such transaction or acquired business or assets; and
Entergy or its subsidiaries otherwise may be unable to achieve the full strategic and financial benefits that they anticipate from the transaction, or such benefits may be delayed or may not occur at all.
Entergy may not be successful in managing these or any other significant risks that it may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material effect on its business.
The construction of, and capital improvements to, power generation facilities involve substantial risks. Should construction or capital improvement efforts be unsuccessful, the financial condition, results of operations, or liquidity of Entergy and the Utility operating companies, could be materially affected.
Entergy’sbut also provides services to Entergy Wholesale Commodities. Entergy Operations is also wholly-owned by Entergy Corporation and the Utility operating companies’ ability to complete construction of power generation facilities, or make other capital improvements, in a timely mannerprovides nuclear management, operations and within budget is contingent upon many variablesmaintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to substantial risks. These variables include, but are not limitedthe owner oversight of Entergy Arkansas, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to project management expertise and escalating costs for materials, labor, and environmental compliance. Delays in obtaining permits, shortages in materials and qualified labor, suppliers and contractors not performing as required under their contracts, changes in the scope and timing of projects, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in law or regulation, including environmental compliance requirements, and other events beyond the control of the Utility operating companies orand System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas
Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson Unit 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Wholesale Commodities business may occur that may materially affectGulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.
Entergy Texas purchases from Entergy Louisiana pursuant to a life-of-unit purchased power agreement a 42.5% share of capacity and energy from the schedule, cost, and performance70% of these projects. If these projects or other capital improvements are significantly delayed or becomeRiver Bend subject to cost overruns or cancellation,retail regulation. Entergy Texas was allocated a share of River Bend’s nuclear and environmental liabilities that is identical to the Utility operating companies could incur additional costs and termination payments, or face increased risk of potential write-offshare of the investment inplant’s output purchased by Entergy Texas under the project.purchased power agreement. In addition, the Utility operating companies could be exposed to higher costs and market volatility, which could affect cash flow and cost recovery, should their respective regulators decline to approve the construction of new generation needed to meet the reliability needs of customers at the lowest reasonable cost.
For further information regarding capital expenditure plans and other uses of capital in connection with the potential constructiontermination of additional generation supply sources within the Utility operating companies’ service territory, and asSystem Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the Entergy Wholesale Commodities business, see the “Capital Expenditure Plans and Other Uses of Capital” section of Management’s Financial Discussion and Analysisfinancial statements for Entergy and eachadditional discussion of the Registrant Subsidiaries.purchased power agreements.
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
On October 1, 2015, the businesses formerly conducted by Entergy Louisiana (Old Entergy Louisiana) and Entergy Gulf States Louisiana (Old Entergy Gulf States Louisiana) were combined into a single public utility. In order to effect the business combination, under the Texas Business Organizations Code (TXBOC), Old Entergy Louisiana allocated substantially all of its assets to a new subsidiary, Entergy Louisiana Power, LLC, a Texas limited liability company (New Entergy Louisiana), and New Entergy Louisiana assumed the liabilities of Old Entergy Louisiana, in a transaction regarded as a merger under the TXBOC. Under the TXBOC, Old Entergy Gulf States Louisiana allocated substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States Louisiana assumed the liabilities of Old Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. New Entergy Gulf States Louisiana then merged into New Entergy Louisiana with New Entergy Louisiana surviving the merger. Thereupon, Old Entergy Louisiana changed its name from “Entergy Louisiana, LLC” to “EL Investment Company, LLC” and New Entergy Louisiana changed its name from “Entergy Louisiana Power, LLC” to “Entergy Louisiana, LLC” (Entergy Louisiana). With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Old Entergy Louisiana and Old Entergy Gulf States Louisiana.
Part I Item 1A & 1B1
Entergy Corporation, Utility operating companies, and System Energy
The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs to fulfill their obligations related to environmental and other matters.
The businesses in which the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business operate are subject to extensive environmental regulation by local, state, and federal authorities. These laws and regulations affect the manner in which the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business conduct their operations and make capital expenditures. These laws and regulations also affect how the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business manage air emissions, discharges to water, wetlands impacts, solid and hazardous waste storage and disposal, cooling and service water intake, the protection of threatened and endangered species, certain migratory birds and eagles, hazardous materials transportation, and similar matters. Federal, state, and local authorities continually revise these laws and regulations, and the laws and regulations are subject to judicial interpretation and to the permitting and enforcement discretion vested in the implementing agencies. Developing and implementing plans for facility compliance with these requirements can lead to capital, personnel, and operation and maintenance expenditures. Violations of these requirements can subject the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. In addition, the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business potentially are subject to liability under these laws for the costs of remediation of environmental contamination of property now or formerly owned or operated by the Utility operating companies, System Energy, and Entergy Wholesale Commodities and of property contaminated by hazardous substances they generate. The Utility operating companies are currently involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future. The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business have incurred and expect to incur significant costs related to environmental compliance.
Emissions of nitrogen and sulfur oxides, mercury, particulates, greenhouse gases, and other regulated air emissions from generating plants are potentially subject to increased regulation, controls and mitigation expenses. In addition, existing air regulations and programs promulgated by the EPA often are challenged legally, sometimes resulting in large-scale changes to anticipated regulatory regimes and the resulting need to shift course, both operationally and economically, depending on the nature of the changes. Risks relating to global climate change, initiatives to compel greenhouse gas emission reductions, and water availability issues are discussed below.
Entergy and its subsidiaries may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if Entergy and its subsidiaries fail to obtain, maintain, or comply with any such approval, the operation of its facilities could be stopped or become subject to additional costs. For further information regarding environmental regulation and environmental matters, see the “Regulation of Entergy’s Business– Environmental Regulation” section of Part I, Item 1.
The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs related to reliability standards.
Entergy’s business is subject to extensive and mandatory reliability standards. Such standards, which are established by the North American Electric Reliability Corporation (NERC), the SERC Reliability Corporation (SERC), and other regional enforcement entities, are approved by the FERC and frequently are reviewed, amended, and supplemented. Failure to comply with such standards could result in the imposition of fines or civil penalties, and potential exposure to third party claims for alleged violations of such standards. The standards, as well as the laws and regulations that govern them, are subject to judicial interpretation and to the enforcement discretion vested in the implementing agencies. In addition to exposure to civil penalties and fines, the Utility operating companies have incurred and expect to incur significant costs related to compliance with new and existing reliability standards, including costs associated with the Utility operating companies’ transmission system and generation assets. The changes to the
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
reliability standards applicable to the electric power industry are ongoing, and Entergy cannot predict the ultimate effect that the reliability standards will have on its Utility and Entergy Wholesale Commodities.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans Internal Restructuring
In November 2017, pursuant to the agreement in principle, Entergy New Orleans, Inc. undertook a multi-step restructuring, including the following:
•Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.
•Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans, Inc. allocated substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy Texas)
The effects of weather and economic conditions, and the related impact on electricity and gas usage, may materially affect the Utility operating companies’ results of operations.
Temperatures above normal levels in the summer tend to increase electric cooling demand and revenues, and temperatures below normal levels in the winter tend to increase electric and gas heating demand and revenues. As a corollary, moderate temperatures in either season tend to decrease usage of energy and resulting revenues. Seasonal pricing differentials, coupled with higher consumption levels, typically cause the Utility operating companies to report higher revenues in the third quarterNew Orleans Power assumed substantially all of the fiscal year thanliabilities of Entergy New Orleans, Inc. in a transaction regarded as a merger under the other quarters. Extreme weather conditions or storms, however, may stressTXBOC. Entergy New Orleans, Inc. remained in existence and held the membership interests in Entergy New Orleans Power.
•Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility operating companies’ generation facilitiesHolding Company, LLC, a Texas limited liability company and transmission and distribution systems, resulting in increased maintenance and capital costs (and potential increased financing needs), limits on their ability to meet peak customer demand, increased regulatory oversight, and lower customer satisfaction. These extreme conditions could have a material effect on the Utility operating companies’ financial condition, resultssubsidiary of operations, and liquidity.
Entergy’s electricity sales volumes are affected by a number of factors, including economic conditions, weather, customer bill sizes (large bills tend to induce conservation), trends in energy efficiency, new technologies and self-generation alternatives, including the willingness and ability of large industrial customers to develop co-generation facilities that greatly reduce their demand from Entergy. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and rarely have a long-lasting effect on Entergy’s operating results. Others, such as the increasing adoption of energy efficient appliances, new building codes, distributed energy resources, energy storage, demand side management and new technologies such as rooftop solar are having a more permanent effect of reducing sales growth rates from historical norms.Entergy Corporation). As a result of these emerging efficiencies and technologies, the Utility operating companies may experience lower usage per customer in the residential and commercial classes, and further advances have the potential to limit sales growth in the future. Electricity sales to industrial customers, in particular, benefit from steady economic growth and favorable commodity prices; however, they are sensitive to changes in conditions in the markets in which its customers operate. Any negative change in any of these or other factors has the potential to result in slower sales growth or sales declines and increased bad debt expense, which could materially affect Entergy’s and the Utility operating companies’ results of operations, financial condition, and liquidity.
The effects of climate change and environmental and regulatory obligations intended to compel greenhouse gas emission reductions or to placecontribution, Entergy New Orleans Power is a price on greenhouse gas emissions could materially affect the financial condition, results of operations, and liquiditywholly-owned subsidiary of Entergy the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business.Holding Company, LLC.
In an effort to address climate change concerns, federal, state, and local authorities are calling for additional laws and regulations aimed at known or suspected causes of climate change. For example, in response to the United States Supreme Court’s 2007 decision holding that the EPA has authority to regulate emissions of CO2 and other “greenhouse gases” under the Clean Air Act, the EPA, various environmental interest groups, and other organizations are focusing considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. In 2010, the EPA promulgated its first regulations controlling greenhouse gas emissions from certain vehicles and from new and significantly modified stationary sources of emissions, including electric generating units. During 2012 and 2014, the EPA proposed CO2 emission standards for new and existing sources. The EPA finalized these standards in 2015; however, in late 2017, the EPA proposed to repeal the regulations and issued an Advanced Notice of Proposed Rulemaking for replacing certain aspects of the standards for existing sources. As examples of state action, in the Northeast, the Regional Greenhouse Gas Initiative establishes a cap on CO2 emissions from electric power plants and requires generators to purchase emission permits to cover their CO2 emissions, and a similar program has been
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
developed in California. The impact that recent changes in the federal government will have on existing and pending environmental laws and regulations related to greenhouse gas emissions is currently unclear.
Developing and implementing plans for compliance with greenhouse gas emissions reduction requirements can lead to additional capital, personnel, and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects; moreover, long-term planning to meet environmental requirements can be negatively impacted and costs may increase to the extent laws and regulations change prior to full implementation. These requirements could, in turn, lead to changes in the planning or operations of balancing authorities or organized markets in areas where the Utility operating companies, System Energy, or Entergy Wholesale Commodities do business. Violations of such requirements may subject Entergy Wholesale Commodities and the Utility operating companies to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. To the extent Entergy believes any of these costs are recoverable in rates, however, additional material rate increases for customers could be resisted by Entergy’s regulators and, in extreme cases, Entergy’s regulators might deny or defer timely recovery of these costs. Future changes in environmental regulation governing the emission of CO2 and other greenhouse gases could make some of Entergy’s electric generating units uneconomical to maintain or operate, and could increase the difficulty that Entergy and its subsidiaries have with obtaining or maintaining required environmental regulatory approvals, which could also materially affect the financial condition, results of operations and liquidity of Entergy and its subsidiaries. In addition, lawsuits have occurred or are reasonably expected against emitters of greenhouse gases alleging that these companies are liable for personal injuries and property damage caused by climate change. These lawsuits may seek injunctive relief, monetary compensation, and punitive damages.
In additionDecember 2017, Entergy New Orleans, Inc. changed its name to the regulatory and financial risks associated with climate change discussed above, potential physical risks from climate change include an increase in sea level, wind and storm surge damages, wetland and barrier island erosion, risks of flooding and changes in weather conditions, (such as increases in precipitation, drought, or changes in average temperatures)Entergy Utility Group, Inc., and potential increased impacts of extreme weather conditions or storms. Entergy subsidiaries own assets in, and serve, communities that are at risk from sea level rise, changes in weather conditions, storms, and loss of the protection offered by coastal wetlands. A significant portion of the nation’s oil and gas infrastructure is located in these areas and susceptible to storm damage that could be aggravated by wetland and barrier island erosion, which could give rise to fuel supply interruptions and price spikes. Entergy and its subsidiaries also face the risk that climate change could impact the availability and quality of water supply necessary for operations.
These and other physical changes could result in changes in customer demand, increased costs associated with repairing and maintaining generation facilities and transmission and distribution systems resulting in increased maintenance and capital costs (and potential increased financing needs), limits on the Entergy System’s ability to meet peak customer demand, increased regulatory oversight, and lower customer satisfaction. Also, to the extent that climate change adversely impacts the economic health of a region or results in energy conservation or demand side management programs, it may adversely impact customer demand and revenues. Such physical or operational risks could have a material effect on Entergy’s, Entergy Wholesale Commodities’, System Energy’s, and the Utility operating companies’ financial condition, results of operations, and liquidity.
Continued and future availability and quality of water for cooling, process, and sanitary uses could materially affect the financial condition, results of operations, and liquidity of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business.
Water is a vital natural resource that is also critical to the Utility operating companies’, System Energy’s, and Entergy Wholesale Commodities’ business operations. Entergy’s facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Three of Entergy’s Utility operating companies own and/or operate hydroelectric facilities. Accordingly, water availability and quality are critical to Entergy’s business operations. Impacts to water availability or quality could negatively impact both operations and revenues.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Entergy secures water through various mechanisms (ground water wells, surface waters intakes, municipal supply, etc.) and operates under the provisions and conditions set forth by the provider and/or regulatory authorities. Entergy also obtains and operates in substantial compliance with water discharge permits issued under various provisions of the Clean Water Act and/or state water pollution control provisions. Regulations and authorizations for both water intake and use and for waste discharge can become more stringent in times of water shortages, low flows in rivers, low lake levels, low groundwater aquifer volumes, and similar conditions. The increased use of water by industry, agriculture, and the population at large, population growth, and the potential impacts of climate change on water resources may cause water use restrictions that affect Entergy and its subsidiaries.
Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices, which could materially affect Entergy’s and its subsidiaries’ results of operations, financial condition, and liquidity.
To manage near-term financial exposure related to commodity price fluctuations, Entergy and its subsidiaries, including the Utility operating companies and the Entergy Wholesale Commodities business, may enter into contracts to hedge portions of their purchase and sale commitments, fuel requirements, and inventories of natural gas, uranium and its conversion and enrichment, coal, refined products, and other commodities, within established risk management guidelines. As part of this strategy, Entergy and its subsidiaries may utilize fixed- and variable-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. However, Entergy and its subsidiaries normally cover only a portion of the exposure of their assets and positions to market price volatility, and the coverage will vary over time. In addition, Entergy also elects to leave certain volumes during certain years unhedged. To the extent Entergy and its subsidiaries have unhedged positions, fluctuating commodity prices can materially affect Entergy’s and its subsidiaries’ results of operations and financial position.
Although Entergy and its subsidiaries devote a considerable effort to these risk management strategies, they cannot eliminate all the risks associated with these activities. As a result of these and other factors, Entergy and its subsidiaries cannot predict with precision the impact that risk management decisions may have on their business, results of operations, or financial position.
Entergy’s over-the-counter financial derivatives are subject to rules implementing the Dodd-Frank Wall Street Reform and Consumer Protection Act that are designed to promote transparency, mitigate systemic risk and protect against market abuse. Entergy cannot predict the impact any proposed or not fully-implemented final rules will have on its ability to hedge its commodity price risk or on over-the-counter derivatives markets as a whole, but such rules and regulations could have a material effect on Entergy's risk exposure, as well as reduce market liquidity and further increase the cost of hedging activities.
Entergy has guaranteed or indemnified the performance of a portion of the obligations relating to hedging and risk management activities. Reductions in Entergy’s or its subsidiaries’ credit quality or changes in the market prices of energy commodities could increase the cash or letter of credit collateral required to be posted in connection with hedging and risk management activities, which could materially affect Entergy’s or its subsidiaries’ liquidity and financial position.
The Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties may not meet their obligations, which may materially affect the Utility operating companies and Entergy Wholesale Commodities.
The hedging and risk management practices of the Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties that owe Entergy and its subsidiaries money, energy, or other commodities will not perform their obligations. Currently, some hedging agreements contain provisions that require the counterparties to provide credit support to secure all or part of their obligations to Entergy or its subsidiaries. If the counterparties to these arrangements fail to perform, Entergy or its subsidiaries may enforce and recover the proceeds from the credit support provided and acquire alternative hedging arrangements, which credit
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
support may not always be adequate to cover the related obligations. In such event, Entergy and its subsidiaries might incur losses in addition to amounts, if any, already paid to the counterparties. In addition, the credit commitments of Entergy’s lenders under its bank facilities may not be honored for a variety of reasons, including unexpected periods of financial distress affecting such lenders, which could materially affect the adequacy of its liquidity sources.
Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.
The performance of the capital markets affects the values of the assets held in trust under Entergy’s pension and postretirement benefit plans. A decline in the market value of the assets may increase the funding requirements relating to Entergy’s benefit plan liabilities and also result in higher benefit costs. As the value of the assets decreases, the “expected return on assets” component of benefit costs decreases, resulting in higher benefits costs. Additionally, asset losses are incorporated into benefit costs over time, thus increasing benefits costs. Volatility in the capital markets has affected the market value of these assets, which may affect Entergy’s planned levels of contributions in the future. Additionally, changes in interest rates affect the liabilities under Entergy’s pension and postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding and recognition of higher liability carrying costs. The funding requirements of the obligations related to the pension benefit plans can also increase as a result of changes in, among other factors, retirement rates, life expectancy assumptions, or Federal regulations. For further information regarding Entergy’s pension and other postretirement benefit plans, refer to the “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” section of Management’s Financial Discussion and Analysis for Entergy and each of its Registrant Subsidiaries and Note 11 to the financial statements.
The litigation environment in the states in which certain Entergy subsidiaries operate poses a significant risk to those businesses.
Entergy and its subsidiaries are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, asbestos, hazardous material and ratepayer matters, and injuries and damages issues, among other matters. The states in which the Utility operating companies operate, in particular Louisiana, Mississippi, and Texas, have proven to be unusually litigious environments. Judges and juries in these states have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. Entergy and its subsidiaries use legal and appropriate means to contest litigation threatened or filed against them, but the litigation environment in these states poses a significant business risk.
Domestic or international terrorist attacks, including cyber attacks, and failures or breaches of Entergy’s and its subsidiaries’ technology systems may adversely affect Entergy’s results of operations.
As power generators and distributors, Entergy and its subsidiaries face heightened risk of an act or threat of terrorism, including physical and cyber attacks, either as a direct act against one of Entergy’s generation facilities, transmission operations centers, or distribution infrastructure used to manage and transport power to customers. An actual act could affect Entergy’s ability to operate, including its ability to operate the information technology systems and network infrastructure on which it relies to conduct its business. While malware was recently discovered on our corporate network and remediated on a timely basis, it did not affect the company’s operational systems, nuclear plants or transmission network, nor did it have a material effect on our operations. Additionally, within Entergy’s industry, there have been attacks on energy infrastructure, but with minimal impact to operations, and there may be more attacks in the future. The Utility operating companies also face heightened risk of an act or threat by cyber criminals intent on accessing personal information for the purpose of committing identity theft, taking company-sensitive data, or disrupting the company’s ability to operate.
Entergy and its subsidiaries operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure in accordance with mandatory and prescriptive standards. Despite the implementation of multiple layers of security by Entergy and its subsidiaries,
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
technology systems remain vulnerable to potential threats that could lead to unauthorized access or loss of availability to critical systems essential to the reliable operation of Entergy’s electric system. Moreover, the functionality of Entergy’s technology systems depends on both its and third-party systems to which Entergy is connected directly or indirectly (such as systems belonging to suppliers, vendors and contractors). While Entergy has processes in place to assess systems of certain of these suppliers, vendors and contractors, Entergy does not ultimately control the adequacy of their defenses against cyber and other attacks, but has implemented oversight measures to assess maturity and manage third-party risk. If Entergy’s or its subsidiaries’ technology systems were compromised and unable to detect or recover in a timely fashion to a normal state of operations, Entergy or its subsidiaries may be unable to perform critical business functions that are essential to the company’s well-being and the health, safety, and security needs of its customers. In addition, an attack on its information technology infrastructure may result in a loss of its confidential, sensitive, and proprietary information, including personal information of its customers, employees, vendors, and others in Entergy’s care.
Any such attacks, failures or breaches could have a material effect on Entergy’s and the Utility operating companies’ business, financial condition, results of operations or reputation. Insurance may not be adequate to cover losses that might arise in connection with these events. The risk of such attacks, failures, or breaches may cause Entergy and the Utility operating companies to incur increased capital and operating costs to implement increased security for its power generation, transmission, and distribution assets and other facilities, such as additional physical facility security and security personnel, and for systems to protect its information technology and network infrastructure systems. Such events may also expose Entergy to an increased risk of litigation (and associated damages and fines).
(Entergy New Orleans)
The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidity.
Gas rates charged to retail gas customers are comprised primarily of purchased gas cost charges, which provide no return or profitOrleans Power then changed its name to Entergy New Orleans, and distribution charges, which provide a return or profit to the utility. Distribution charges are affected by the amount of gas sold to customers. Purchased gas cost charges, which comprise most of a customer’s bill and may be adjusted monthly, represent gas commodity costs thatLLC. Entergy New Orleans, recovers from its customers. Entergy New Orleans’s cash flows can be affected by differences between the time period when gas is purchased and the time when ultimate recovery from customers occurs. When purchased gas cost charges increase substantially reflecting higher gas procurement costs incurred by Entergy New Orleans, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy New Orleans, which could adversely affect results of operations.
(System Energy)
System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on affiliated companies for all of its revenues.
System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. Charges under the Unit Power Sales Agreement are paid by the Utility operating companies as consideration for their respective entitlements to receive capacity and energy. The useful economic life of Grand Gulf is finite and is limited by the terms of its operating license, which expires in November 2044. System Energy’s financial condition depends both on the receipt of payments from the Utility operating companies under the Unit Power Sales Agreement and on the continued commercial operation of Grand Gulf.
For information regarding the Unit Power Sales Agreement, the sale and leaseback transactions and certain other agreements relating to the Entergy System companies’ support of System Energy (including the Capital Funds
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Agreement), see Notes 8 and 10 to the financial statements and the “Utility - System Energy and Related Agreements” section of Part I, Item 1.
(Entergy Corporation)
As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock.
Entergy Corporation is a holding company with no material revenue generating operations of its own or material assets other than the stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Entergy Corporation’s ability to satisfy its financial obligations, including the payment of interest and principal on its outstanding debt, and to pay dividends on its common stock depends on the payment to it of dividends or distributions by its subsidiaries. The payments of dividends or distributions to Entergy Corporation by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings, and on any applicable legal, regulatory, or contractual limitations on subsidiaries’ ability to pay such dividends or distributions. Provisions in the articles of incorporation of certain of Entergy Corporation’s subsidiaries restrict the payment of cash dividends to Entergy Corporation. For further information regarding dividend or distribution restrictions to Entergy Corporation, see Note 7 to the financial statements.
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ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
Net Income
2017 Compared to 2016
Net income decreased $27.4 million primarily due to higher nuclear refueling outage expenses, higher depreciation and amortization expenses, higher taxes other than income taxes, and higher interest expense, partially offset by higher other income.
2016 Compared to 2015
Net income increased $92.9 million primarily due to higher net revenue and lower other operation and maintenance expenses, partially offset by a higher effective income tax rate and higher depreciation and amortization expenses.
Net Revenue
2017 Compared to 2016
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2017 to 2016.
|
| | | |
| Amount |
| (In Millions) |
| |
2016 net revenue |
| $1,520.5 |
|
Retail electric price | 33.8 |
|
Opportunity sales | 5.6 |
|
Asset retirement obligation | (14.8 | ) |
Volume/weather | (29.0 | ) |
Other | 6.5 |
|
2017 net revenue |
| $1,522.6 |
|
The retail electric price variance is primarily due to the implementation of formula rate plan rates effective with the first billing cycle of January 2017 and an increase in base rates effective February 24, 2016, each as approved by the APSC. A significant portion of the base rate increase was related to the purchase of Power Block 2 of the Union Power Station in March 2016. The increase was partially offset by decreases in the energy efficiency rider, as approved by the APSC, effective April 2016 and January 2017. See Note 2 to the financial statements for further discussion of the rate case and formula rate plan filings. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.
The opportunity sales variance results from the estimated net revenue effect of the 2017 and 2016 FERC orders in the opportunity sales proceeding attributable to wholesale customers. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The asset retirement obligation affects net revenue because Entergy Arkansas records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and decommissioning trust fund earnings plus asset retirement obligation-related costs collected in revenue. The variance is primarily caused by a decrease in regulatory credits because of an increase in decommissioning trust fund earnings, including portfolio rebalancing for the ANO 1 and ANO 2 decommissioning trust funds.
The volume/weather variance is primarily due to the effect of less favorable weather on residential and commercial sales during the billed and unbilled sales periods. The decrease was partially offset by an increase of 733 GWh, or 11%, in industrial usage primarily due to a new customer in the primary metals industry.
2016 Compared to 2015
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2016 to 2015.
|
| | | |
| Amount |
| (In Millions) |
| |
2015 net revenue |
| $1,362.2 |
|
Retail electric price | 161.5 |
|
Other | (3.2 | ) |
2016 net revenue |
| $1,520.5 |
|
The retail electric price variance is primarily due to an increase in base rates, as approved by the APSC. The new base rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. The increase includes an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. A significant portion of the increase was related to the purchase of Power Block 2 of the Union Power Station in March 2016. See Note 2 to the financial statements for further discussion of the rate case. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.
Other Income Statement Variances
2017 Compared to 2016
Nuclear refueling outage expenses increased primarily due to the amortization of higher costs associated with the most recent outages compared to previous outages.
Other operation and maintenance expenses increased primarily due to:
the deferral in the first quarter 2016 of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance, as approved by the APSC as part of the 2015 rate case settlement. These costs are being amortized over a ten-year period beginning March 2016. See Note 2 to the financial statements for further discussion of the rate case settlement;
an increase of $9.5 million in transmission and distribution expenses primarily due to higher vegetation maintenance costs and higher labor costs, including contract labor;
an increase of $5.9 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 2017 as compared to the prior year; and
the effect of recording in July 2016 the final court decision in a lawsuit against the DOE related to spent nuclear fuel storage costs. The damages awarded included the reimbursement of $5.5 million of spent nuclear fuel
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
storage costs previously recorded as other operation and maintenance expense. See Note 8 to the financial statements for further discussion of Entergy Arkansas’s spent nuclear fuel litigation.
The increase was partially offset by:
a decrease of $16 million in nuclear generation expenses primarily due to a decrease in regulatory compliance costs compared to the prior year, partially offset by higher nuclear labor costs, including contract labor, to position the nuclear fleet to meet its operational goals. The decrease in regulatory compliance costs is primarily related to NRC inspection activities in 2016 as a result of the NRC’s March 2015 decision to move ANO into the “multiple/repetitive degraded cornerstone column” of the NRC’s reactor oversight process action matrix. See Note 8 to the financial statements for a discussion of the ANO stator incident and subsequent NRC reviews;
a decrease of $11.5 million in energy efficiency expenses primarily due to the timing of recovery from customers; and
a decrease of $5.2 million in fossil-fueled generation expenses primarily due to lower long-term service agreement costs, partially offset by an overall higher scope of work including plant outages in 2017 compared to 2016.
Taxes other than income taxes increased primarily due to an increase in ad valorem taxes primarily due to higher assessments and higher millage rates and an increase in local franchise taxes primarily due to higher billing factors.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including Power Block 2 of the Union Power Station purchased in March 2016. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.
Other income increased primarily due to higher realized gains in 2017 compared to 2016 on the decommissioning trust fund investments, including portfolio rebalancing for the ANO 1 and ANO 2 decommissioning trust funds.
Interest expense increased primarily due to:
an increase of $3.3 million in estimated interest expense recorded in connection with the opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding; and
the issuance in May 2017 of $220 million of 3.5% Series first mortgage bonds and the issuance in June 2016 of $55 million of 3.5% Series first mortgage bonds, partially offset by the redemption in July 2016 of $60 million of 6.38% Series first mortgage bonds and the redemption in February 2016 of $175 million of 5.66% Series first mortgage bonds. See Note 5 to the financial statements for further discussion of long-term debt.
2016 Compared to 2015
Nuclear refueling outage expenses increased primarily due to the amortization of higher costs associated with the most recent outages compared to previous outages.
Other operation and maintenance expenses decreased primarily due to:
a decrease of $21.6 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
the deferral of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance, as approved by the APSC as part of the 2015 rate case settlement. These costs are being amortized over a ten-year period beginning March 2016. See Note 2 to the financial statements for further discussion of the rate case settlement; and
a decrease of $7.2 million in energy efficiency costs, including the effects of true-ups to the energy efficiency filings for fixed costs to be collected from customers and incentives recognized as a result of participation in energy efficiency programs.
The decrease was partially offset by an increase of $24.1 million in nuclear generation expenses primarily due to an overall higher scope of work performed during plant outages and higher nuclear labor costs compared to prior year and an increase of $8.2 million in fossil-fueled generation expenses primarily due to the purchase of Power Block 2 of the Union Power Station in March 2016. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.
Taxes other than income taxes decreased primarily due to a decrease in local franchise taxes resulting from lower residential and commercial revenues compared to the prior year and a decrease in payroll taxes.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including Power Block 2 of the Union Power Station purchased in March 2016. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.
Interest expense increased primarily due to:
$5.1 million in estimated interest expense recorded in connection with the FERC orders issued in April 2016 in the opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding; and
the net issuance of $230 million of first mortgage bonds in 2016. See Note 5 to the financial statements for further discussion of long-term debt.
Income Taxes
The effective income tax rates for 2017, 2016, and 2015 were 40.1%, 39.2%, and 35.3%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.
Income Tax Legislation
See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Tax Cuts and Jobs Act, the federal income tax legislation enacted in December 2017. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses proceedings commenced or other responses by Entergy’s regulators to the Act.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2017, 2016, and 2015 were as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (In Thousands) |
Cash and cash equivalents at beginning of period |
| $20,509 |
| |
| $9,135 |
| |
| $218,505 |
|
| | | | | |
Net cash provided by (used in): | | | |
| | |
|
Operating activities | 555,556 |
| | 676,511 |
| | 474,890 |
|
Investing activities | (829,312 | ) | | (947,995 | ) | | (685,274 | ) |
Financing activities | 259,463 |
| | 282,858 |
| | 1,014 |
|
Net increase (decrease) in cash and cash equivalents | (14,293 | ) | | 11,374 |
| | (209,370 | ) |
| | | | | |
Cash and cash equivalents at end of period |
| $6,216 |
| |
| $20,509 |
| |
| $9,135 |
|
Operating Activities
Net cash flow provided by operating activities decreased $121 million in 2017 primarily due to income tax refunds of $8.1 million in 2017 compared to income tax refunds of $135.7 million in 2016. Entergy Arkansas had income tax refunds in 2016 and 2017 in accordance with an intercompany income tax allocation agreement. The income tax refunds in 2017 resulted from the utilization of Entergy Arkansas’s net operating losses. The 2016 income tax refunds resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit. See Note 3 to the financial statements for a discussion of the income tax audit.
Net cash flow provided by operating activities increased $201.6 million in 2016 primarily due to:
income tax refunds of $135.7 million in 2016 compared to income tax payments of $103.3 million in 2015. Entergy Arkansas had income tax refunds in 2016 and income tax payments in 2015 in accordance with an intercompany income tax allocation agreement. The 2016 income tax refunds resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit whereas the income tax payments in 2015 resulted primarily from final settlement of amounts outstanding associated with the 2006-2007 IRS audit as well as adjustments associated with the settlement of the 2008-2009 IRS audit. See Note 3 to the financial statements for further discussion of the income tax audits;
the timing of payments to vendors; and
an increase in net revenue.
The increase was partially offset by a decrease due to the timing of recovery of fuel and purchased power costs.
Investing Activities
Net cash flow used in investing activities decreased $118.7 million in 2017 primarily due to the purchase of Power Block 2 of the Union Power Station in March 2016 for approximately $237 million and a decrease of $35.5 million in transmission construction expenditures primarily due to a lower scope of work performed in 2017. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The decrease was partially offset by:
an increase of $50.4 million in nuclear construction expenditures primarily due to a higher scope of work performed on various nuclear projects in 2017;
an increase of $37.7 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and service deliveries, and the timing of cash payments during the nuclear fuel cycle;
an increase of $32.9 million in information technology construction expenditures primarily due to increased spending on substation technology upgrades;
an increase of $22.3 million in fossil-fueled generation construction expenditures primarily due to a higher scope of work performed on various projects in 2017; and
an increase of $11.2 million due to increased spending on advanced metering infrastructure.
Net cash flow used in investing activities increased $262.7 million in 2016 primarily due to the purchase of Power Block 2 of the Union Power Station in March 2016 for approximately $237 million. See Note 14 to the financial statements for further discussion of the Union Power Station purchase. The increase was partially offset by fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and service deliveries, and the timing of cash payments during the nuclear fuel cycle.
Financing Activities
Net cash flow provided by financing activities decreased $23.4 million in 2017 primarily due to:
a $200 million capital contribution received from Entergy Corporation in March 2016 primarily in anticipation of Entergy Arkansas’s purchase of Power Block 2 of the Union Power Station;
the net issuance of $119.1 million of long-term debt in 2017 compared to the net issuance of $189.1 million of long-term debt in 2016; and
$15 million in common stock dividends paid in 2017 resulting from Entergy Arkansas’s routine evaluation of its ability to pay dividends. There were no common stock dividends paid in 2016 in anticipation of the purchase of Power Block 2 of the Union Power Station.
The decrease was partially offset by:
money pool activity;
the redemptions of $75 million of 6.45% Series preferred stock and $10 million of 6.08% Series preferred stock in 2016; and
net short-term borrowings of $50 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2017 compared to net repayments of $11.7 million in 2016.
Increases in Entergy Arkansas’s payable to the money pool are a source of cash flow, and Entergy Arkansas’s payable to the money pool increased by $114.9 million in 2017 compared to decreasing by $1.5 million in 2016. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Net cash flow provided by financing activities increased $281.8 million in 2016 primarily due to:
the net issuance of $189.1 million of long-term debt in 2016 compared to the net retirement of $13.2 million of long-term debt in 2015;
a $200 million capital contribution received from Entergy Corporation in March 2016 primarily in anticipation of Entergy Arkansas’s purchase of Power Block 2 of the Union Power Station; and
net repayments of $11.7 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2016 compared to net repayments of $36.3 million in 2015.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The increase was partially offset by the redemptions of $75 million of 6.45% Series preferred stock and $10 million of 6.08% Series preferred stock in 2016 and money pool activity.
Decreases in Entergy Arkansas’s payable to the money pool are a use of cash flow, and Entergy Arkansas’s payable to the money pool decreased by $1.5 million in 2016 compared to increasing by $52.7 million in 2015.
See Note 5 to the financial statements for further details of long-term debt.
Capital Structure
Entergy Arkansas’s capitalization is balanced between equity and debt, as shown in the following table.
|
| | | |
| December 31, 2017 | | December 31, 2016 |
Debt to capital | 55.5% | | 55.3% |
Effect of excluding the securitization bonds | (0.3%) | | (0.4%) |
Debt to capital, excluding securitization bonds (a) | 55.2% | | 54.9% |
Effect of subtracting cash | —% | | (0.2%) |
Net debt to net capital, excluding securitization bonds (a) | 55.2% | | 54.7% |
| |
(a) | Calculation excludes the securitization bonds, which are non-recourse to Entergy Arkansas. |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings and long-term debt, including the currently maturing portion. Capital consists of debt, preferred stock without sinking fund, and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because the securitization bonds are non-recourse to Entergy Arkansas, as more fully described in Note 5 to the financial statements. Entergy Arkansas also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because net debt indicates Entergy Arkansas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Arkansas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure. In addition, in certain infrequent circumstances, such as large transactions that would materially alter the capital structure if financed entirely with debt and reducing dividends, Entergy Arkansas may receive equity contributions to maintain the targeted capital structure.
Uses of Capital
Entergy Arkansas requires capital resources for:
construction and other capital investments;
debt and preferred stock maturities or retirements;
working capital purposes, including the financing of fuel and purchased power costs; and
dividend and interest payments.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.
|
| | | | | | | | | | | |
| 2018 | | 2019 | | 2020 |
| (In Millions) |
Planned construction and capital investment: | | | |
| | |
|
Generation |
| $190 |
| |
| $240 |
| |
| $225 |
|
Transmission | 170 |
| | 165 |
| | 175 |
|
Distribution | 225 |
| | 245 |
| | 225 |
|
Utility Support | 110 |
| | 85 |
| | 85 |
|
Total |
| $695 |
| |
| $735 |
| |
| $710 |
|
Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2019-2020 | | 2021-2022 | | after 2022 | | Total |
| (In Millions) |
Long-term debt (a) |
| $125 |
| |
| $266 |
| |
| $672 |
| |
| $4,208 |
| |
| $5,271 |
|
Operating leases |
| $17 |
| |
| $29 |
| |
| $16 |
| |
| $24 |
| |
| $86 |
|
Purchase obligations (b) |
| $595 |
| |
| $1,050 |
| |
| $863 |
| |
| $5,369 |
| |
| $7,877 |
|
| |
(a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
(b) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Arkansas, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which are discussed in Note 8 to the financial statements. |
In addition to the contractual obligations given above, Entergy Arkansas currently expects to contribute approximately $64.1 million to its qualified pension plans and approximately $472 thousand to its other postretirement health care and life insurance plans in 2018, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations, Entergy Arkansas has ($117.7) million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Arkansas includes specific investments, such as transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including investment to support advanced metering; resource planning, including potential generation projects; system improvements; investments in ANO 1 and 2; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the financial statements.
As discussed above in “Capital Structure,” Entergy Arkansas routinely evaluates its ability to pay dividends to Entergy Corporation from its earnings. Provisions in Entergy Arkansas’s articles of incorporation relating to preferred
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
stock restrict the amount of retained earnings available for the payment of cash dividends or other distributions on its common and preferred stock.
Advanced Metering Infrastructure (AMI)
In September 2016, Entergy Arkansas filed an application seeking a finding from the APSC that Entergy Arkansas’s deployment of AMI is in the public interest. Entergy Arkansas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Arkansas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $208 million. The filing identified a number of quantified and unquantified benefits, and Entergy Arkansas provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal net benefit to customers of $406 million. Entergy Arkansas also sought to continue to include in rate base the remaining book value of existing meters, which was approximately $57 million at December 31, 2015, that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Arkansas proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Deployment of the communications network is expected to begin in 2018. Entergy Arkansas proposed to include the AMI deployment costs and the quantified benefits in future formula rate plan filings, and the 2018 costs were approved in the 2017 formula rate plan filing. In June 2017 the APSC staff and Arkansas Attorney General filed direct testimony. The APSC staff generally supported Entergy Arkansas’s AMI deployment conditioned on various recommendations. The Arkansas Attorney General’s consultant primarily recommended denial of Entergy Arkansas’s application but alternatively suggested recommendations in the event the APSC approves Entergy Arkansas’s proposal. Entergy Arkansas filed rebuttal testimony in June 2017, substantially accepting the APSC staff’s recommendations. In August 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement. In October 2017 the APSC issued an order finding that Entergy Arkansas’s AMI deployment is in the public interest and approving the settlement agreement subject to a minor modification. Entergy Arkansas expects to recover the undepreciated balance of its existing meters through a regulatory asset to be amortized over 15 years. Entergy Arkansas has begun discussions with the other parties to implement the items in the settlement agreement including pre-pay and time of use programs.
Sources of Capital
Entergy Arkansas’s sources to meet its capital requirements include:
internally generated funds;
cash on hand;
debt or preferred stock issuances; and
bank financing under new or existing facilities.
Entergy Arkansas may refinance, redeem, or otherwise retire debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
All debt and common and preferred stock issuances by Entergy Arkansas require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in Entergy Arkansas’s corporate charters, bond indentures, and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Arkansas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
|
| | | | | | |
2017 | | 2016 | | 2015 | | 2014 |
(In Thousands) |
($166,137) | | ($51,232) | | ($52,742) | | $2,218 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Arkansas has a credit facility in the amount of $150 million scheduled to expire in August 2022. Entergy Arkansas also has a $20 million credit facility scheduled to expire in April 2018. The $150 million credit facility permits the issuance of letters of credit against $5 million of the borrowing capacity of the facility. As of December 31, 2017, there were no cash borrowings and no letters of credit outstanding under the credit facilities. In addition, Entergy Arkansas is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2017, a $1 million letter of credit was outstanding under Entergy Arkansas’s uncommitted letter of credit facility. See Note 4 to the financial statements for further discussion of the credit facilities.
The Entergy Arkansas nuclear fuel company variable interest entity has a credit facility in the amount of $80 million scheduled to expire in May 2019. As of December 31, 2017, $50 million in letters of credit to support a like amount of commercial paper issued and $24.9 million in loans were outstanding under the Entergy Arkansas nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for further discussion of the nuclear fuel company variable interest entity credit facility.
Entergy Arkansas obtained authorizations from the FERC through October 2019 for short-term borrowings not to exceed an aggregate amount of $250 million at any time outstanding and borrowings by its nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of Entergy Arkansas’s short-term borrowing limits. The long-term securities issuances of Entergy Arkansas are limited to amounts authorized by the APSC, and the current authorization extends through December 2018.
State and Local Rate Regulation and Fuel-Cost Recovery
Retail Rates
2015 Base Rate Filing
In April 2015, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing notified the APSC of Entergy Arkansas’s intent to implement a forward test year formula rate plan pursuant to Arkansas legislation passed in 2015, and requested a retail rate increase of $268.4 million, with a net increase in revenue of $167 million. The filing requested a 10.2% return on common equity. In September 2015 the APSC staff and intervenors filed direct testimony, with the APSC staff recommending a revenue requirement of $217.9 million and a 9.65% return on common equity. In December 2015, Entergy Arkansas, the APSC staff, and certain of the intervenors in the rate case filed with the APSC a joint motion for approval of a settlement of the case that proposed a retail rate increase of approximately $225 million with a net increase in revenue of approximately $133 million; an authorized return on common equity of 9.75%; and a formula rate plan tariff that provides a +/- 50 basis point band around the 9.75% allowed return on common equity. A significant portion of the rate increase is related to Entergy Arkansas’s acquisition in March 2016 of Union Power Station Power Block 2 for a base purchase price of $237 million. The settlement agreement also provided for amortization over a 10-year period of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance. A settlement hearing was held in January 2016. In February 2016 the APSC approved the settlement with one exception that reduced the retail rate increase proposed in the settlement by $5 million. The settling parties agreed to the APSC modifications in February 2016. The new rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. In March 2016, Entergy Arkansas made a compliance filing regarding the
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
new rates that included an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. The interim base rate adjustment surcharge was designed to recover a total of $21.1 million over the nine-month period from April 2016 through December 2016.
2016 Formula Rate Plan Filing
In July 2016, Entergy Arkansas filed with the APSC its 2016 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2017 test period to be below the formula rate plan bandwidth. The filing requested a $67.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%. In October 2016, Entergy Arkansas filed with the APSC revised formula rate plan attachments with an updated request for a $54.4 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors, as well as three additional adjustments identified as appropriate by Entergy Arkansas. In November 2016 a hearing was held and the APSC issued an order directing the parties to brief certain issues. In December 2016 the APSC approved the settlement agreement and the $54.4 million revenue requirement increase with approximately $25 million of the $54.4 million revenue requirement subject to possible future adjustment and refund to customers with interest. The APSC requested supplemental information for some of Entergy Arkansas’s requested nuclear expenditures. In December 2016 the APSC approved Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2017. In April 2017, Entergy Arkansas filed a motion consented to by all parties requesting that it be permitted to submit the supplemental information requested by the APSC in conjunction with its 2017 formula rate plan filing, which was subsequently made in July 2017 and is discussed below. In May 2017 the APSC approved the joint motion and proposal to review Entergy Arkansas’s supplemental information on a concurrent schedule with the 2017 formula rate plan filing. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the docket and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and recovery of the 2017 and 2018 nuclear costs.
2017 Formula Rate Plan Filing
In July 2017, Entergy Arkansas filed with the APSC its 2017 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2018 test period to be below the formula rate plan bandwidth. The filing projected a $129.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%. Entergy Arkansas’s formula rate plan is subject to a four percent annual revenue constraint and the projected annual revenue requirement increase exceeded the four percent, resulting in a proposed increase for the 2017 formula rate plan of $70.9 million. In October 2017, Entergy Arkansas filed with the APSC revised formula rate plan attachments that projected a $126.2 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors. The revised formula rate plan filing included a proposed $71.1 million revenue requirement increase based on a revision to the four percent constraint calculation. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the docket and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and the $71.1 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2018.
Internal Restructuring
In November 2017, Entergy Arkansas filed an application with the APSC seeking authorization to undertake a restructuring that would result in the transfer ofLLC holds substantially all of the assets, and operationshas assumed substantially all of the liabilities, of Entergy Arkansas to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company.New Orleans, Inc. The restructuring is subject to regulatory review and approval by the APSC, the FERC, and the NRC. Entergy Arkansas also filedwas accounted for as a notice with the Missouri Public Service Commission in December 2017 out of an abundance of caution, althoughtransaction between entities under common control.
Entergy Arkansas Inc. and SubsidiariesInternal Restructuring
Management’s Financial Discussion and Analysis
Entergy Arkansas does not serve any retail customers in Missouri. If the APSC approves the restructuring by September 1, 2018, and the restructuring closes on or before December 1,In November 2018, Entergy Arkansas proposed in its application to credit retail customers $66 million over six years, beginning in 2019. In February 2018, Entergy Arkansas filed supplemental testimony reducing the proposed retail customer credits to $39.6 million over six years. If the APSC, the FERC, and the NRC approvals are obtained, Entergy Arkansas expects the restructuring will be consummated on or before December 1, 2018.
It is currently contemplated that Entergy Arkansas would undertakeundertook a multi-step restructuring, which would includeincluding the following:
•Entergy Arkansas, would redeemInc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million, which includes call premiums, plus accumulated and unpaid dividends, if any.million.
•Entergy Arkansas, would convertInc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, will allocateInc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power will assumeassumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, will remainInc. remained in existence and holdheld the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, will contributeInc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power will beis a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, will changeInc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power will then changechanged its name to Entergy Arkansas, LLC.
Upon the completion of the restructuring, Entergy Arkansas, LLC will holdholds substantially all of the assets, and will have assumed substantially all of the liabilities, of Entergy Arkansas.Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Mississippi Internal Restructuring
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
Entergy Wholesale Commodities
Entergy Wholesale Commodities includes the ownership, operation, and decommissioning of nuclear power plants, located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities revenues are primarily derived from sales of energy and generation capacity from these plants. Entergy Wholesale Commodities also provides operations and management services, including decommissioning-related services, to nuclear power plants owned by non-affiliated entities in the United States. Entergy Wholesale Commodities also includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers.
See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
Property
Nuclear Generating Stations
Entergy Wholesale Commodities includes the ownership of the following nuclear power plants:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Power Plant | | Market | | In Service Year | | Acquired | | Location | | Capacity - Reactor Type | | License Expiration Date |
Indian Point 3 (a) | | NYISO | | 1976 | | Nov. 2000 | | Buchanan, NY | | 1,041 MW - Pressurized Water | | 2025 (a) |
Indian Point 2 (a) | | NYISO | | 1974 | | Sept. 2001 | | Buchanan, NY | | 1,028 MW - Pressurized Water | | 2024 (a) |
Palisades (b) | | MISO | | 1971 | | Apr. 2007 | | Covert, MI | | 811 MW - Pressurized Water | | 2031 (b) |
(a)Power operations ceased at the Indian Point 2 plant in April 2020. The fuel was permanently removed from the reactor vessel and placed in the spent fuel pool in May 2020. The Indian Point 3 plant is expected to cease operations on April 30, 2021. Entergy and Holtec jointly filed a license transfer application with the NRC in November 2019, requesting approval for the transfer of the Indian Point plants, along with their nuclear decommissioning trusts and decommissioning liabilities, from Entergy to Holtec. The NRC approved the license transfer application on November 23, 2020.
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(b)The Palisades plant is expected to cease operations on May 31, 2022. There is a contract to sell the plant to Holtec subject to NRC and other regulatory approvals.
See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
Entergy Wholesale Commodities also includes the ownership of two non-operating nuclear facilities, Big Rock Point in Michigan and Indian Point 1 in New York that were acquired when Entergy purchased the Palisades and Indian Point 2 nuclear plants, respectively. These facilities are in various stages of the decommissioning process. Both Big Rock Point and Indian Point 1 are under contract to be sold with their respective plants.
Non-nuclear Generating Stations
Entergy Wholesale Commodities includes the ownership, or interests in joint ventures that own, the following non-nuclear power plants:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Plant | | Location | | Ownership | | Net Owned Capacity (a) | | Type |
Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
RS Cogen; 425 MW (c) | | Lake Charles, LA | | 50% | | 213 MW | | Gas/Steam |
Nelson Unit 6; 550 MW | | Westlake, LA | | 11% | | 60 MW(b) | | Coal |
(a)“Net Owned Capacity” refers to the nameplate rating on the generating unit.
(b)The owned MW capacity is the portion of the plant capacity owned by Entergy Wholesale Commodities. For a complete listing of Entergy’s jointly-owned generating stations, refer to “Jointly-Owned Generating Stations” in Note 1 to the financial statements.
(c)Indirectly owned through an interest in an unconsolidated joint venture. In December 2020, Entergy’s wholly-owned subsidiary with a direct interest in RS Cogen, LLC entered into a membership interest purchase agreement with a subsidiary of the other 50% equity partner to sell its 50% membership interest in the joint venture to the equity partner. The targeted closing date for the transaction is October 2022.
Independent System Operators
The Indian Point plants fall under the authority of the New York Independent System Operator (NYISO). The Palisades plant falls under the authority of the MISO. The primary purpose of NYISO and MISO is to direct the operations of the major generation and transmission facilities in their respective regions; ensure grid reliability; administer and monitor wholesale electricity markets; and plan for their respective region’s energy needs.
Energy and Capacity Sales
As a wholesale generator, Entergy Wholesale Commodities’ core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and also sells energy in the day ahead or spot markets. Entergy Wholesale Commodities also sells unforced capacity, which allows load-serving entities to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Entergy Wholesale Commodities’ forward physical power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Entergy Wholesale Commodities to deliver MWh of energy, make capacity available, or both.See “Market and Credit Risk Sensitive Instruments” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for additional information regarding these contracts.
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As part of the purchase of the Palisades plant in 2007, Entergy executed a 15-year PPA with the seller, Consumers Energy, for 100% of the plant’s output, excluding any future uprates. Under the purchased power agreement, Consumers Energy receives the value of any new environmental credits for the first ten years of the agreement. Palisades and Consumers Energy will share on a 50/50 basis the value of any new environmental credits for years 11 through 15 of the agreement. The environmental credits are defined as benefits from a change in law that causes capability of the plant as of the purchase date to become a tradable attribute (e.g., emission credit, renewable energy credit, environmental credit, “green” credit, etc.) or otherwise to have a market value. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022 and transfer to Holtec thereafter.
Customers
Entergy Wholesale Commodities’ customers for the sale of both energy and capacity from its nuclear plants include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. These customers include Consumers Energy, the company from which Entergy purchased the Palisades plant, and NYISO and MISO. Substantially all the credit exposure associated with the planned energy output under contract for Entergy Wholesale Commodities nuclear plants is with counterparties or their guarantors that have public investment grade credit ratings.
Competition
The NYISO market is highly competitive. Entergy Wholesale Commodities has numerous competitors in New York including generation companies affiliated with regulated utilities, other independent power producers, municipal and co-operative generators, owners of co-generation plants and wholesale power marketers. Entergy Wholesale Commodities is an independent power producer, which means it generates power for sale to third parties at day ahead or spot market prices to the extent that the power is not sold under a fixed price contract. Municipal and co-operative generators also generate power but use most of it to deliver power to their municipal or co-operative power customers. Owners of co-generation plants produce power primarily for their own consumption. Wholesale power marketers do not own generation; rather they buy power from generators or other market participants and resell it to retail providers or other market participants. Competition in the New York power market is affected by, among other factors, the amount of generation and transmission capacity in these markets. MISO does not have a centralized clearing capacity market, but load serving entities do meet most of their capacity needs through bilateral contracts and self-supply with a smaller portion coming through voluntary MISO auctions. Almost all of Palisades’ current output is contracted to Consumers Energy through May 2022. Entergy Wholesale Commodities does not expect to be materially affected by competition in the MISO market in the near term.
Seasonality
Entergy Wholesale Commodities’ revenues and operating income are subject to fluctuations during the year due to seasonal factors, weather conditions, and contract pricing. When outdoor and cooling water temperatures are low, generally during colder months, Entergy Wholesale Commodities nuclear power plants operate more efficiently, and consequently, generate more electricity. Many of Entergy Wholesale Commodities’ contracts provide for shaped pricing over the course of the year. As a result of these factors, Entergy Wholesale Commodities’ revenues are typically higher in the first and third quarters than in the second and fourth quarters.
Fuel Supply
Nuclear Fuel
See “Fuel Supply - Nuclear Fuel” in the Utility portion of Part I, Item 1 for a discussion of the nuclear fuel cycle and markets. Entergy Nuclear Fuels Company, a wholly-owned subsidiary, is responsible for contracts to acquire nuclear materials, except for fuel fabrication, for Entergy Wholesale Commodities nuclear power plants,
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while Entergy Nuclear Operations, Inc. acts as the agent for the purchase of nuclear fuel assembly fabrication services. All contracts for the disposal of spent nuclear fuel are between the DOE and each of the nuclear power plant owners. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment has been adjusted to reflect reduced overall requirements related to the planned permanent shutdowns of the Indian Point 3 and Palisades plants. Fuel procurement for the Entergy Wholesale Commodities segment was primarily limited to the requirements of the Palisades plant’s final refueling in 2020.
Other Business Activities
Entergy Nuclear Power Marketing, LLC (ENPM) was formed in 2005 to centralize the power marketing function for Entergy Wholesale Commodities nuclear plants. Upon its formation, ENPM entered into long-term power purchase agreements with the Entergy Wholesale Commodities subsidiaries that own nuclear power plants (generating subsidiaries). As part of a series of agreements, ENPM agreed to assume and/or otherwise service the existing power purchase agreements that were in effect between the generating subsidiaries and their customers. ENPM’s functions include origination of new energy and capacity transactions and generation scheduling.
Services provided by either Entergy Nuclear, Inc. or other Entergy Wholesale Commodities subsidiaries include engineering, operations and maintenance, fuel procurement, management and supervision, technical support and training, administrative support, and other managerial or technical services required to operate, maintain, and decommission nuclear electric power facilities.
TLG Services, a subsidiary in the Entergy Wholesale Commodities segment, offers decommissioning, engineering, and related services to nuclear power plant owners.
Entergy provides plant operation support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. In 2010 an Entergy subsidiary signed an agreement to extend the management support services to Cooper Nuclear Station by 15 years, through January 2029.
Regulation of Entergy’s Business
Federal Power Act
The Federal Power Act provides the FERC the authority to regulate:
•the transmission and wholesale sale of electric energy in interstate commerce;
•the reliability of the high voltage interstate transmission system through reliability standards;
•sale or acquisition of certain assets;
•securities issuances;
•the licensing of certain hydroelectric projects;
•certain other activities, including accounting policies and practices of electric and gas utilities; and
•changes in control of FERC jurisdictional entities or rate schedules.
The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over the rates charged by Entergy Arkansas and Entergy Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the Utility operating companies. In addition, the FERC regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC regulation of the MISO RTO includes regulation of the design and implementation of the wholesale markets administered by the MISO RTO, as well as the rates, terms, and conditions of open access transmission service over the member systems and the allocation of costs associated with transmission upgrades.
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Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 70 MW of capacity.
State Regulation
Utility
Entergy Arkansas is subject to regulation by the APSC as to the following:
•utility service;
•utility service areas;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery rider;
•terms and conditions of service;
•service standards;
•the acquisition, sale, or lease of any public utility plant or property constituting an operating unit or system;
•certificates of convenience and necessity and certificates of environmental compatibility and public need, as applicable, for generating and transmission facilities;
•avoided cost payments to Qualifying Facilities;
•net energy metering;
•integrated resource planning;
•utility mergers and acquisitions and other changes of control; and
•the issuance and sale of certain securities.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory Authority only if it fails to treat its retail customers in Tennessee in the same manner as its retail customers in Arkansas. Additionally, Entergy Arkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to retail ratemaking or other regulatory jurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment clause and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•certification of certain transmission projects;
•certification of capacity acquisitions, both for owned capacity and purchase power contracts;
•procurement process to acquire over 50 MW;
•audits of the environmental adjustment charge, avoided cost payment to Qualifying Facilities, and energy efficiency rider;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control.
Entergy Mississippi is subject to regulation by the MPSC as to the following:
•utility service;
•utility service areas;
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•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery mechanism;
•terms and conditions of service;
•service standards;
•certification of generating facilities and certain transmission projects;
•avoided cost payments to Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers, acquisitions, and other changes of control.
Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.
Entergy New Orleans is subject to regulation by the City Council as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment charge and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•audit of the environmental adjustment charge;
•certification of the construction or extension of any new plant, equipment, property, or facility that comprises more than 2% of the utility’s rate base;
•integrated resource planning;
•net energy metering;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other changes of control.
To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to the following:
•retail rates and charges, including depreciation rates, and terms and conditions of service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;
•fuel recovery, including reconciliations (audits) of the fuel adjustment charges;
•service standards;
•certification of certain transmission and generation projects;
•utility service areas, including extensions into new areas;
•avoided cost payments to Qualifying Facilities;
•net energy metering; and
•utility mergers, sales/acquisitions/leases of plants over $10 million, sales of greater than 50% voting stock of utilities, and transfers of controlling interest in or operation of utilities.
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Regulation of the Nuclear Power Industry
Atomic Energy Act of 1954 and Energy Reorganization Act of 1974
Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC. Entergy subsidiaries in the Entergy Wholesale Commodities segment are subject to the NRC’s jurisdiction as the owners and operators of Indian Point Energy Center, Palisades, and Big Rock Point.
Nuclear Waste Policy Act of 1982
Spent Nuclear Fuel
Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Entergy’s nuclear owner/licensee subsidiaries have been charged fees for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2020 of $192.0 million for the one-time fee. Entergy accepted assignment of the Pilgrim, FitzPatrick, Indian Point 3, Indian Point 1 and Indian Point 2, Vermont Yankee, Palisades, and Big Rock Point spent fuel disposal contracts with the DOE held by their previous owners. The FitzPatrick spent fuel disposal contract was assigned to Exelon as part of the sale of the plant, completed in March 2017. The Vermont Yankee spent fuel disposal contract was assigned to NorthStar as part of the sale of the plant in January 2019. The Pilgrim spent fuel disposal contract was transferred to Holtec as part of the sale of Entergy Nuclear Generation Company in August 2019. The owners of these plants previous to Entergy have paid or retained liability for the fees for all generation prior to the purchase dates of those plants. The fees payable to the DOE may be adjusted in the future to assure full recovery. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.6 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).
The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing (the DOE filed the license application in June 2008) and, after the license is granted by the NRC, proceed with the repository construction and commencement of receipt of spent fuel. Because the DOE has not begun accepting spent fuel, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts. The DOE continues to delay meeting its obligation. Specific steps were taken to discontinue the Yucca Mountain project, including a motion to the NRC to withdraw the license application with prejudice and the establishment of a commission to develop recommendations for alternative spent fuel storage solutions. In August 2013 the U.S. Court of Appeals for the D.C. Circuit ordered the NRC to continue with the Yucca Mountain license review, but only to the extent of funds previously appropriated by Congress for that purpose and not yet used. Although the NRC completed the safety evaluation report for the license review in 2015, the previously appropriated funds are not sufficient to complete the review, including required hearings. The government has taken no effective action to date related to the recommendations of the appointed spent fuel study commission. Accordingly, large uncertainty remains regarding the time frame under
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which the DOE will begin to accept spent fuel from Entergy’s facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at Entergy’s nuclear sites.
Following the defunding of the Yucca Mountain spent fuel repository program, the National Association of Regulatory Utility Commissioners and others sued the government seeking cessation of collection of the one mill per net kWh generated and sold after April 7, 1983 fee. In November 2013 the D.C. Circuit Court of Appeals ordered the DOE to submit a proposal to Congress to reset the fee to zero until the DOE complies with the Nuclear Waste Policy Act or Congress enacts an alternative waste disposal plan. In January 2014 the DOE submitted the proposal to Congress under protest, and also filed a petition for rehearing with the D.C. Circuit. The petition for rehearing was denied. The zero spent fuel fee went into effect prospectively in May 2014.
As a result of the DOE’s failure to begin disposal of spent nuclear fuel in 1998 pursuant to the Nuclear Waste Policy Act of 1982 and the spent fuel disposal contracts, Entergy’s nuclear owner/licensee subsidiaries have incurred and will continue to incur damages. These subsidiaries have been, and continue to be, involved in litigation to recover the damages caused by the DOE’s delay in performance. See Note 8 to the financial statements for discussion of final judgments recorded by Entergy in 2018, 2019, and 2020 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE. Through 2020, Entergy’s subsidiaries won and collected on judgments against the government totaling approximately $800 million.
Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at Palisades in 1993, at ANO in 1996, at River Bend in 2005, at Grand Gulf in 2006, at Indian Point in 2008, and at Waterford 3 in 2011. These facilities will be expanded as needed.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Louisiana, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, Waterford 3, and Grand Gulf, respectively. In addition, Entergy Louisiana and Entergy Texas are entitled to recover from customers through electric rates the estimated decommissioning costs for the portion of River Bend subject to retail rate regulation. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.
In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In October 2020, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and ANO 2 decommissioning trusts were adequately funded without further collections, and in December 2020, the APSC ordered zero collections for ANO 1 and ANO 2 decommissioning.
In July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend to address previously identified funding shortfalls. This LPSC decision contemplated that the level of decommissioning collections could be revisited should the NRC grant license extensions for both Waterford 3 and River Bend. In July 2019, following the NRC approval of license extensions for Waterford 3 and River Bend, Entergy Louisiana made a filing with the LPSC seeking to adjust decommissioning and depreciation rates for those plants, including one proposed scenario that would adjust Louisiana-jurisdictional decommissioning collections to zero for both plants (including an offsetting increase in depreciation rates). Because of the ongoing public health emergency arising from the COVID-19 pandemic and accompanying economic uncertainty, Entergy Louisiana determined that the relief sought in the filing was no longer appropriate, and in November 2020, filed an unopposed motion to dismiss the proceeding. Following that filing, in a December 2020 order, the LPSC dismissed the proceeding without prejudice.
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In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2018 the PUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning fund was adequate following license renewal.
In September 2016 the NRC issued a 20-year operating license renewal for Grand Gulf. In a 2017 filing at the FERC, System Energy stated that with the renewed operating license, Grand Gulf’s decommissioning trust was sufficiently funded, and proposed, among other things, to cease decommissioning collections for Grand Gulf effective October 1, 2017. The FERC accepted a settlement including the proposed decommissioning revenue requirement by letter order in August 2018.
Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.
In January 2019, Entergy sold 100% of the membership interest in Entergy Nuclear Vermont Yankee to a subsidiary of NorthStar. As a result of the sale, NorthStar assumed ownership of Vermont Yankee and its decommissioning and site restoration trusts, together with complete responsibility for the facility’s decommissioning and site restoration. See Note 9 to the financial statements for further discussion of Vermont Yankee decommissioning costs and see “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the NorthStar transaction.
In August 2019, Entergy sold 100% of the equity interests in Entergy Nuclear Generation Company, LLC to a subsidiary of Holtec International. As a result of the sale, Holtec assumed ownership of Pilgrim and its decommissioning trust, together with complete responsibility for the facility’s decommissioning and site restoration. See Note 14 to the financial statements for further discussion of the sale.
For the Indian Point 3 and FitzPatrick plants purchased in 2000 from NYPA, NYPA retained the decommissioning trust funds and the decommissioning liabilities with the right to require the Entergy subsidiaries to assume each of the decommissioning liabilities provided that it assigns the corresponding decommissioning trust, up to a specified level, to the Entergy subsidiaries. In August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy, which was completed in January 2017. In March 2017, Entergy sold the FitzPatrick plant to Exelon, and as part of the transaction, the FitzPatrick decommissioning trust fund, along with the decommissioning obligation for that plant, was transferred to Exelon. The FitzPatrick spent fuel disposal contract was assigned to Exelon as part of the transaction. See Note 14 to the financial statements for discussion of the FitzPatrick sale.
In March 2020 filings with the NRC were made reporting on decommissioning funding for all of Entergy subsidiaries’ nuclear plants. Those reports showed that decommissioning funding for each of the nuclear plants met the NRC’s financial assurance requirements.
Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 16 to the financial statements.
Price-Anderson Act
The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect the public in the event of a nuclear power plant accident. The costs of this insurance
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are borne by the nuclear power industry. Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025. The Price-Anderson Act limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $137.6 million per reactor (with 97 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, System Energy, or an Entergy Wholesale Commodities company is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units is also purchased. The Price-Anderson Act and insurance applicable to the nuclear programs of Entergy are discussed in more detail in Note 8 to the financial statements.
NRC Reactor Oversight Process
The NRC’s Reactor Oversight Process is a program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response. The NRC evaluates plant performance by analyzing two distinct inputs: inspection findings resulting from the NRC’s inspection program and performance indicators reported by the licensee. The evaluations result in the placement of each plant in one of the NRC’s Reactor Oversight Process Action Matrix columns: “licensee response column,” or Column 1, “regulatory response column,” or Column 2, “degraded cornerstone column,” or Column 3, and “multiple/repetitive degraded cornerstone column,” or Column 4. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject to progressively increasing levels of inspection by the NRC with, in general, progressively increasing levels of associated costs. The nuclear generating plants owned and operated by Entergy’s Utility and Entergy Wholesale Commodities businesses are currently in Column 1, except for Grand Gulf, which is currently in Column 2.
In November 2020 the NRC placed Grand Gulf in Column 2 based on the incidence of three unplanned plant scrams during the second and third quarters of 2020.Two of the scram events related to new turbine control system components that failed, and a third related to a feedwater valve positioner that failed, all of which had been replaced in a refueling outage that ended in May 2020. The NRC plans to conduct a supplemental inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 2. As a consequence of two additional Grand Gulf scrams during the fourth quarter 2020, System Energy expects Grand Gulf to be placed into NRC Column 3 based on plant performance indicators for the four quarters ended December 31, 2020. This will involve an additional supplemental NRC inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 3.
Environmental Regulation
Entergy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy’s businesses are in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted below. Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely estimated. Except to the extent discussed below, at this time compliance with federal, state, and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Entergy’s businesses and is not expected to have a material effect on their competitive position, results of operations, cash flows, or financial position.
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Clean Air Act and Subsequent Amendments
The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a lesser extent, certain operations at nuclear and other facilities. Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements. These programs include:
•New source review and preconstruction permits for new sources of criteria air pollutants, greenhouse gases, and significant modifications to existing facilities;
•Acid rain program for control of sulfur dioxide (SO2) and nitrogen oxides (NOx);
•Nonattainment area programs for control of criteria air pollutants, which could include fee assessments for air pollutant emission sources under Section 185 of the Clean Air Act if attainment is not reached in a timely manner;
•Hazardous air pollutant emissions reduction programs;
•Interstate Air Transport;
•Operating permit programs and enforcement of these and other Clean Air Act programs;
•Regional Haze programs; and
•New and existing source standards for greenhouse gas and other air emissions.
New Source Review (NSR)
Preconstruction permits are required for new facilities and for existing facilities that undergo a modification that results in a significant net emissions increase and is not classified as routine repair, maintenance, or replacement. Units that undergo certain non-routine modifications must obtain a permit modification and may be required to install additional air pollution control technologies. In December 2020 the EPA amended the NSR regulations to clarify when a physical change or change in the method of operation will constitute such a modification. Entergy has an established process for identifying modifications requiring additional permitting approval and is monitoring the regulations and associated guidance provided by the states and the federal government with regard to the determination of routine repair, maintenance, and replacement. Several years ago, however, the EPA implemented an enforcement initiative, aimed primarily at coal plants, to identify modifications that it does not consider routine for which the unit did not obtain a modified permit. Various courts and the EPA have been inconsistent in their judgments regarding modifications that are considered routine and on other legal issues that affect this program.
In February 2011, Entergy received a request from the EPA for several categories of information concerning capital and maintenance projects at the White Bluff and Independence facilities, both located in Arkansas, in order to determine compliance with the Clean Air Act, including NSR requirements and air permits issued by the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ). In August 2011, Entergy’s Nelson facility, located in Louisiana, received a similar request for information from the EPA. In September 2015 an additional request for similar information was received for the White Bluff facility. Entergy responded to all requests. None of these EPA requests for information alleged that the facilities were in violation of law.
In January and February 2018, Entergy Arkansas, Entergy Mississippi, Entergy Power, and other co-owners received 60-day notice of intent to sue letters from the Sierra Club and the National Parks Conservation Association concerning allegations of violations of new source review and permitting provisions of the Clean Air Act at the Independence and White Bluff coal-burning units, respectively. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims as well as other issues facing Entergy Arkansas’s fossil generation plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, is subject to approval by the U.S. District Court for the Eastern District of Arkansas. In October 2019 the District Court requested supplemental briefing on several issues to be resolved prior to addressing the motion to approve the
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settlement; that briefing was completed in May 2020. For further information about the settlement, see “Regional Haze” discussed below.
National Ambient Air Quality Standards
The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide, and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is classified as “marginal,” “moderate,” “serious,” or “severe.” When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.
Ozone Nonattainment
Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area that is not in attainment with the applicable NAAQS for ozone. The ozone nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Both Lewis Creek and the Montgomery County Power Station hold all necessary permits for construction and operation and comply with applicable air quality program regulations. Measures enacted to return the area to ozone attainment could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the ozone NAAQS.
Potential SO2Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. In Entergy’s utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana are designated as nonattainment. In August 2017 the EPA issued a letter indicating that East Baton Rouge and St. Charles parishes would be designated by December 31, 2020, as monitors were installed to determine compliance. In December 2020 the EPA designated East Baton Rouge, St. Charles, St. James, and West Baton Rouge parishes in Louisiana as attainment/unclassifiable, and, in Texas, Jefferson County as attainment/unclassifiable and Orange County as unclassifiable. Challenges to these final designations must be filed within 60 days of publication in the Federal Register. Entergy continues to monitor this situation.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2020 the EPA finalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. The final appropriate and necessary finding does not revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. Entergy will continue to monitor this situation.
Cross-State Air Pollution
In March 2005 the EPA finalized the Clean Air Interstate Rule (CAIR), which was intended to reduce SO2 and NOx emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule required a combination of capital investment to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy.
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Based on several court challenges, CAIR and its subsequent versions, now known as the Cross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions. In September 2016 the EPA finalized the CSAPR Update Rule to address interstate transport for the 2008 ozone NAAQS. Starting in 2017 the final rule requires reductions in summer nitrogen oxides (NOx) emissions. Several states, including Arkansas and Texas, filed a challenge to the Update Rule. In September 2019 the D.C. Circuit upheld the EPA’s underlying approach to the Update Rule, but determined that it was inconsistent with the Clean Air Act because it failed to include deadlines consistent with downwind states’ deadlines for attainment. The court remanded the rule to the EPA for further consideration, but did not vacate so the rule remains in effect pending the EPA’s further review. In October 2020 the EPA issued its proposal intended to address the D.C. Circuit’s remand. The draft rule proposes to finalize interstate transport obligations for 21 states. For nine states, including Arkansas, Mississippi, and Texas, the EPA proposes that additional emission reductions are not necessary. For 12 states, however, including Louisiana, the EPA proposes additional emission reductions through proposed reductions in the number of NOx emission allowances allocated to each state. Entergy, through its various trade associations, filed comments on the proposal and will continue to monitor the rulemaking and its potential impact on its facilities in Louisiana. If the October 2020 proposal is finalized, ozone season NOx emissions may become more expensive in Louisiana.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could result in a requirement to install SO2 and NOx pollution control technology as Best Available Retrofit Control Technology (BART) to continue operating certain of Entergy’s fossil generation units. The rule leaves certain CAVR determinations to the states.
In Arkansas, the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ) prepared a state implementation plan (SIP) for Arkansas facilities to implement its obligations under the CAVR. In April 2012 the EPA finalized a decision addressing the Arkansas Regional Haze SIP, in which it disapproved a large portion of the Arkansas plan, including the emission limits for NOx and SO2 at White Bluff. In April 2015 the EPA published a proposed federal implementation plan (FIP) for Arkansas, taking comment on requiring installation of scrubbers and low NOx burners to continue operating both units at the White Bluff plant and both units at the Independence plant and NOx controls to continue operating the Lake Catherine plant. Entergy filed comments by the deadline in August 2015. Among other comments, including opposition to the EPA’s proposed controls on the Independence units, Entergy proposed to meet more stringent SO2 and NOx limits at both White Bluff and Independence within three years of the effective date of the final FIP and to cease the use of coal at the White Bluff units at a later date.
In September 2016 the EPA published the final Arkansas Regional Haze FIP. In most respects, the EPA finalized its original proposal but shortened the time for compliance for installation of the NOx controls. The FIP required an emission limitation consistent with SO2 scrubbers at both White Bluff and Independence by October 2021 and NOx controls by April 2018. The EPA declined to adopt Entergy’s proposals related to ceasing coal use as an alternative to SO2 scrubbers for White Bluff SO2 BART. In November 2016, Entergy and other interested parties, including the State of Arkansas, filed petitions for administrative reconsideration and stay at the EPA as well as petitions for judicial review in the U.S. Court of Appeals for the Eighth Circuit. The Eighth Circuit granted the stay pending settlement discussions and pending the State’s development of a SIP that, if approved by the EPA, would replace the FIP. The state had proposed its replacement SIP in two parts: Part I considers NOx requirements, and Part II considers SO2 requirements. The EPA approved the Part I NOx SIP in January 2018. The Part I SIP requires that Entergy address NOx impacts on visibility via compliance with the Cross-State Air Pollution Rule ozone-season emission trading program. Arkansas has finalized a Part II SIP which has been approved by the EPA but is currently pending a state court appeal. That appeal has been stayed pending the outcome of a federal court case, which may resolve many of the issues on appeal. The final Part II SIP requires that Entergy achieve SO2 emission reductions via the use of low-sulfur coal at both White Bluff and Independence within three years. The
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Part II SIP also requires that Entergy cease to use coal at White Bluff by December 31, 2028 and notes the current planning assumption that Entergy’s Independence units will cease to use coal by December 31, 2030.
In January and February 2018, Entergy Arkansas, Entergy Mississippi, Entergy Power, and other co-owners received 60-day notice of intent to sue letters from the Sierra Club and the National Parks Conservation Association concerning allegations of violations of new source review and permitting provisions of the Clean Air Act at the Independence and White Bluff coal-burning units, respectively. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims and reducing the risk that Entergy Arkansas, as operator of Independence and White Bluff, might be compelled under the Clean Air Act’s regional haze program to install costly emissions control technologies. Consistent with the terms of the settlement and in many cases also the Part II SIP, Entergy Arkansas, along with co-owners, will begin using only low-sulfur coal at Independence and White Bluff by mid-2021; cease to use coal at White Bluff and Independence by the end of 2028 and 2030, respectively; cease operation of the remaining gas unit at Lake Catherine by the end of 2027; reserve the option to develop new generating sources at each plant site; and commit to install or propose to regulators at least 800 MWs of renewable generation by the end of 2027, with at least half installed or proposed by the end of 2022 (which includes two existing Entergy Arkansas projects) and with all qualifying co-owner projects counting toward satisfaction of the obligation. Under the settlement, the Sierra Club and the National Parks Conservation Association also waive certain potential existing claims under federal and state environmental law with respect to specified generating plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, is subject to approval by the U.S. District Court for the Eastern District of Arkansas. The EPA, which is allowed to comment on such a settlement agreement, has stated that it has no objections to the settlement. In November 2020 the court denied motions by the Arkansas Attorney General and the Arkansas Affordable Energy Coalition to intervene and to stay the proceedings. The proposed intervenors did not appeal the ruling. Still pending before the court is a motion by the plaintiffs to approve the settlement, in support of which Entergy made a filing. The Arkansas Attorney General also filed an application before the APSC in December 2018 seeking an investigation into the effects of the settlement. The Arkansas Affordable Energy Coalition filed to support the Arkansas Attorney General’s application, and Entergy Arkansas filed a motion to dismiss it. The application remains pending before the APSC. In October 2019 the District Court requested supplemental briefing on several issues prior to addressing the motion to approve the settlement; that briefing concluded in May 2020.
In Louisiana, Entergy has worked with the Louisiana Department of Environmental Quality (LDEQ) and the EPA to revise the Louisiana SIP for regional haze, which had been disapproved in part in 2012. The LDEQ submitted a revised SIP in February 2017. In May 2017 the EPA proposed to approve a majority of the revisions. In September 2017 the EPA issued a proposed SIP approval for the Nelson plant, requiring an emission limitation consistent with the use of low-sulfur coal, with a compliance date of January 22, 2021. The EPA issued final approval in December 2017. The EPA approval was appealed to the U.S. Court of Appeals for the Fifth Circuit. In October 2019 the Fifth Circuit affirmed the EPA’s SIP approval. A petition for rehearing filed by plaintiffs was denied by the Fifth Circuit. Plaintiffs did not petition for further review by the Supreme Court.
The second planning period (2018-2028) for the regional haze program requires states to examine sources for impacts on visibility and to prepare SIPs by 2021. Entergy received information collection requests from Arkansas and Louisiana requesting an evaluation of technical and economic feasibility of various NOx and SO2 control technologies for Independence, Nelson 6, and Ninemile. Responses to the information requests have been submitted to the respective state agencies.
New and Existing Source Performance Standards for Greenhouse Gas Emissions
In July 2019 the EPA released the Affordable Clean Energy Rule (ACE), which applies only to existing coal-fired electric generating units. The ACE determines that heat rate improvements are the best system of emission reductions and lists six candidate technologies for consideration by states at each coal unit. The rule and associated rulemakings by the EPA replace the Obama administration’s Clean Power Plan, which established
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national emissions performance rates for existing fossil-fuel fired steam electric generating units and combustion turbines. The ACE rule provides states discretion in determining how the best system for emission reductions applies to individual units, including through the consideration of technical feasibility and the remaining useful life of the facility. The ADEQ and the LDEQ have issued information collection requests to Entergy facilities to help the states collect the information needed to determine the best system of emission reductions for each facility. Entergy responded to the requests and will continue to monitor litigation challenging the rule. In January 2021 the U.S. Court of Appeals for the D.C. Circuit vacated ACE. The court held that ACE relied on an incorrect interpretation of the Clean Air Act that the statute expressly forecloses emission reduction approaches, such as emissions trading and generating shifting, that cannot be applied at and to the individual source. The court remanded ACE to the EPA for further consideration and also vacated the repeal of the Clean Power Plan. The vacatur will not be effective until the court issues its mandate which is being held until after disposition of any petitions for rehearing. Entergy is currently reviewing the court’s opinion.
In 2018 the EPA proposed a revision to the new source performance standard on greenhouse gas emissions that primarily impacts new coal units and, therefore, should not impact Entergy. In January 2021 the EPA finalized a pollutant-specific contribution finding for greenhouse gas emissions from new, modified, and reconstructed electric generating units. The rule establishes a three percent threshold for determining when a pollutant significantly contributes to air pollution and reaffirms the EPA’s position that the Clean Air Act Section 111(b) requires the EPA to make pollutant-specific significant contribution findings before promulgation of a new source performance standard. The EPA did not, however, finalize the new source performance standard on greenhouse gas emissions and intends to address the 2018 proposal in a future action.
Potential Legislative, Regulatory, and Judicial Developments
In addition to the specific instances described above, there are a number of legislative and regulatory initiatives concerning air emissions, as well as other media, that are under consideration at the federal, state, and local level. Because of the nature of Entergy’s business, the imposition of any of these initiatives could affect Entergy’s operations. Entergy continues to monitor these initiatives and activities in order to analyze their potential operational and cost implications. These initiatives include:
•designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;
•introduction of bills in Congress and development of regulations by the EPA proposing further limits on NOx, SO2, mercury, and carbon dioxide and other air emissions. New legislation or regulations applicable to stationary sources could take the form of market-based cap-and-trade programs, direct requirements for the installation of air emission controls onto air emission sources, or other or combined regulatory programs;
•efforts in Congress or at the EPA to establish a federal carbon dioxide emission tax, control structure, or unit performance standards;
•revisions to the estimates of the Social Cost of Carbon and its use for regulatory impact analysis of federal laws and regulations;
•implementation of the Regional Greenhouse Gas Initiative by several states in the northeastern United States and similar actions in other regions of the United States;
•efforts on the local, state, and federal level to codify renewable portfolio standards, clean energy standards, or a similar mechanism requiring utilities to produce or purchase a certain percentage of their power from defined renewable energy sources or energy sources with lower emissions;
•efforts to develop more stringent state water quality standards, effluent limitations for Entergy’s industry sector, stormwater runoff control regulations, and cooling water intake structure requirements;
•efforts to restrict the previously-approved continued use of oil-filled equipment containing certain levels of polychlorinated biphenyls (PCBs);
•efforts by certain external groups to encourage reporting and disclosure of environmental, social, and governance risk;
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•the listing of additional species as threatened or endangered, the protection of critical habitat for these species, and developments in the legal protection of eagles and migratory birds;
•the regulation of the management, disposal, and beneficial reuse of coal combustion residuals; and
•the regulation of the management and disposal and recycling of equipment associated with renewable and clean energy sources such as used solar panels, wind turbine blades, hydrogen usage, or battery storage.
Entergy continues to support national legislation that would increase planning certainty for electric utilities while addressing carbon dioxide emissions in an economy-wide, responsible, and flexible manner. By virtue of its proportionally large investment in low-emitting generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020. In 2020, Entergy succeeded in achieving its initial climate commitment to reduce carbon dioxide cumulative emissions by 20% from 2000 levels. Total carbon dioxide emissions representing Entergy’s ownership share of power plants and controllable power purchases in the United States were approximately 39.1 million tons in 2020 and 40.7 million tons in 2019. Since its original commitment in 2001, Entergy’s cumulative emissions are approximately 7.6% below its 2020 goal.
Entergy voluntarily conducted a climate scenario analysis and published a comprehensive report in March 2019. The report follows the framework and recommendations of the Task Force on Climate-related Disclosures, describing climate-related governance, strategy, risk management, and metrics and targets. Scenario analyses resulted in Entergy developing and publishing a new goal of reducing the Utility’s emission rate by 50 percent from 2000 levels by 2030. In September 2020, Entergy committed to achieving net-zero carbon emissions by 2050, while continuing its commitment to grid reliability and affordability for customers. In December 2020, Entergy published a report regarding this long-term commitment that describes its approach and technology point-of-view. Technology research and development, innovation, and advancement are critical to Entergy’s ability to meet this climate commitment.
Entergy participates in the M.J. Bradley & Associates’ Annual Benchmarking Air Emissions Report, an annual analysis of the 100 largest U.S. electric power producers. The report is available on the M.J. Bradley website. Entergy’s annual greenhouse gas emissions inventory is also third-party verified, and that certification is made available on the American Carbon Registry website. Entergy participates annually in the Dow Jones Sustainability Index and in 2020 was listed on the North American Index. Entergy has been listed on the World or North American Index, or both, for nineteen consecutive years. Entergy also participated in the 2020 CDP and CDP Water evaluations, receiving a ‘B’ for both responses.
Clean Water Act
The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act) provide the statutory basis for the National Pollutant Discharge Elimination System permit program, section 402, and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The Clean Water Act requires virtually all discharges of pollutants to waters of the United States to be permitted. Section 316(b) of the Clean Water Act regulates cooling water intake structures, section 401 of the Clean Water Act requires a water quality certification from the state in support of certain federal actions and approvals, and section 404 regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.
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Steam Electric Effluent Guidelines
The 2015 Steam Electric Effluent Limitations Guidelines (ELG) rule required, among other things, that there be no discharge of bottom ash transport water. In October 2020 the EPA issued its final rule revision on bottom ash transport water allowing the discharge of up to 10% system volume for certain purge waters, including storm events and non-routine operations. The final rule requires compliance as soon as possible beginning October 31, 2021, but no later than December 31, 2025. Several challenges to the final rule have been filed. Additionally, the Fifth Circuit Court of Appeals previously vacated and remanded the provisions of the rule related to legacy wastewater and leachate, which the EPA plans to address in a separate rulemaking. Despite the final rule and pending challenges, Entergy is implementing projects at its White Bluff and Independence plants to convert to zero-discharge systems to comply with the ELG rule and the coal combustion residuals restrictions on impoundments. Additionally, the Nelson Unit 6 facility is implementing operational and maintenance measures to minimize the potential for discharge of bottom ash transport water from the existing bottom ash handling system at the site, and is reviewing the effectiveness of these changes for compliance with the requirements of the October 2020 final rule.
Federal Jurisdiction of Waters of the United States
In February 2019 the EPA published its proposed revised definition of Waters of the United States, which proposes to narrow the scope of Clean Water Act jurisdiction, as compared to a 2015 definition which had been stayed by several federal courts. The final rule was released in January 2020 and effective in June 2020. In October 2019 the EPA repealed the 2015 rule and re-codified the pre-existing regulations. That rule was effective late December 2019. Numerous challenges have been filed against both rules.
Groundwater at Certain Nuclear Sites
The NRC requires nuclear power plants to monitor and report regularly the presence of radioactive material in the environment. Entergy joined other nuclear utilities and the Nuclear Energy Institute in 2006 to develop a voluntary groundwater monitoring and protection program. This initiative began after detection of very low levels of radioactive material, primarily tritium, in groundwater at several plants in the United States. Tritium is a radioactive form of hydrogen that occurs naturally and is also a byproduct of nuclear plant operations. In addition to tritium, other radionuclides have been found in site groundwater at nuclear plants.
As part of the groundwater monitoring and protection program, Entergy has: (1) performed reviews of plant groundwater characteristics (hydrology) and historical records of past events on site that may have potentially impacted groundwater; (2) implemented fleet procedures on how to handle events that could impact groundwater; and (3) installed groundwater monitoring wells and began periodic sampling. The program also includes protocols for notifying local officials if contamination is found. To date, radionuclides such as tritium have been detected at Arkansas Nuclear One, Indian Point, Palisades, Grand Gulf, and River Bend. Each of these sites has installed groundwater monitoring wells and implemented a program for testing groundwater at the sites for the presence of tritium and other radionuclides. Based on current information, the concentrations and locations of radionuclides detected at these plants pose no threat to public health or safety, but each site continues to evaluate the results from its groundwater monitoring program.
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint, and several liability on responsible parties. Many states have adopted programs similar to CERCLA. Entergy subsidiaries in the Utility and Entergy Wholesale Commodities businesses have sent waste materials to various
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disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been or will be sold to decommissioning companies. In addition, environmental laws now regulate certain of Entergy’s operating procedures and maintenance practices that historically were not subject to regulation. Some disposal sites used by Entergy subsidiaries have been the subject of governmental action under CERCLA or similar state programs, resulting in site clean-up activities. Entergy subsidiaries have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs. The affected Entergy subsidiaries have established provisions for the liabilities for such environmental clean-up and restoration activities. Details of potentially material CERCLA and similar state program liabilities are discussed in the “Other Environmental Matters” section below.
Coal Combustion Residuals
In June 2010 the EPA issued a proposed rule on coal combustion residuals (CCRs) that contained two primary regulatory options: (1) regulating CCRs destined for disposal in landfills or received (including stored) in surface impoundments as so-called “special wastes” under the hazardous waste program of Resource Conservation and Recovery Act (RCRA) Subtitle C; or (2) regulating CCRs destined for disposal in landfills or surface impoundments as non-hazardous wastes under Subtitle D of RCRA. Under both options, CCRs that are beneficially reused in certain processes would remain excluded from hazardous waste regulation. In April 2015 the EPA published the final CCR rule with the material being regulated under the second scenario presented above - as non-hazardous wastes regulated under RCRA Subtitle D.
The final regulations create new compliance requirements including modified storage, new notification and reporting practices, product disposal considerations, and CCR unit closure criteria. Entergy believes that on-site disposal options will be available at its facilities, to the extent needed for CCR that cannot be transferred for beneficial reuse. As of December 31, 2020, Entergy has recorded asset retirement obligations related to CCR management of $20.1 million.
In December 2016 the Water Infrastructure Improvements for the Nation Act (WIIN Act) was signed into law, which authorizes states to regulate coal ash rather than leaving primary enforcement to citizen suit actions. States may submit to the EPA proposals for a permit program.
Pursuant to the EPA Rule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area, but has not indicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and detection monitoring will continue as the rule requires. In late-2017, Entergy determined that certain in-ground wastewater treatment system recycle ponds at its White Bluff and Independence facilities require management under the new EPA regulations. Consequently, in order to move away from using the recycle ponds, White Bluff and Independence each have installed a new permanent bottom ash handling system that does not fall under the CCR rule. As of November 2020, both sites are operating the new system and no longer are sending waste to the recycle ponds. Each site has commenced closure of one of its two recycle ponds, with the remaining pond being held in reserve during initial operation of the new bottom ash handling system. Closure of the remaining recycle pond at each site will commence as soon as possible, but no later than April 11, 2021, which is the deadline under the finalized CCR rule to commence closure of any unlined recycle ponds. Any potential requirements for corrective action or operational changes under the new CCR rule continue to be assessed. Notably, ongoing litigation has resulted in the EPA’s continuing review of the rule. Consequently, the nature and cost of additional corrective action requirements may depend, in part, on the outcome of the EPA’s review.
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Other Environmental Matters
Entergy Louisiana and Entergy Texas
Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, currently is involved in the second phase of the remedial investigation of the Lake Charles Service Center site, located in Lake Charles, Louisiana. A manufactured gas plant (MGP) is believed to have operated at this site from approximately 1916 to 1931. Coal tar, a by-product of the distillation process employed at MGPs, apparently was routed to a portion of the property for disposal. The same area also has been used as a landfill. In 1999, Entergy Gulf States, Inc. signed a second administrative consent order with the EPA to perform a removal action at the site. Removal actions addressed contaminated source material, soil, and sediment and included capping certain soil on and off-site. In 2002 approximately 7,400 tons of contaminated soil and debris were excavated and disposed of from an area within the service center. In 2003 a cap was constructed over the remedial area to prevent the migration of contamination to the surface. In August 2005 an administrative order was issued by the EPA requiring that a 10-year groundwater study be conducted at this site. The groundwater monitoring study commenced in January 2006. The EPA released the second Five Year Review in 2015. In that review, the EPA indicated that the remediation technique was insufficient and that Entergy would need to utilize other remediation technologies on the site. In July 2015, Entergy submitted a Focused Feasibility Study to the EPA outlining the potential remedies and suggesting installation of the new remedial method, a waterloo barrier. The estimated cost for this remedy is approximately $2 million, to be allocated between Entergy Louisiana and Entergy Texas. In early 2017 the EPA indicated that the waterloo barrier may not be necessary and requested revisions to the Focused Feasibility Study. The EPA released the third Five Year Review in late-2019 confirming that a new remedial method is not necessary but requiring continuation of the current groundwater monitoring. The site’s remedy includes monitored natural attenuation of groundwater, and institutional controls to restrict groundwater and land use. The EPA has determined that no additional actions are needed for the remedy to be protective over the long-term, and the remedy is protective of human health and the environment.
Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas
The Texas Commission on Environmental Quality (TCEQ) notified Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas that the TCEQ believes those entities are potentially responsible parties (PRPs) concerning contamination existing at the San Angelo Electric Service Company (SESCO) facility in San Angelo, Texas. The facility operated as a transformer repair and scrapping facility from the 1930s until 2003. Both soil and groundwater contamination existed at the site. Entergy subsidiaries sent transformers to this facility. Entergy Arkansas, Entergy Louisiana, and Entergy Texas responded to an information request from the TCEQ. Entergy Louisiana and Entergy Texas joined a group of PRPs responding to site conditions in cooperation with the State of Texas, creating cost allocation models based on review of SESCO documents and employee interviews, and investigating contribution actions against other PRPs. Entergy Louisiana and Entergy Texas have agreed to contribute to the remediation of contaminated soil and groundwater at the site in a measure proportionate to those companies’ involvement at the site. Current estimates, although variable depending on ultimate remediation design and performance, indicate that Entergy’s total share of remediation costs likely will be approximately $1.5 million to $2 million. Groundwater monitoring wells at the site were plugged and abandoned in December 2019 following receipt of a certificate of completion issued by the TCEQ. Site decommissioning activities are complete and final disposition of the property will be determined at a later time.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas
The EPA notified Entergy that the EPA believes Entergy is a PRP concerning PCB contamination at the F.J. Doyle Salvage facility in Leonard, Texas. The facility operated as a scrap salvage business during the 1970s to the 1990s. In May 2018 the EPA investigated the site surface and sub-surface soils and, in November 2018 the EPA conducted a removal action, including disposal of PCB contaminated soils. Entergy responded to the EPA’s information requests in May and July 2019. In November 2020 the EPA sent Entergy and other PRPs a demand
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letter seeking reimbursement for response costs totaling $4 million expended at the site. The demand letter is being evaluated and liability and PRP allocation of response costs are yet to be determined.
Entergy Texas
In December 2016 a transformer inside the Hartburg, Texas Substation had an internal fault resulting in a release of approximately 15,000 gallons of non-PCB mineral oil. Cleanup ensued immediately; however, rain caused much of the oil to spread across the substation yard and into a nearby wetland. The TCEQ and the National Response Center were immediately notified, and the TCEQ responded to the site approximately two hours after the cleanup was initiated. The remediation liability is estimated at $2.2 million; however, this number could fluctuate depending on the remediation extent and wetland mitigation requirements. In July 2017, Entergy entered into the Voluntary Cleanup Program with the TCEQ. In November 2017, additional soil sampling was completed in the wetland area and, in February 2018, a site summary report of findings was submitted to the TCEQ. The TCEQ responded in June 2018 and requested an ecological exclusion criteria checklist/Tier II screening-level ecological risk assessment, and additional site assessment, additional soil samples, groundwater samples, and some additional diagrams and maps. In October 2018, Entergy submitted the requested information to the TCEQ. In January 2019 the TCEQ responded with another request for information. In March 2019, Entergy submitted the requested information to the TCEQ. In August 2019 the TCEQ responded with a request for additional information including an Affected Property Assessment Report (APAR) and water well survey. The TCEQ has agreed that the necessity of the water well survey is dependent on the results of the groundwater resampling that will occur. Groundwater sampling was completed in December 2019 and results were submitted to the TCEQ for review. Based on the groundwater sampling results, the TCEQ confirmed in February 2020 that a water well survey is not necessary and requested the APAR and an Ecological Risk Assessment by August 2020. Due to COVID-19 delays, the TCEQ extended the APAR and Ecological Risk Assessment submittal dates to December 2020, which Entergy timely met.
Litigation
Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but certain states in which Entergy operates have proven to be unusually litigious environments. Judges and juries in Louisiana, Mississippi, and Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. The litigation environment in these states poses a significant business risk to Entergy.
Asbestos Litigation(Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)
See Note 8 to the financial statements for a discussion of this litigation.
Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
See Note 8 to the financial statements for a discussion of these proceedings.
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Human Capital
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2020, Entergy subsidiaries employed 13,400 people.
| | | | | |
Utility: | |
Entergy Arkansas | 1,244 | |
Entergy Louisiana | 1,654 | |
Entergy Mississippi | 750 | |
Entergy New Orleans | 303 | |
Entergy Texas | 658 | |
System Energy | — | |
Entergy Operations | 3,529 | |
Entergy Services | 3,859 | |
Entergy Nuclear Operations | 1,356 | |
Other subsidiaries | 47 | |
Total Entergy | 13,400 | |
Approximately 3,900 employees are represented by the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the International Brotherhood of Teamsters, the United Government Security Officers of America, and the International Union, Security, Police, and Fire Professionals of America.
Below is the breakdown of Entergy’s employees by gender and race/ethnicity:
| | | | | | | | | | | |
Gender (%) | 2020 | | 2019 |
Female | 21 | | 20 |
Male | 79 | | 80 |
| 100 | | 100 |
| | | | | | | | | | | |
Race/Ethnicity (%) | 2020 | | 2019 |
White | 78 | | 79 |
Black/African American | 15 | | 15 |
Hispanic/Latino | 3 | | 2 |
Asian | 2 | | 2 |
Other | 2 | | 2 |
| 100 | | 100 |
Entergy’s Approach to Human Resources
Entergy’s people and culture enable its success; that is why acquiring, retaining, and developing talent are important components of Entergy’s human resources strategy. Entergy focuses on an approach that includes, among other things, governance and oversight; safety; organizational health, including diversity, inclusion and belonging; and talent management.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Governance and Oversight
Ensuring that workplace processes support the desired culture and strategy begins with the Board of Directors and the Office of the Chief Executive. The Personnel Committee establishes priorities and reviews performance on a range of topics. It oversees Entergy’s incentive plan design and administers its executive compensation plans to incentivize the behaviors and outcomes that support achievement of Entergy’s corporate objectives. Annually, it reviews executive performance, development and succession plans to align a high performing executive team with Entergy’s priorities. The Personnel Committee also oversees Entergy’s performance through regular briefings on a wide variety of human resources topics including Entergy’s safety culture and performance; organizational health; and diversity, inclusion, and belonging initiatives and performance.
Other committees of the Board oversee other key aspects of Entergy’s culture. For example, the Audit Committee reviews reports on ethics and compliance training and performance, as well as regular reports on calls made to Entergy’s ethics line and related investigations. To maximize the sharing of information and facilitate the participation of all Board members in these discussions, the Board schedules its regular committee meetings in a manner such that all directors can attend.
The Office of the Chief Executive, which includes the Senior Vice President and Chief Human Resources Officer, ensures annual business plans are designed to support Entergy’s talent objectives, reviews workforce-related metrics, and regularly discusses the development, succession planning, and performance of their direct reports and other company officers.
Safety
Entergy’s safety objective is: Everyone Safe. All Day. Every Day. While the COVID-19 pandemic and historical hurricane season presented significant challenges, Entergy’s safety strategy and commitment to excellence showed results in 2020. Entergy employees achieved a total recordable incident rate of 0.40 in 2020 compared to 0.56 in 2019 and 0.48 in 2018. The recordable incident rate equals the number of recordable incidents per 100 full-time equivalents. Recordable incidents include fatalities, lost-time accidents, restricted-duty accidents, and medical attentions and is not inclusive of potential work-related COVID-19 cases. This marked improvement in total recordable incident rate placed Entergy in top-decile in safety performance when benchmarked amongst peers within the Edison Electric Institute.
Organizational Health, including Diversity, Inclusion and Belonging
Entergy believes that organizational health fosters an engaged and productive culture that positions Entergy to deliver sustainable value to its stakeholders. Entergy measures its progress through an organizational health survey coordinated by an external third party. Since initially administering the survey in 2014, Entergy improved from an initial score of 49 (fourth quartile) to a score in 2020 of 72 (near top quartile). In addition to significantly improved scores, initial employee participation of 66 percent in 2014 rose to and remains at 90 percent in 2018-2020.
Entergy believes that a culture focused on diversity, inclusion, and belonging drives foundational engagement. Entergy is committed to developing and retaining a workforce that reflects the rich diversity of the communities it serves. In 2019, Entergy embarked on a three-year phased approach to enhance inclusion for individuals and teams. Among other actions, the primary focus of its 2020 actions was taking a stand against social injustice, reinforcing expectations, training and leading by example, starting at the top of the organization and cascading through management ranks.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Talent Management
Entergy’s focus on talent management is organized in three areas: developing and attracting a diverse pool of talent, equipping its leaders to develop the organization, and building premier utility capability through employee performance management and succession programs. Entergy believes that developing a diverse pool of local talent equipped with the skills needed, today and in the future, and reflecting the communities Entergy serves will give it a long-term competitive advantage. The focus of Entergy’s leadership development programs is to equip managers with the skills needed to effectively develop their teams and improve the leader-employee relationship. Entergy’s talent development infrastructure, which includes a combination of business function-specific and enterprise-wide learning and development programs, is designed to ensure Entergy has qualified staff with the skills, experiences, and behaviors needed to perform today and prepare for the future. Entergy strives to achieve its strategic priorities by aligning and enhancing team and individual performance with business objectives, effectively deploying talent through succession planning, and managing workforce transitions.
Availability of SEC filings and other information on Entergy’s website
Entergy electronically files reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies, and amendments to such reports. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. Copies of the reports that Entergy files with the SEC can be obtained at the SEC’s website.
Entergy uses its website, http://www.entergy.com, as a routine channel for distribution of important information, including news releases, analyst presentations and financial information. Filings made with the SEC are posted and available without charge on Entergy’s website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These filings include annual and quarterly reports on Forms 10-K and 10-Q (including related filings in Inline XBRL format) and current reports on Form 8-K; proxy statements; and any amendments to those reports or statements. All such postings and filings are available on Entergy’s Investor Relations website free of charge. Entergy is providing the address to its internet site solely for the information of investors and does not intend the address to be an active link. The contents of the website are not incorporated into this report.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
RISK FACTORS
See “RISK FACTOR SUMMARY” in Part I Item 1 for a summary of Entergy’s and the Registrant Subsidiaries’ risk factors.
Investors should review carefully the following risk factors and the other information in this Form 10-K. The risks that Entergy faces are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect Entergy’s financial condition, results of operations, and liquidity. See “FORWARD-LOOKING INFORMATION.”
Utility Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The impacts of the COVID-19 pandemic and responsive measures taken on Entergy’s and its Utility operating companies’ business, results of operations, and financial condition are highly uncertain and cannot be predicted.
In December 2019 a novel strain of coronavirus was reported to have surfaced in Wuhan, China. Since then, COVID-19 has spread throughout most countries in the world, including the United States. Public health officials in the United States have both recommended and mandated wearing of masks, precautions to mitigate the spread of COVID-19, including prohibitions on congregating in heavily-populated areas, mandated closure or limitations on the functions of non-essential business, and shelter-in-place orders or similar measures, including throughout Entergy’s service areas. While some of these mitigation measures have been lifted, it is unclear how long certain forms of mitigation measures will remain in place, whether they will be reinstated in the future, and how they will ultimately impact the general economy, Entergy’s customers, and its operations.
Entergy and its Utility operating companies have experienced a decline in commercial and industrial sales and an increase in arrearages and bad debt expense due to non-payment by customers, and expect such reduced levels of sales and increased arrearages and bad debt expense to continue, the extent and duration of which management cannot predict. The Utility operating companies temporarily suspended disconnecting customers for non-payment of bills, and the suspension remains in place at Entergy Arkansas, has been re-instituted at Entergy New Orleans, and could be re-instituted at the other Utility operating companies should their regulators mandate. While they are working with regulators to ensure ultimate recovery for those and other COVID-19 related costs, the amount, method, and timing of such recovery is unknown. Entergy and its Registrant Subsidiaries also could experience, and in some cases have experienced, among other challenges, supply chain, vendor, and contractor disruptions; delays in completion of capital or other construction projects, maintenance, and other operations activities, including prolonged or delayed outages; delays in regulatory proceedings; workforce availability, health or safety issues; increased storm recovery costs; increased cybersecurity risks as a result of many employees telecommuting; increased late or uncollectible customer payments; volatility in the credit or capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available credit facilities); or other adverse impacts on their ability to execute on business strategies and initiatives.
A sustained or further economic decline could adversely impact Entergy’s and the Utility operating companies’ liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, or increased bad debt expense. The Utility operating companies also may experience regulatory outcomes that require them to postpone planned investment and otherwise reduce costs due to the impact of the COVID-19 pandemic on their customers. In addition, if the COVID-19 pandemic continues to create disruptions or turmoil in the credit or financial markets, or adversely impacts Entergy’s credit metrics or ratings, such developments could adversely affect its ability to access capital on favorable terms and continue to meet its
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Entergy Corporation, Utility operating companies, and System Energy
liquidity needs, or cause a decrease in the value of its defined benefit pension trust funds, as well as its nuclear decommissioning trust funds, all of which are highly uncertain and cannot be predicted.
Entergy cannot predict the extent or duration of the outbreak, the impact of new variants of COVID-19, the timing, availability, distribution or effectiveness of a vaccine, anti-viral or other treatments for COVID-19, governmental responsive measures, or the extent of the effects or ultimate impacts on the global, national or local economy, the capital markets, or its customers, suppliers, operations, financial condition, results of operations, or cash flows.
The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that can be lengthy and subject to appeal, potentially resulting in delays in effecting rate changes, lengthy litigation and uncertainty as to ultimate results.
The Utility operating companies are regulated on a cost-of-service and rate of return basis and are subject to statutes and regulatory commission rules and procedures. The rates that the Utility operating companies and System Energy charge reflect their capital expenditures, operations and maintenance costs, allowed rates of return, financing costs, and related costs of service. These rates significantly influence the financial condition, results of operations, and liquidity of Entergy and each of the Utility operating companies and System Energy. These rates are determined in regulatory proceedings and are subject to periodic regulatory review and adjustment, including adjustment upon the initiative of a regulator or affected stakeholders.
In addition, regulators may initiate proceedings to investigate the prudence of costs in the Utility operating companies’ and System Energy’s base rates and examine, among other things, the reasonableness or prudence of the companies’ operation and maintenance practices, level of expenditures (including storm costs and costs associated with capital projects), allowed rates of return and rate base, proposed resource acquisitions, and previously incurred capital expenditures that the operating companies seek to place in rates. The regulators may disallow costs subject to their jurisdiction found not to have been prudently incurred or found not to have been incurred in compliance with applicable tariffs, creating some risk to the ultimate recovery of those costs. Regulatory proceedings relating to rates and other matters typically involve multiple parties seeking to limit or reduce rates. Traditional base rate proceedings, as opposed to formula rate plans, generally have long timelines, are primarily based on historical costs, and may or may not be limited in scope or duration by statute. The length of these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates, such that the Utility operating companies may not fully recover all costs during the rate effective period and the Utility operating companies may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings.
The Utility operating companies have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including the operation of their assets and infrastructure or the quality of their service. Criticism or adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view the applicable operating company in a favorable light and could potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements.
The base rates of Entergy Texas are established largely in traditional base rate case proceedings.Between base rate proceedings, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs.These riders include a distribution cost recovery factor rider mechanism for the recovery of distribution-related capital investment and certain non-fuel MISO charges, a transmission cost recovery factor rider mechanism for the recovery of transmission-related capital investments, a generation cost recovery rider mechanism for the recovery of generation-related capital investments, and a fixed fuel factor mechanism for the recovery of MISO fuel and energy-related costs.Entergy Texas also is required to make a filing every three years,
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at a minimum, reconciling its fuel and purchased power costs and fuel factor revenues.In the course of this reconciliation, the PUCT determines whether eligible fuel and fuel-related expenses and revenues are necessary and reasonable, and makes a prudence finding for each of the fuel-related contracts for the reconciliation period.Entergy Texas also is required to file full base rate case proceedings every four years and within eighteen months of utilizing its generation cost recovery rider for investments above $200 million.
Between base rate cases, Entergy Arkansas and Entergy Mississippi are able to adjust base rates annually through formula rate plans that utilize a forward test year (Entergy Arkansas) or forward-looking features (Entergy Mississippi).In response to Entergy Arkansas’s application for a general change in rates in 2015, the APSC approved the formula rate plan tariff proposed by Entergy Arkansas including its use of a projected year test period and an initial five-year term.The initial five-year term expires in 2021. Entergy Arkansas has requested APSC approval of the extension of the formula rate plan tariff for an additional five years through 2026.If Entergy Arkansas’s formula rate plan were terminated or not extended beyond the initial term, Entergy Arkansas could file an application for a general change in rates that may include a request for continued regulation under a formula rate review mechanism.If Entergy Mississippi’s formula rate plan is terminated, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan.Entergy Arkansas and Entergy Mississippi recover fuel and purchased energy and certain non-fuel costs through other APSC-approved and MPSC-approved tariffs, respectively.
Entergy Louisiana historically sets electric base rates annually through a formula rate plan using an historic test year.The form of the formula rate plan, on a combined basis, was approved in connection with the business combination of Entergy Louisiana and Entergy Gulf States Louisiana and largely followed the formula rate plans that were approved by the LPSC in connection with the full electric base rate cases filed by those companies in February 2013.The formula rate plan was most recently extended through the test year 2019; certain modifications were made in that extension, including a decrease to the allowed return on equity and the addition of a transmission cost recovery mechanism.The formula rate plan continues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities and purchase power agreements approved by the LPSC and as noted, for certain transmission investment, among other items.MISO fuel and energy-related costs are recoverable in Entergy Louisiana’s fuel adjustment clause.Entergy Louisiana has a pending request to extend its formula rate plan with certain modifications, including implementation of a distribution investment recovery mechanism and use of end of period rate base.In the event that the electric formula rate plan is not renewed or extended, Entergy Louisiana would revert to the more traditional rate case environment.
Entergy New Orleans previously operated under a formula rate plan that ended with the 2011 test year.Based on a settlement agreement approved by the City Council, with limited exceptions, the base rates of Entergy New Orleans were frozen until rates were implemented in connection with the base rate case filed by Entergy New Orleans in 2018.In November 2019 the City Council issued a resolution resolving the rate case, with rates to become effective retroactive to August 2019.The resolution allows Entergy New Orleans to implement a three-year formula rate plan, beginning with the 2019 test year as adjusted for forward-looking known and measurable changes.In November 2020 the City Council issued a resolution approving a settlement of the 2018 rate case.As part of this settlement, Entergy New Orleans agreed to postpone the filing of its first test year formula rate plan to 2021 and, in return, to be provided an additional test year for the three-year cycle.See Note 2 to the financial statements for further discussion.
The rates of System Energy are established by the FERC, and the costs allowed to be charged pursuant to these rates are, in turn, passed through to the participating Utility operating companies through the Unit Power Sales Agreement, which has monthly billings that reflect the current operating costs of, and investment in, Grand Gulf. Retail regulators and other parties may seek to initiate proceedings at FERC to investigate the prudence of costs included in the rates charged under the Unit Power Sales Agreement and examine, among other things, the
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
reasonableness or prudence of the operation and maintenance practices, level of expenditures, allowed rates of return and rate base, and previously incurred capital expenditures. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a separate request for FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings nor can it predict whether any outcome could have a material effect on Entergy’s or System Energy’s results of operations, financial condition or liquidity. See Note 2 to the financial statements for further discussion of the proceedings. System Energy has received FERC acceptance for billing protocols to provide retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
The Utility operating companies and System Energy, and the energy industry as a whole, have experienced a period of rising costs and investments, and an upward trend in spending, especially with respect to infrastructure investments, which is likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms. For information regarding rate case proceedings and formula rate plans applicable to the Utility operating companies, see Note 2 to the financial statements.
Changes to state or federal legislation or regulation affecting electric generation, electric and natural gas transmission, distribution, and related activities could adversely affect Entergy and the Utility operating companies’ financial position, results of operations, or cash flows and their utility businesses.
If legislative and regulatory structures evolve in a manner that erodes the Utility operating companies’ exclusive rights to serve their regulated customers, they could lose customers and sales and their results of operations, financial position, or cash flows could be materially affected. Additionally, technological advances in energy efficiency and distributed energy resources are reducing the costs of these technologies and together with ongoing state and federal subsidies, the increasing penetration of these technologies could result in reduced sales by the Utility operating companies. Such loss of sales could put upward pressure on rates, resulting in adverse regulatory actions to mitigate such effects on rates. Entergy and the Utility operating companies cannot predict if or when they may be subject to changes in legislation or regulation, or the extent and timing of reductions of the cost of distributed energy resources, nor can they predict the impact of these changes on their results of operations, financial position, or cash flows.
The Utility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings.
The Utility operating companies recover their fuel, purchased power, and associated costs from their customers through rate mechanisms subject to periodic regulatory review and adjustment. Because regulatory review can result in the disallowance of incurred costs found not to have been prudently incurred, including the cost of replacement power purchased when generators experience outages or when planned outages are extended, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs, particularly when there are substantial or sudden increases in such costs. Regulators also may initiate proceedings to investigate the continued usage or the adequacy and operation of the fuel and purchased power recovery clauses of the Utility operating companies and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.
The Utility operating companies’ cash flows can be negatively affected by the time delays between when gas, power, or other commodities are purchased and the ultimate recovery from customers of the costs in rates. On occasion, when the level of incurred costs for fuel and purchased power rises very dramatically, some of the Utility operating companies may agree to defer recovery of a portion of that period’s fuel and purchased power costs for recovery at a later date, which could increase the near-term working capital and borrowing requirements of those companies. For a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power costs recovery, see Note 2 to the financial statements.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
There remains uncertainty regarding the effect of the termination of the System Agreement on the Utility operating companies.
The Utility operating companies historically engaged in the coordinated planning, construction, and operation of generating resources and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that had been approved by the FERC. The System Agreement terminated in its entirety on August 31, 2016.
There remains uncertainty regarding the long-term effect of the termination of the System Agreement on the Utility operating companies because of the significant effect of the agreement on the generation and transmission functions of the Utility operating companies and the significant period of time (over 30 years) that it had been in existence. In the absence of the System Agreement, there remains uncertainty around the effectiveness of governance processes and the potential absence of federal authority to resolve certain issues among the Utility operating companies and their retail regulators.
In addition, although the System Agreement terminated in its entirety in August 2016, there are a few outstanding System Agreement proceedings at the FERC and at the D.C. Circuit that may require future adjustments, including challenges to the level and timing of payments made by Entergy Arkansas under the System Agreement. The outcome and timing of these FERC proceedings and resulting recovery and impact on rates cannot be predicted at this time.
For further information regarding the regulatory proceedings relating to the System Agreement, see Note 2 to the financial statements.
The Utility operating companies are subject to economic risks associated with participation in the MISO markets and the allocation of transmission upgrade costs. The operation of the Utility operating companies’ transmission system pursuant to the MISO RTO tariff and their participation in the MISO RTO’s wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
On December 19, 2013, the Utility operating companies integrated into the MISO RTO. MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. The Utility operating companies are subject to economic risks associated with participation in the MISO markets. MISO tariff rules and system conditions, including transmission congestion, could affect the Utility operating companies’ ability to sell capacity, energy, and/or ancillary services in certain regions and/or the economic value of such sales, or the cost of serving the Utility operating companies’ respective loads, and MISO market rules may change in ways that cause additional risk.
The Utility operating companies participate in the MISO regional transmission planning process and are subject to risks associated with planning decisions that MISO makes in the exercise of control over the planning of the Utility operating companies’ transmission assets that are under MISO’s functional control. The Utility operating companies pay transmission rates that reflect the cost of transmission projects that the Utility operating companies do not own, which could increase cash or financing needs. In addition to the cash and financing-related risks arising from the potential additional cost allocation to the Utility operating companies from transmission projects of others, there is a risk that the Utility operating companies’ business and financial position could be harmed as a result of lost investment opportunities and other effects that flow from an increased number of competitive projects being approved and constructed that are interconnected with their transmission systems. Further, the terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets, the
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
allocation of transmission upgrade costs, the MISO-wide allowed base rate of return on equity, and any required MISO-related charges and credits are subject to regulation by the FERC. The operation of the Utility operating companies’ transmission system pursuant to the MISO tariff and their participation in the MISO wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements. In addition, orders from each of the Utility operating companies’ respective retail regulators generally require that the Utility operating companies make periodic filings, or generally allow the retail regulator to direct the making of such filings, setting forth the results of analysis of the costs and benefits realized from MISO membership as well as the projected costs and benefits of continued membership in MISO and/or requesting approval of their continued membership in MISO. These filings have been submitted periodically by each of the Utility operating companies as required by their respective retail regulators, and the outcome of the resulting proceedings may affect the Utility operating companies’ continued membership in MISO.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather (including from Hurricane Laura, Hurricane Delta, and Hurricane Zeta), or the impact on customer bills of permitted storm cost recovery, could have material effects on Entergy and its Utility operating companies.
Entergy’s and its Utility operating companies’ results of operations, liquidity, and financial condition can be materially affected by the destructive effects of severe weather. Severe weather can also result in significant outages for the customers of the Utility operating companies and, therefore, reduced revenues for the Utility operating companies during the period of the outages. A delay or failure in recovering amounts for storm restoration costs incurred or revenues lost as a result of severe weather could have a material effect on Entergy and those Utility operating companies affected by severe weather. In addition, the recovery of major storm restoration costs from customers could effectively limit our ability to make planned capital or other investments due to the impact of such storm cost recovery on customer bills.
In August and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of the Utility’s service territories in Louisiana, including New Orleans, Texas, and to a lesser extent, in Arkansas and Mississippi. The storms resulted in widespread power outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild. Total restoration costs for the repair and/or replacement of the electrical system damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta are currently estimated to be approximately $2.4 billion. Because Entergy has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Nuclear Operating, Shutdown, and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)
Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities must consistently operate their nuclear power plants at high capacity factors in order to be successful, and lower capacity factors could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Nuclear capacity factors significantly affect the results of operations of certain Utility operating companies, System Energy, and Entergy Wholesale Commodities. Nuclear plant operations involve substantial fixed operating
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
costs. Consequently, to be successful, a plant owner must consistently operate its nuclear power plants at high capacity factors, consistent with safety requirements. For the Utility operating companies that own nuclear plants, lower capacity factors can increase production costs by requiring the affected companies to generate additional energy, sometimes at higher costs, from their owned or contractually controlled facilities or purchase additional energy in the spot or forward markets in order to satisfy their supply needs. For the Entergy Wholesale Commodities nuclear plants, lower capacity factors directly affect revenues and cash flow from operations. Entergy Wholesale Commodities’ forward sales are comprised of various hedge products, many of which have some degree of operational-contingent price risk. Certain unit-contingent contracts guarantee specified minimum capacity factors. In the event plants with these contracts were operating below the guaranteed capacity factors, Entergy would be subject to price risk for the undelivered power. Further, Entergy Wholesale Commodities’ nuclear forward sales contracts can also be on a firm LD basis, which subjects Entergy to increasing price risk as capacity factors decrease. Many of these firm hedge products have damages risk.
Certain of the Utility operating companies and System Energy periodically shut down their nuclear power plants to replenish fuel. Plant maintenance and upgrades are often scheduled during such refueling outages. If refueling outages last longer than anticipated or if unplanned outages arise, Entergy’s and their results of operations, financial condition, and liquidity could be materially affected.
Outages at nuclear power plants to replenish fuel require the plant to be “turned off.” Refueling outages generally are planned to occur once every 18 to 24 months. Plant maintenance and upgrades are often scheduled during such planned outages, which typically extends the planned outage duration. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease, and maintenance costs may increase.
Certain of the Utility operating companies and System Energy face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication). These risks could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Based upon currently planned fuel cycles, Entergy’s nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable prices through 2020 and beyond. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. While there are a number of possible alternate suppliers that may be accessed to mitigate any supplier performance failure, the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S. Market prices for nuclear fuel have been extremely volatile from time to time in the past and may be subject to increased volatility due to the imposition of tariffs, domestic purchase requirements or limitations on importation of uranium or uranium products from foreign countries, or shifting trade arrangements between countries. Although Entergy’s nuclear fuel contract portfolio provides a degree of hedging against market risks for several years, costs for nuclear fuel in the future cannot be predicted with certainty due to normal inherent market uncertainties, and price changes could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance and reliability of conversion, enrichment, and fabrication services providers. These service providers are fewer in number than uranium suppliers. For conversion and enrichment services, Entergy diversifies its supply by supplier and country and may take special measures to ensure a reliable supply of enriched uranium for fabrication into nuclear fuel. For fabrication services, each plant is dependent upon the performance of the fabricator of that plant’s nuclear fuel; therefore, Entergy relies upon additional monitoring, inspection, and oversight of the fabrication process to assure reliability and quality of its nuclear fuel. Certain of the suppliers and service providers are located in or dependent upon countries, such as Russia, in which international sanctions or tariffs could further restrict the ability of such
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suppliers to continue to supply fuel or provide such services at acceptable prices or at all. The inability of such suppliers or service providers to perform such obligations could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business face the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants, which could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Under the Atomic Energy Act and Energy Reorganization Act, the NRC regulates the operation of nuclear power plants. The NRC may modify, suspend, or supplementrevoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the stepsAtomic Energy Act, related regulations, or the terms of the licenses for nuclear facilities. Interested parties may also intervene which could result in prolonged proceedings. A change in the Atomic Energy Act, other applicable statutes, or the applicable regulations or licenses, or the NRC’s interpretation thereof, may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially affect the results of operations, liquidity, or financial condition of Entergy (through Entergy Wholesale Commodities), its Utility operating companies, or System Energy. A change in the classification of a plant owned by one of these companies under the NRC’s Reactor Oversight Process, which is the NRC’s program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response, also could cause the owner of the plant to incur material additional costs as a result of the increased oversight activity and potential response costs associated with the change in classification.For additional information concerning the current classification of the plants owned by Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business, see “Regulation of Entergy’s Business- Regulation of the Nuclear Power Industry - NRC Reactor Oversight Process” in Part I, Item 1.
Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate actions to modify, suspend, or revoke licenses, shut down a nuclear facility, or impose civil penalties. As a result, if an incident were to occur at any nuclear generating unit, whether an Entergy nuclear generating unit or not, it could materially affect the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, System Energy, or Entergy Wholesale Commodities.
Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities are exposed to risks and costs related to operating and maintaining their nuclear power plants, and their failure to maintain operational efficiency at their nuclear power plants could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
The nuclear generating units owned by certain of the Utility operating companies, System Energy,and the Entergy Wholesale Commodities business began commercial operations in the 1970s-1980s. Older equipment may require more capital expenditures to keep each of these nuclear power plants operating safely and efficiently. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages, or any unanticipated capital expenditures, could result in increased costs, some of which costs may not be fully recoverable by the Utility operating companies and System Energy in regulatory proceedings should there be a determination of imprudence. Operations at any of the nuclear generating units owned and operated by Entergy’s subsidiaries could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. A decision may be made to close a unit rather than incur the expense of restarting it or returning the unit to full capacity. For the Utility operating companies and System Energy, this could result in certain costs being stranded and potentially not fully recoverable in regulatory proceedings. For Entergy Wholesale Commodities, this could result in lost revenue and increased fuel and purchased power expense to meet
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
supply commitments and penalties for failure to perform under their contracts with customers. In addition, the operation and maintenance of Entergy’s nuclear facilities require the commitment of substantial human resources that can result in increased costs.
The nuclear industry continues to address susceptibility to the effects of stress corrosion cracking and other corrosion mechanisms on certain materials within plant systems. The issue is applicable at all nuclear units to varying degrees and is managed in accordance with industry standard practices and guidelines that include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.
Moreover, Entergy is becoming more dependent on fewer suppliers for key parts of Entergy’s nuclear power plants that may need to be replaced or refurbished, and in some cases, parts are no longer available and have to be reverse-engineered for replacement. In addition, certain major parts have long lead-times to manufacture if an unplanned replacement is needed. This dependence on a reduced number of suppliers and long lead-times on certain major parts for unplanned replacements could result in delays in obtaining qualified replacement parts and, therefore, greater expense for Entergy.
The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities nuclear power plants, as well as the costs of and their ability to fully decommission their nuclear power plants, could be significantly affected by the timing of the opening of a spent nuclear fuel disposal facility, as well as interim storage and transportation requirements.
Certain of the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities nuclear plants incur costs for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the disposal of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, or any interim storage facility, and the timing of such facility opening, will significantly affect the costs associated with on-site storage of spent nuclear fuel. For example, while the DOE is required by law to proceed with the licensing of Yucca Mountain and, after the license is granted by the NRC, to construct the repository and commence the receipt of spent fuel, the NRC licensing of the Yucca Mountain repository is effectively at a standstill. These actions are prolonging the time before spent fuel is removed from Entergy’s plant sites. Because the DOE has not accomplished its objectives, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts, and Entergy has sued the DOE for such breach. Furthermore, Entergy is uncertain as to when the DOE will commence acceptance of spent fuel from its facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at the companies’ nuclear sites and maintenance costs on existing storage facilities, including aging management of fuel storage casks, may increase. The costs of on-site storage are also affected by regulatory requirements for such storage. In addition, the availability of a repository or other off-site storage facility for spent nuclear fuel may affect the ability to fully decommission the nuclear units and the costs relating to decommissioning. For further information regarding spent fuel storage, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs – Spent Fuel Disposal” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 8 to the financial statements.
Certain of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities nuclear plant owners may be required to pay substantial retrospective premiums imposed under the Price-Anderson Act in the event of a nuclear incident, and losses not covered by insurance could have a material effect on Entergy’s and their results of operations, financial condition, or liquidity.
Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere. The Price-Anderson Act limits each reactor owner’s public liability (off-site) for a single nuclear incident to the payment of retrospective premiums into a secondary insurance pool, which is referred to as Secondary Financial Protection, up to approximately $137.6 million per reactor. With 97 reactors currently
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
participating, this translates to a total public liability cap of approximately $14 billion per incident. The limit is subject to change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As required by the Price-Anderson Act, the Utility operating companies, System Energy, and Entergy Wholesale Commodities carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers, which is $450 million for each operating site. Claims for any nuclear incident exceeding that amount are covered under Secondary Financial Protection. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the primary insurance coverage, each owner of a nuclear plant reactor, including Entergy’s Utility operating companies, System Energy, and the Entergy Wholesale Commodities plant owners, regardless of fault or proximity to the incident, will be required to pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary insurance level, up to a maximum of approximately $137.6 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.101 billion). The retrospective premium payment is currently limited to approximately $21 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $137.6 million cap.
NEIL is a utility industry mutual insurance company, owned by its members, including the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities plants. All member plants could be subject to an annual assessment (retrospective premium of up to 10 times current annual premium for all policies) should the NEIL surplus (reserve) be significantly depleted due toinsured losses. As of December 31, 2020, the maximum annual assessment amounts total $104 million for the Utility plants. Retrospective premium insurance available through NEIL’s reinsurance treaty can cover the potential assessments and the Entergy Wholesale Commodities plants currently maintain the retrospective premium insurance to cover those potential assessments.
As an owner of nuclear power plants, Entergy participates in industry self-insurance programs and could be liable to fund claims should a plant owned by a different company experience a major event. Any resulting liability from a nuclear accident may exceed the applicable primary insurance coverage and require contribution of additional funds through the industry-wide program that could significantly affect the results of operations, financial condition, or liquidity of Entergy, certain of the Utility operating companies, System Energy, or the Entergy Wholesale Commodities subsidiaries.
The decommissioning trust fund assets for the nuclear power plants owned by the Utility operating companies, System Energy, and the Entergy Wholesale Commodities nuclear plant owners may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts, if one or more of Entergy’s nuclear power plants is retired earlier than the anticipated shutdown date, if the plants cost more to decommission than estimated, or if current regulatory requirements change, which then could require significant additional funding.
Owners of nuclear generating plants have an obligation to decommission those plants. Certain of the Utility operating companies, System Energy, and owners of the Entergy Wholesale Commodities nuclear power plants maintain decommissioning trust funds for this purpose. Certain of the Utility operating companies collect funds from their customers, which are deposited into the trusts covering the units operated for or on behalf of those companies. Those rate collections, as adjusted from time to time by rate regulators, are generally based upon operating license lives and trust fund balances as well as estimated trust fund earnings and decommissioning costs. Assets in these trust funds are subject to market fluctuations, will yield uncertain returns that may fall below projected return rates, and may result in losses resulting from the recognition of impairments of the value of certain securities held in these trust funds.
Under NRC regulations, nuclear plant owners are permitted to project the NRC-required decommissioning amount, based on an NRC formula or a site-specific estimate, and the amount that will be available in each nuclear power plant’s decommissioning trusts combined with any other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used. If the projected amount of each individual plant’s decommissioning trusts exceeds the NRC-required decommissioning amount, then its NRC license termination decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs required to decommission these nuclear power plants, or funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources or commitments would be required. Furthermore, depending upon the level of funding available in the trust funds, the NRC may not permit the trust funds to be used to pay for related costs such as the management of spent nuclear fuel that are not included in the NRC’s formula. The NRC may also require a plan for the provision of separate funding for spent fuel management costs. In addition to NRC requirements, there are other decommissioning-related obligations for certain of the Entergy Wholesale Commodities nuclear power plants, which management believes it will be able to satisfy.
Further, federal or state regulatory changes, including mandated increases in decommissioning funding or changes in the methods or standards for decommissioning operations, may also increase the funding requirements of, or accelerate the timing for funding of, the obligations related to the decommissioning of the Utility operating companies, System Energy, or Entergy Wholesale Commodities nuclear power plants or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. Such changes also could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. As a result, under any of these circumstances, Entergy’s results of operations, liquidity, and financial condition could be materially affected.
An early plant shutdown (either generally or relative to current expectations), poor investment results, or higher than anticipated decommissioning costs (including as a result of changing regulatory requirements) could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that the Utility operating companies, System Energy, or the Entergy Wholesale Commodities nuclear plant owners may be required to provide significant additional funds or credit support to satisfy regulatory requirements for decommissioning, which, with respect to the Utility operating companies, may not be recoverable from customers in a timely fashion or at all.
For further information regarding nuclear decommissioning costs, management’s decision to exit the merchant power business, the impairment charges that resulted from such decision, and the planned sales of Palisades and Indian Point Energy Center (which, in each case, will include the transfer of the associated decommissioning trusts), see the “Critical Accounting Estimates- Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy, the “Entergy Wholesale Commodities Exit from the Merchant Power Business” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries, and Notes 9 and 14 to the financial statements.
New or existing safety concerns regarding operating nuclear power plants and nuclear fuel could lead to restrictions upon the operation and decommissioning of Entergy’s nuclear power plants.
New and existing concerns are being expressed in public forums about the safety of nuclear generating units and nuclear fuel. These concerns have led to, and may continue to lead to, various proposals to Federal regulators and governing bodies in some localities where Entergy’s subsidiaries own nuclear generating units for legislative and regulatory changes that might lead to the shutdown of nuclear units, additional requirements or restrictions related to spent nuclear fuel on-site storage and eventual disposal, or other adverse effects on owning, operating, and decommissioning nuclear generating units. Entergy vigorously responds to these concerns and proposals. If any of the existing proposals, or any proposals that may arise in the future with respect to legislative and regulatory changes, become effective, they could have a material effect on Entergy’s results of operations and financial condition.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
(Entergy Corporation)
Entergy Wholesale Commodities nuclear power plants are exposed to price risk.
Entergy and its subsidiaries do not have a regulator-authorized rate of return on their capital investments in non-utility businesses. As a result, the sale of capacity and energy from the Entergy Wholesale Commodities nuclear power plants, unless otherwise contracted, is subject to the fluctuation of market power prices. In order to reduce future price risk to desired levels, Entergy Wholesale Commodities utilizes contracts that are unit-contingent and Firm LD and various products such as forward sales, options, and collars. As of December 31, 2020, Entergy Wholesale Commodities’ nuclear power generation plants had sold forward 98% in 2021 and 99% in 2022 of its generation portfolio’s planned energy output, reflecting the planned shutdown and sale of the remaining Entergy Wholesale Commodities nuclear power plants by mid-2022.
Market conditions such as product cost, market liquidity, and other portfolio considerations influence the product and contractual mix. The obligations under unit-contingent agreements depend on a generating asset that is operating; if the generation asset is not operating, the seller generally is not liable for damages. For some unit-contingent obligations, however, there is also a guarantee of availability that provides for the payment to the power purchaser of contract damages, if incurred, in the event the unit owner fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. Firm LD sales transactions may be exposed to substantial operational price risk, a portion of which may be capped through the use of risk management products, to the extent that the plants do not run as expected and market prices exceed contract prices.
Market prices may fluctuate substantially, sometimes over relatively short periods of time, and at other times experience sustained increases or decreases. Demand for electricity and its fuel stock can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply, prices might be depressed. Also, from time to time there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, credit requirements, bidding rules, and other mechanisms to address volatility and other issues in these markets.
The effects of sustained low natural gas prices and power market structure challenges have resulted in lower market prices for electricity in the power regions where the Entergy Wholesale Commodities nuclear power plants are located. In addition, currently the market design under which the plants operate does not adequately compensate merchant nuclear plants for their environmental and fuel diversity benefits in the region. These conditions were primary factors leading to Entergy’s decision to shut down (or sell) Entergy Wholesale Commodities’ nuclear power plants before the end of their operating licenses.
The price that different counterparties offer for various products including forward sales is influenced both by market conditions as well as the contract terms such as damage provisions, credit support requirements, and the number of available counterparties interested in contracting for the desired forward period. Depending on differences between market factors at the time of contracting versus current conditions, Entergy Wholesale Commodities’ contract portfolio may have average contract prices above or below current market prices, including at the expiration of the contracts, which may significantly affect Entergy Wholesale Commodities’ results of operations, financial condition, or liquidity. New hedges are generally layered into on a rolling forward basis, which tends to drive hedge over-performance to market in a falling price environment, and hedge underperformance to market in a rising price environment; however, hedge timing, product choice, and hedging costs will also affect these results. See the “Market and Credit Risk Sensitive Instruments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries. Since Entergy Wholesale Commodities has announced the closure (or sale) of its nuclear plants, Entergy Wholesale Commodities may enter into fewer forward sales contracts for output from such plants.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The Entergy Wholesale Commodities business is subject to substantial governmental regulation and may be adversely affected by legislative, regulatory, or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
The Entergy Wholesale Commodities business is subject to extensive regulation under federal, state, and local laws. Compliance with the requirements under these various regulatory regimes may cause the Entergy Wholesale Commodities business to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines, and/or civil or criminal liability.
Public utilities under the Federal Power Act are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Each of the owners of the Entergy Wholesale Commodities nuclear power plants that generates electricity, as well as Entergy Nuclear Power Marketing, LLC, is a “public utility” under the Federal Power Act by virtue of making wholesale sales of electric energy and/or owning wholesale electric transmission facilities. The FERC has granted these generating and power marketing companies the authority to sell electricity at market-based rates. The FERC’s orders that grant the Entergy Wholesale Commodities’ generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that the Entergy Wholesale Commodities business can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, the Entergy Wholesale Commodities’ market-based sales are subject to certain market behavior rules, and if any of its generating and power marketing companies were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority and potential penalties of up to $1.29 million per day per violation. If the Entergy Wholesale Commodities’ generating or power marketing companies were to lose their market-based rate authority, such companies would be required to obtain the FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates the Entergy Wholesale Commodities business charges for power from its facilities.
The Entergy Wholesale Commodities business is also affected by legislative and regulatory changes, as well as changes to market design, market rules, tariffs, cost allocations, and bidding rules imposed by the existing Independent System Operators. The Independent System Operators that oversee most of the wholesale power markets may impose, and in the future may continue to impose, mitigation, including price limitations, offer caps and other mechanisms, to address some of the volatility and the potential exercise of market power in these markets. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of the Entergy Wholesale Commodities business’ generation facilities that sell energy and capacity into the wholesale power markets. For further information regarding federal, state, and local laws and regulation applicable to the Entergy Wholesale Commodities business, see the “Regulation of Entergy’s Business” section in Part I, Item 1.
The regulatory environment applicable to the electric power industry is subject to changes as a result of restructuring initiatives at both the state and federal levels. Entergy cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on the Entergy Wholesale Commodities business. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism, have raised claims that the competitive marketplace is not working because energy prices in wholesale markets exceed the marginal cost of operating nuclear power plants, and have made proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process, which could require material changes to business planning models. If competitive restructuring of the electric power markets is reversed, modified, discontinued, or delayed, the Entergy Wholesale Commodities business’ results of operations, financial condition, and liquidity could be materially affected.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The power plants owned by the Entergy Wholesale Commodities business are subject to impairment charges in certain circumstances, which could have a material effect on Entergy’s results of operations, financial condition, or liquidity.
Entergy reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from the operations of such assets. Projected net cash flows depend on the expected operating life of the assets, the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy and capacity over the remaining life of the assets. In particular, the remaining assets of the Entergy Wholesale Commodities business are subject to further impairment in connection with the closure and sale of its nuclear power plants. Moreover, prior to the closure and sale of these plants, the failure of the Entergy Wholesale Commodities business to achieve forecasted operating results and cash flows, an unfavorable change in forecasted operating results or cash flows, a reduction in the expected remaining useful life of a unit, or a decline in observable industry market multiples could all result in potential additional impairment charges for the affected assets.
If Entergy concludes that any of its nuclear power plants is unlikely to operate through its planned shutdown date, which conclusion would be based on a variety of factors, such a conclusion could result in a further impairment of part or all of the carrying value of the plant. Any impairment charge taken by Entergy with respect to effectuateits long-lived assets, including the restructuring.remaining power plants owned by the Entergy Wholesale Commodities business, would likely be material in the quarter that the charge is taken and could otherwise have a material effect on Entergy’s results of operations, financial condition, or liquidity. For further information regarding evaluating long-lived assets for impairment, see the “Critical Accounting Estimates - Impairment of Long-lived Assets” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries and for further discussion of the impairment charges, see Note 14 to the financial statements.
Production Cost Allocation Rider
Entergy Arkansas has in place an APSC-approved production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of System Agreement proceedings.
Entergy Louisiana
Fuel Recovery
Entergy Louisiana’s rate schedules include a fuel adjustment clause designed to recover the cost of fuel and purchased power costs. The fuel adjustment clause contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers, including carrying charges. See Note 2 to the financial statements for a discussion of proceedings related to audits of Entergy Louisiana’s fuel adjustment clause filings.
To help stabilize electricity costs, Entergy Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Louisiana historically hedged approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity was reviewed on an annual basis. In January 2018, Entergy Louisiana filed an application with the LPSC to suspend these seasonal hedging programs and implement financial hedges with terms up to five years for a portion of its natural gas exposure, which was approved in November 2018.
Entergy Louisiana’s gas rates include a purchased gas adjustment clause based on estimated gas costs for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
Retail Rates - Gas
In accordance with the settlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of the upper end of the earnings band as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.
Other
In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and the second is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the LPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax obligation at the parent level of a consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020.
Entergy Mississippi
Fuel Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.
To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.
Formula Rate Plan
In August 2012 the MPSC opened inquiries to review whether the current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan was still appropriate or could be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan proceeding. In March 2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans. The docket remains open.
Entergy New Orleans
Fuel Recovery
Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.
Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of its natural gas hedging program consistent with the City Council’s stated policy objectives. The program uses financial instruments to hedge exposure to volatility in the wholesale price of natural gas purchased to serve Entergy New Orleans gas customers. Entergy New Orleans hedges up to 25% of actual gas sales made during the winter months.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy New Orleans’s efforts to recover storm-related costs.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Energy Efficiency Programs
A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. The rate settlement provided an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provided a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. In January 2015 the City Council approved funding for the Energy Smart program from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In April 2017 the City Council approved an implementation plan for the Energy Smart program from April 2017 through December 2019. The City Council directed that the $11.8 million balance reported for Energy Smart funds be used to continue funding the program for Entergy New Orleans’s legacy customers and that the Energy Smart Algiers program continue to be funded through the Algiers fuel adjustment clause, until additional customer funding is required for the legacy customers. In September 2017, Entergy New Orleans filed a supplemental plan and proposed several options for an interim cost recovery mechanism necessary to recover program costs during the period between when existing funds directed to Energy Smart programs are depleted and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect. In December 2017 the City Council approved an energy efficiency cost recovery rider as an interim funding mechanism for Energy Smart, subject to verification that no additional funding sources exist. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. See Note 2 to the financial statements for discussion of Entergy New Orleans’s application with the City Council seeking approval of an implementation plan for the Energy Smart program from April 2020 through December 2022.
Entergy Texas
Fuel Recovery
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included in base rates. Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. The PUCT fuel cost proceedings are discussed in Note 2 to the financial statements.
At the PUCT’s April 2013 open meeting, the PUCT Commissioners discussed their view that a purchased power capacity rider was good public policy. The PUCT issued an order in May 2013 adopting the rule allowing for a purchased power capacity rider, subject to an offsetting adjustment for load growth. The rule, as adopted, also includes a process for obtaining pre-approval by the PUCT of purchased power agreements. Entergy Texas has not exercised the option to recover its capacity costs under the new rider mechanism, but will continue to evaluate the benefits of utilizing the new rider to recover future capacity costs.
Electric Industry Restructuring
In June 2009, a law was enacted in Texas that required Entergy Texas to cease all activities relating to Entergy Texas’s transition to competition. The law allows Entergy Texas to remain a part of the SERC Reliability Corporation (SERC) Region, although it does not prevent Entergy Texas from joining another power region. The law provides that proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding
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exist. Under the law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT’s certification of Entergy Texas’s power region.
The law also contains provisions that allow Entergy Texas to take advantage of a cost recovery mechanism that permits annual filings for the recovery of reasonable and necessary expenditures for transmission infrastructure improvement and changes in wholesale transmission charges. This mechanism was previously available to other non-ERCOT Texas utility companies, but not to Entergy Texas.
The law further amended already existing law that had required Entergy Texas to propose for PUCT approval a tariff to allow eligible customers the ability to contract for competitive generation. The amending language in the law provides, among other things, that: 1) the tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers who choose not to participate in the tariff; 2) Entergy Texas shall “purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer;” and 3) Entergy Texas shall provide and price transmission service and ancillary services under that tariff at a rate that is unbundled from its cost of service. The law directs that the PUCT may not issue an order on the tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction.
The PUCT determined that unrecovered costs that may be recovered through the rider consist only of those costs necessary to implement and administer the competitive generation program and do not include lost revenues or embedded generation costs. The amount of customer load that may be included in the competitive generation service program is limited to 115 MW.
In September 2011 the PUCT adopted a proposed rule implementing a distribution cost recovery factor to recover capital and capital-related costs related to distribution infrastructure. The distribution cost recovery factor permits utilities once per year to implement an increase or decrease in rates above or below amounts reflected in base rates to reflect depreciation expense, federal income tax and other taxes, and return on investment. The distribution cost recovery factor rider may be changed a maximum of four times between base rate cases.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery factor rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas franchises are considered to be contracts and, therefore, are terminable pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.
Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
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Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas, and holds non-exclusive franchises to provide electric service in approximately 68 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire over the period 2020-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
Property and Other Generation Resources
Owned Generating Stations
The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2020, is indicated below:
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| | Owned and Leased Capability MW(a) |
Company | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
Entergy Arkansas | | 5,175 | | | 2,091 | | | 1,817 | | | 1,194 | | | 73 | | | — | |
Entergy Louisiana | | 11,317 | | | 8,827 | | | 2,144 | | | 346 | | | — | | | — | |
Entergy Mississippi | | 3,347 | | | 2,929 | | | — | | | 416 | | | — | | | 2 | |
Entergy New Orleans | | 665 | | | 638 | | | — | | | — | | | — | | | 27 | |
Entergy Texas | | 2,260 | | | 2,005 | | | — | | | 255 | | | — | | | — | |
System Energy | | 1,256 | | | — | | | 1,256 | | | — | | | — | | | — | |
Total | | 24,020 | | | 16,490 | | | 5,217 | | | 2,211 | | | 73 | | | 29 | |
(a)“Owned and Leased Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.
Summer peak load for the Utility has averaged 21,591 MW over the previous decade.
The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 8,801 MW of new long-term resources and the deactivation of about 4,664 MW of legacy generation. As MISO market participants, the Utility operating companies also participate in MISO’s Day Ahead and Real Time Energy and Ancillary Services markets to economically dispatch generation and purchase energy to serve customers reliably and at the lowest reasonable cost.
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Other Generation Resources
RFP Procurements
The Utility operating companies from time to time issue requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies. The RFPs issued by the Utility operating companies have sought resources needed to meet near-term MISO reliability requirements as well as long-term requirements through a broad range of wholesale power products, including limited-term (1 to 3 years) and long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
•Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine J. Wayne Leonard Power Station (previously referred to as the St. Charles generating facility) at its existing Little Gypsy electric generating station. The facility began commercial operation in May 2019;
•Entergy Texas’s construction of the 993 MW, combined-cycle, gas turbine Montgomery County Power Station at its existing Lewis Creek electric generating station. The facility began commercial operation in January 2021;
•Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station site. The facility began commercial operation in March 2020;
•In October 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the facility is scheduled to be in service by early 2022;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020 and the facility is scheduled to be in service by the end of 2021;
•Entergy New Orleans received regulatory approval in August 2019 to construct the New Orleans Solar Station (a 20 MW self-build solar project) located at the NASA Michoud Facility.The facility was placed in service in December 2020;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Lee County, Arkansas. In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2022;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2023; and
•In June 2020, Entergy Texas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 1,200 acres in Liberty County near Dayton, Texas.In September 2020, Entergy Texas filed a petition with the PUCT seeking a finding that the transaction is in the public interest and requesting all necessary approvals.Closing is expected to occur by the end of 2023.
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The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:
•River Bend’s 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
•Entergy Arkansas’s wholesale base load capacity life-of-unit PPAs executed in 2003 totaling approximately 220 MW between Entergy Arkansas and Entergy Louisiana (110 MW) and between Entergy Arkansas and Entergy New Orleans (110 MW) related to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which had not been included in Entergy Arkansas’s retail rates);
•In May 2011, Entergy Texas and Calpine Energy Services, L.P. executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. Entergy Louisiana purchases 50% of the facility’s capacity and energy from Entergy Texas. In July 2014, LS Power purchased the Carville Energy Center and replaced Calpine Energy Services as the counterparty to the agreement;
•In September 2012, Entergy Gulf States Louisiana executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 MW when available, from Rain CII Carbon LLC’s petroleum coke calcining facility in Sulphur, Louisiana. The facility began commercial operation in May 2013. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with the facility;
•In March 2013, Entergy Gulf States Louisiana executed a 20-year agreement for 8.5 MW from Agrilectric Power Partners, LP’s refurbished rice hull-fueled electric generation facility located in Lake Charles, Louisiana. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with Agrilectric;
•In September 2013, Entergy Louisiana executed a 10-year agreement with TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, to purchase approximately 3 MW from its landfill gas-fueled power generation facility located in Cleveland, Texas;
•Entergy Mississippi’s cost-based purchase, beginning in January 2013, of 90 MW from Entergy Arkansas’s share of Grand Gulf (only 60 MW of this PPA came through the RFP process). Cost recovery for the 90 MW was approved by the MPSC in January 2013;
•In April 2015, Entergy Arkansas and Stuttgart Solar, LLC executed a 20-year agreement for 81 MW from a solar photovoltaic electric generation facility located near Stuttgart, Arkansas. The APSC approved the project and deliveries pursuant to that agreement commenced in June 2018;
•In November 2016, Entergy Louisiana and LS Power executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. The transaction received regulatory approval and will begin in June 2022;
•In November 2016, Entergy Louisiana and Occidental Chemical Corporation executed a 10-year agreement for 500 MW from the Taft Cogeneration facility located in Hahnville, Louisiana. The transaction received regulatory approval and began in June 2018;
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
•In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021;
•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a five-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
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•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021; and
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a solar photovoltaic electric generating facility located in Polk County, Texas.The PPA is expected to start when the facility reaches commercial operation in 2023.
In April 2020, Entergy Services, on behalf of Entergy Texas, issued an RFP for combined-cycle gas turbine capacity and energy resources. The RFP was seeking up to 1,000 MW - 1,200 MW of capacity, capacity-related benefits, energy, other electric products, and environmental attributes, if any, from a single generation resource located in the “Eastern Region” of Entergy Texas’s service area. In December 2020, Entergy Texas posted notice that it has elected to proceed with the self-build alternative, Orange County Power Station. The self-build alternative will be conditioned on receipt of required internal and regulatory approvals.
In June 2020, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic resources. The RFP was seeking 300 MW of energy, capacity, capacity-related benefits, other electric products, and environmental attributes from eligible new-build solar photovoltaic generation resources. In December 2020, Entergy Louisiana concluded evaluations of the RFP. Three proposals have been placed on the primary selection list and two proposals have been placed on the secondary selection list. Negotiations are currently in progress.
In January 2021, Entergy Texas provided notice that it intends to issue an RFP for solar generation resources. The RFP is seeking a minimum of 200 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Texas customers.
Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process, including Entergy Mississippi’s January 2006 acquisition of the 480 MW, combined-cycle, gas-fired Attala power plant; Entergy Gulf States Louisiana’s March 2008 acquisition of the 322 MW, simple-cycle, gas-fired Calcasieu Generating Facility; Entergy Louisiana’s April 2011 acquisition of the 580 MW, combined-cycle, gas-fired Acadia Energy Center Unit 2; Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) March 2016 acquisitions of the 1,980 MW (summer rating), natural gas-fired, combined-cycle gas turbine Union Power Station power blocks, each rated at 495 MW (summer rating); and Entergy Mississippi’s October 2019 acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The Utility operating companies have also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.
The Washington Parish Energy Center is a 361 MW natural gas-fired peaking power plant approximately 60 miles north of New Orleans on a site Entergy Louisiana purchased from Calpine in 2019. In May 2018, Entergy Louisiana received LPSC approval of its certification application for this simple-cycle power plant to be developed pursuant to an agreement between Calpine and Entergy Louisiana. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020.
The Hardin County Peaking Facility is an existing 147 MW simple-cycle gas-fired peaking power plant in Kountze, Texas, owned by East Texas Electric Cooperative. Entergy Texas is currently seeking regulatory certification to move forward with the purchase of the facility. The facility has been in operation since January 2010.
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Power Through Program
In December 2020, Entergy Texas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation that is to be installed at commercial and industrial customer premises. If approved, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.”
Interconnections
The Utility operating companies’ generating units are interconnected to a transmission system operating at various voltages up to 500 kV. These generating units consist of steam-electric production facilities, combustion-turbine generators, pressurized and boiling water nuclear reactors, and inverter-based technologies operating in the MISO energy and ancillary services market. Entergy’s Utility operating companies are MISO market participants and are interconnected with many neighboring utilities. MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. As a Regional Transmission Organization, MISO assures consumers of unbiased regional grid management and open access to the transmission facilities under MISO’s functional supervision. In addition, the Utility operating companies are members of SERC Reliability Corporation (SERC). SERC is a nonprofit corporation responsible for promoting and improving the reliability, adequacy, and critical infrastructure of the bulk power supply systems in all or portions of 16 central and southeastern states.SERC serves as a regional entity with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing Bulk Electric System reliability standards within the SERC Region.
Gas Property
As of December 31, 2020, Entergy New Orleans distributed and transported natural gas for distribution within New Orleans, Louisiana, through approximately 2,600 miles of gas pipeline. As of December 31, 2020, the gas properties of Entergy Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Louisiana’s financial position.
Title
The Utility operating companies’ generating stations are generally located on properties owned in fee simple. Most of the substations and transmission and distribution lines are constructed on private property or public rights-of-way pursuant to easements, servitudes, or appropriate franchises. Some substation properties are owned in fee simple. The Utility operating companies generally have the right of eminent domain, whereby they may perfect title to, or secure easements or servitudes on, private property for their utility operations.
Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are subject to the liens of mortgages securing bonds issued by those companies. The Lewis Creek generating station of Entergy Texas was acquired by merger with a subsidiary of Entergy Texas and is currently not subject to the lien of the Entergy Texas indenture.
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Fuel Supply
The sources of generation and average fuel cost per kWh for the Utility operating companies and System Energy for the years 2018-2020 were:
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| | Natural Gas | | Nuclear | | Coal | | Purchased Power | | MISO Purchases |
Year | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh |
2020 | | 47 | | | 1.92 | | | 29 | | | 0.57 | | | 3 | | | 2.54 | | | 8 | | | 4.36 | | | 13 | | | 2.48 | |
2019 | | 40 | | | 2.33 | | | 28 | | | 0.73 | | | 6 | | | 2.31 | | | 8 | | | 4.86 | | | 18 | | | 2.71 | |
2018 | | 39 | | | 2.84 | | | 27 | | | 0.84 | | | 9 | | | 2.24 | | | 8 | | | 5.23 | | | 17 | | | 3.71 | |
Actual 2020 and projected 2021 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:
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| Natural Gas | | Nuclear | | Coal | | Purchased Power (d) | | MISO Purchases (e) |
| 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 |
Entergy Arkansas (a) | 24 | % | | 35 | % | | 60 | % | | 51 | % | | 10 | % | | 13 | % | | 1 | % | | 1 | % | | 5 | % | | — | |
Entergy Louisiana | 51 | % | | 59 | % | | 26 | % | | 27 | % | | 1 | % | | 2 | % | | 9 | % | | 12 | % | | 13 | % | | — | |
Entergy Mississippi (b) | 73 | % | | 69 | % | | 14 | % | | 22 | % | | 4 | % | | 9 | % | | — | | | — | | | 9 | % | | — | |
Entergy New Orleans (b) | 55 | % | | 56 | % | | 33 | % | | 40 | % | | 1 | % | | 2 | % | | 2 | % | | 2 | % | | 9 | % | | — | |
Entergy Texas | 39 | % | | 60 | % | | 11 | % | | 13 | % | | 2 | % | | 6 | % | | 23 | % | | 21 | % | | 25 | % | | — | |
System Energy (c) | — | | | — | | | 100 | % | | 100 | % | | — | | | — | | | — | | | — | | | — | | | — | |
Utility (a) (b) | 47 | % | | 55 | % | | 29 | % | | 31 | % | | 3 | % | | 6 | % | | 8 | % | | 8 | % | | 13 | % | | — | |
(a)Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2020 and is expected to provide less than 1% of its generation in 2021.
(b)Solar power provided less than 1% of Entergy Mississippi’s and Entergy New Orleans's generation in 2020 and is expected to provide less than 1% of each of Entergy Mississippi’s and Entergy New Orleans's generation in 2021.
(c)Capacity and energy from System Energy’s interest in Grand Gulf is allocated as follows under the Unit Power Sales Agreement: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%. Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.
(d)Excludes MISO purchases.
(e)In December 2013, Entergy integrated its transmission system into the MISO RTO. Entergy offers all of its generation into the MISO energy market on a day-ahead and real-time basis and bids for power in the MISO energy market to serve the demand of its customers, with MISO making dispatch decisions. The MISO purchases metric provided for 2020 is not projected for 2021.
Some of the Utility’s gas-fired plants are also capable of using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in 2021, it is possible that various operational events including weather or pipeline maintenance may require the use of fuel oil.
Natural Gas
The Utility operating companies have long-term firm and short-term interruptible gas contracts for both supply and transportation. Over 50% of the Utility operating companies’ power plants maintain some level of long-
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term firm transportation. Short-term contracts and spot-market purchases satisfy additional gas requirements. Entergy Texas owns a gas storage facility that provides reliable and flexible natural gas service to certain generating stations.
Many factors, including wellhead deliverability, storage, pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
Coal
Entergy Arkansas has committed to seven one- to three-year contracts that will supply approximately 85% of the total coal supply needs in 2021. These contracts are staggered in term so that not all contracts have to be renewed the same year. The remaining 15% of total coal requirements will be satisfied by contracts with a term of less than one year. Based on continued improved Powder River Basin (PRB) coal deliveries by rail and the high cost of alternate sources and modes of transportation, no alternative coal consumption is expected at Entergy Arkansas during 2021. Coal will be transported to Arkansas via an existing transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2021.
Entergy Louisiana has committed to five one- to three-year contracts that will supply approximately 90% of Nelson Unit 6 coal needs in 2021. If needed, additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as for Entergy Arkansas’s plants, no alternative coal consumption is expected at Nelson Unit 6 during 2021. Coal will be transported to Nelson primarily via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2021.
For the year 2020, coal transportation delivery rates to Entergy Arkansas-and Entergy Louisiana-operated coal-fired units were adequate to meet supply needs and obligations, and it is expected that delivery times in 2021 will continue to be consistent. Both Entergy Arkansas and Entergy Louisiana control a sufficient number of railcars to satisfy the rail transportation requirement.
The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2021. Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.
Nuclear Fuel
The nuclear fuel cycle consists of the following:
•mining and milling of uranium ore to produce a concentrate;
•conversion of the concentrate to uranium hexafluoride gas;
•enrichment of the uranium hexafluoride gas;
•fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and
•disposal of spent fuel.
The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated
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uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the owner of a nuclear power plant.
Based upon currently planned fuel cycles, the Utility nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through most of 2023. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. There are a number of possible supply alternatives that may be accessed to mitigate any supplier performance failure, including potentially drawing upon Entergy’s inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.
The effects of market price changes may be reduced and deferred by risk management strategies, such as negotiation of floor and ceiling amounts for long-term contracts, buying for inventory or entering into forward physical contracts at fixed prices when Entergy believes it is appropriate and useful. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance reliability of conversion, enrichment, and fabrication services providers. There are fewer of these providers than for uranium. For conversion and enrichment services, like uranium, Entergy diversifies its supply by supplier and country and may take special measures as needed to ensure supply of enriched uranium for the reliable fabrication of nuclear fuel. For fabrication services, each plant is dependent upon the effective performance of the fabricator of that plant’s nuclear fuel, therefore, Entergy provides additional monitoring, inspection, and oversight for the fabrication process to assure reliability and quality.
Entergy Arkansas, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the financial statements of Entergy and the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These credit facilities are subject to periodic renewal, and the notes are issued periodically, typically for terms between three and seven years.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with one interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with CenterPoint Energy Services which guarantees Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The CenterPoint Energy Service gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans also makes interruptible spot market purchases.
Entergy Louisiana purchased natural gas for resale in 2020 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.
Federal Regulation of the Utility
State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.
System Agreement (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Prior to each operating company’s termination of participation in the System Agreement (Entergy Arkansas in December 2013, Entergy Mississippi in November 2015, and Entergy Louisiana, Entergy New Orleans, and Entergy Texas each in August 2016), the Utility operating companies engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which was a rate schedule approved by the FERC. Under the terms of the System Agreement, generating capacity and other power resources were jointly operated by the Utility operating companies that were participating in the System Agreement. The System Agreement provided, among other things, that parties having generating reserves greater than their allocated share of reserves (long companies) would receive payments from those parties having generating reserves that were less than their allocated share of reserves (short companies). Such payments were at amounts sufficient to cover certain of the long companies’ costs for intermediate and peaking oil/gas-fired generation, including operating expenses, fixed charges on debt, dividend requirements on preferred equity, and a fair rate of return on common equity investment. Under the System Agreement, the rates used to compensate long companies were based on costs associated with the long companies’ steam electric generating units fueled by oil or gas and having an annual average heat rate above 10,000 Btu/kWh. In addition, for all energy exchanged among the Utility operating companies under the System Agreement, the companies purchasing exchange energy were required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs.
Although the System Agreement has terminated, certain of the Utility operating companies’ and their retail regulators are pursuing litigation involving the System Agreement at the FERC and in federal courts. The proceedings include challenges to the allocation of costs as defined by the System Agreement and other matters. See Note 2 to the financial statements for discussion of legal proceedings at the FERC and in federal courts involving the System Agreement.
Transmission and MISO Markets
In December 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO did not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities, MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and congestion management and provides schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the markets. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. Each Utility operating company has its own transmission pricing zone and a formula rate template (included as Attachment O to the MISO tariff) used to
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establish transmission rates within MISO. The terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets and the allocation of transmission upgrade costs, are subject to regulation by the FERC.
System Energy and Related Agreements
System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In July 2001 a rate proceeding commenced by System Energy at the FERC in 1995 became final, with the FERC approving a prospective 10.94% return on equity. In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas’s and Entergy Mississippi’s acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC. See Note 2 to the financial statements for discussion of complaints filed with the FERC regarding System Energy’s return on equity.
Unit Power Sales Agreement
The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.
In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf-related costs and recovers the remaining 78% of its share in rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas’s cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans that sell a portion of the output of Entergy Arkansas’s retained share of Grand Gulf to those companies, with the remainder of the retained share being sold to Entergy Mississippi through a separate life-of-resources purchased power agreement. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted rate relief with respect to costs associated with Entergy Louisiana’s share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Entergy Louisiana retains and does not recover from retail ratepayers 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause at 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC’s approval. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of the output of Entergy Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted rate relief for those purchases by the MPSC through its annual unit power cost rate mechanism.
Availability Agreement
The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the financing by System Energy
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of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges.
The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.
System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for its two outstanding series of first mortgage bonds. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.
Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be made directly to the holders of indebtedness that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.
The obligations of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans to make payments under the Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to the FERC for approval with respect to the terms of such sale. No such filing with the FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability Agreement, the jurisdictional portions of the Availability Agreement would be submitted to the FERC for approval.
Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement and, therefore, no payments under the Availability Agreement have ever been required. If Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their Availability Agreement obligations exceed their Unit Power Sales Agreement obligations.
The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors.
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Service Companies
Entergy Services, a limited liability company wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the Utility operating companies, but also provides services to Entergy Wholesale Commodities. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas
Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson Unit 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.
Entergy Texas purchases from Entergy Louisiana pursuant to a life-of-unit purchased power agreement a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend’s nuclear and environmental liabilities that is identical to the share of the plant’s output purchased by Entergy Texas under the purchased power agreement. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements.
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
On October 1, 2015, the businesses formerly conducted by Entergy Louisiana (Old Entergy Louisiana) and Entergy Gulf States Louisiana (Old Entergy Gulf States Louisiana) were combined into a single public utility. In order to effect the business combination, under the Texas Business Organizations Code (TXBOC), Old Entergy Louisiana allocated substantially all of its assets to a new subsidiary, Entergy Louisiana Power, LLC, a Texas limited liability company (New Entergy Louisiana), and New Entergy Louisiana assumed the liabilities of Old Entergy Louisiana, in a transaction regarded as a merger under the TXBOC. Under the TXBOC, Old Entergy Gulf States Louisiana allocated substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States Louisiana assumed the liabilities of Old Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. New Entergy Gulf States Louisiana then merged into New Entergy Louisiana with New Entergy Louisiana surviving the merger. Thereupon, Old Entergy Louisiana changed its name from “Entergy Louisiana, LLC” to “EL Investment Company, LLC” and New Entergy Louisiana changed its name from “Entergy Louisiana Power, LLC” to “Entergy Louisiana, LLC” (Entergy Louisiana). With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Old Entergy Louisiana and Old Entergy Gulf States Louisiana.
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Entergy New Orleans Internal Restructuring
In November 2017, pursuant to the agreement in principle, Entergy New Orleans, Inc. undertook a multi-step restructuring, including the following:
•Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.
•Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans, Inc. allocated substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power assumed substantially all of the liabilities of Entergy New Orleans, Inc. in a transaction regarded as a merger under the TXBOC. Entergy New Orleans, Inc. remained in existence and held the membership interests in Entergy New Orleans Power.
•Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The restructuring was accounted for as a transaction between entities under common control.
Entergy Arkansas Internal Restructuring
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Mississippi Internal Restructuring
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
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•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
Entergy Wholesale Commodities
Entergy Wholesale Commodities includes the ownership, operation, and decommissioning of nuclear power plants, located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities revenues are primarily derived from sales of energy and generation capacity from these plants. Entergy Wholesale Commodities also provides operations and management services, including decommissioning-related services, to nuclear power plants owned by non-affiliated entities in the United States. Entergy Wholesale Commodities also includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers.
See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
Property
Nuclear Generating Stations
Entergy Wholesale Commodities includes the ownership of the following nuclear power plants:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Power Plant | | Market | | In Service Year | | Acquired | | Location | | Capacity - Reactor Type | | License Expiration Date |
Indian Point 3 (a) | | NYISO | | 1976 | | Nov. 2000 | | Buchanan, NY | | 1,041 MW - Pressurized Water | | 2025 (a) |
Indian Point 2 (a) | | NYISO | | 1974 | | Sept. 2001 | | Buchanan, NY | | 1,028 MW - Pressurized Water | | 2024 (a) |
Palisades (b) | | MISO | | 1971 | | Apr. 2007 | | Covert, MI | | 811 MW - Pressurized Water | | 2031 (b) |
(a)Power operations ceased at the Indian Point 2 plant in April 2020. The fuel was permanently removed from the reactor vessel and placed in the spent fuel pool in May 2020. The Indian Point 3 plant is expected to cease operations on April 30, 2021. Entergy and Holtec jointly filed a license transfer application with the NRC in November 2019, requesting approval for the transfer of the Indian Point plants, along with their nuclear decommissioning trusts and decommissioning liabilities, from Entergy to Holtec. The NRC approved the license transfer application on November 23, 2020.
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(b)The Palisades plant is expected to cease operations on May 31, 2022. There is a contract to sell the plant to Holtec subject to NRC and other regulatory approvals.
See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
Entergy Wholesale Commodities also includes the ownership of two non-operating nuclear facilities, Big Rock Point in Michigan and Indian Point 1 in New York that were acquired when Entergy purchased the Palisades and Indian Point 2 nuclear plants, respectively. These facilities are in various stages of the decommissioning process. Both Big Rock Point and Indian Point 1 are under contract to be sold with their respective plants.
Non-nuclear Generating Stations
Entergy Wholesale Commodities includes the ownership, or interests in joint ventures that own, the following non-nuclear power plants:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Plant | | Location | | Ownership | | Net Owned Capacity (a) | | Type |
Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
RS Cogen; 425 MW (c) | | Lake Charles, LA | | 50% | | 213 MW | | Gas/Steam |
Nelson Unit 6; 550 MW | | Westlake, LA | | 11% | | 60 MW(b) | | Coal |
(a)“Net Owned Capacity” refers to the nameplate rating on the generating unit.
(b)The owned MW capacity is the portion of the plant capacity owned by Entergy Wholesale Commodities. For a complete listing of Entergy’s jointly-owned generating stations, refer to “Jointly-Owned Generating Stations” in Note 1 to the financial statements.
(c)Indirectly owned through an interest in an unconsolidated joint venture. In December 2020, Entergy’s wholly-owned subsidiary with a direct interest in RS Cogen, LLC entered into a membership interest purchase agreement with a subsidiary of the other 50% equity partner to sell its 50% membership interest in the joint venture to the equity partner. The targeted closing date for the transaction is October 2022.
Independent System Operators
The Indian Point plants fall under the authority of the New York Independent System Operator (NYISO). The Palisades plant falls under the authority of the MISO. The primary purpose of NYISO and MISO is to direct the operations of the major generation and transmission facilities in their respective regions; ensure grid reliability; administer and monitor wholesale electricity markets; and plan for their respective region’s energy needs.
Energy and Capacity Sales
As a wholesale generator, Entergy Wholesale Commodities’ core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and also sells energy in the day ahead or spot markets. Entergy Wholesale Commodities also sells unforced capacity, which allows load-serving entities to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Entergy Wholesale Commodities’ forward physical power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Entergy Wholesale Commodities to deliver MWh of energy, make capacity available, or both.See “Market and Credit Risk Sensitive Instruments” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for additional information regarding these contracts.
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As part of the purchase of the Palisades plant in 2007, Entergy executed a 15-year PPA with the seller, Consumers Energy, for 100% of the plant’s output, excluding any future uprates. Under the purchased power agreement, Consumers Energy receives the value of any new environmental credits for the first ten years of the agreement. Palisades and Consumers Energy will share on a 50/50 basis the value of any new environmental credits for years 11 through 15 of the agreement. The environmental credits are defined as benefits from a change in law that causes capability of the plant as of the purchase date to become a tradable attribute (e.g., emission credit, renewable energy credit, environmental credit, “green” credit, etc.) or otherwise to have a market value. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022 and transfer to Holtec thereafter.
Customers
Entergy Wholesale Commodities’ customers for the sale of both energy and capacity from its nuclear plants include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. These customers include Consumers Energy, the company from which Entergy purchased the Palisades plant, and NYISO and MISO. Substantially all the credit exposure associated with the planned energy output under contract for Entergy Wholesale Commodities nuclear plants is with counterparties or their guarantors that have public investment grade credit ratings.
Competition
The NYISO market is highly competitive. Entergy Wholesale Commodities has numerous competitors in New York including generation companies affiliated with regulated utilities, other independent power producers, municipal and co-operative generators, owners of co-generation plants and wholesale power marketers. Entergy Wholesale Commodities is an independent power producer, which means it generates power for sale to third parties at day ahead or spot market prices to the extent that the power is not sold under a fixed price contract. Municipal and co-operative generators also generate power but use most of it to deliver power to their municipal or co-operative power customers. Owners of co-generation plants produce power primarily for their own consumption. Wholesale power marketers do not own generation; rather they buy power from generators or other market participants and resell it to retail providers or other market participants. Competition in the New York power market is affected by, among other factors, the amount of generation and transmission capacity in these markets. MISO does not have a centralized clearing capacity market, but load serving entities do meet most of their capacity needs through bilateral contracts and self-supply with a smaller portion coming through voluntary MISO auctions. Almost all of Palisades’ current output is contracted to Consumers Energy through May 2022. Entergy Wholesale Commodities does not expect to be materially affected by competition in the MISO market in the near term.
Seasonality
Entergy Wholesale Commodities’ revenues and operating income are subject to fluctuations during the year due to seasonal factors, weather conditions, and contract pricing. When outdoor and cooling water temperatures are low, generally during colder months, Entergy Wholesale Commodities nuclear power plants operate more efficiently, and consequently, generate more electricity. Many of Entergy Wholesale Commodities’ contracts provide for shaped pricing over the course of the year. As a result of these factors, Entergy Wholesale Commodities’ revenues are typically higher in the first and third quarters than in the second and fourth quarters.
Fuel Supply
Nuclear Fuel
See “Fuel Supply - Nuclear Fuel” in the Utility portion of Part I, Item 1 for a discussion of the nuclear fuel cycle and markets. Entergy Nuclear Fuels Company, a wholly-owned subsidiary, is responsible for contracts to acquire nuclear materials, except for fuel fabrication, for Entergy Wholesale Commodities nuclear power plants,
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while Entergy Nuclear Operations, Inc. acts as the agent for the purchase of nuclear fuel assembly fabrication services. All contracts for the disposal of spent nuclear fuel are between the DOE and each of the nuclear power plant owners. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment has been adjusted to reflect reduced overall requirements related to the planned permanent shutdowns of the Indian Point 3 and Palisades plants. Fuel procurement for the Entergy Wholesale Commodities segment was primarily limited to the requirements of the Palisades plant’s final refueling in 2020.
Other Business Activities
Entergy Nuclear Power Marketing, LLC (ENPM) was formed in 2005 to centralize the power marketing function for Entergy Wholesale Commodities nuclear plants. Upon its formation, ENPM entered into long-term power purchase agreements with the Entergy Wholesale Commodities subsidiaries that own nuclear power plants (generating subsidiaries). As part of a series of agreements, ENPM agreed to assume and/or otherwise service the existing power purchase agreements that were in effect between the generating subsidiaries and their customers. ENPM’s functions include origination of new energy and capacity transactions and generation scheduling.
Services provided by either Entergy Nuclear, Inc. or other Entergy Wholesale Commodities subsidiaries include engineering, operations and maintenance, fuel procurement, management and supervision, technical support and training, administrative support, and other managerial or technical services required to operate, maintain, and decommission nuclear electric power facilities.
TLG Services, a subsidiary in the Entergy Wholesale Commodities segment, offers decommissioning, engineering, and related services to nuclear power plant owners.
Entergy provides plant operation support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. In 2010 an Entergy subsidiary signed an agreement to extend the management support services to Cooper Nuclear Station by 15 years, through January 2029.
Regulation of Entergy’s Business
Federal Power Act
The Federal Power Act provides the FERC the authority to regulate:
•the transmission and wholesale sale of electric energy in interstate commerce;
•the reliability of the high voltage interstate transmission system through reliability standards;
•sale or acquisition of certain assets;
•securities issuances;
•the licensing of certain hydroelectric projects;
•certain other activities, including accounting policies and practices of electric and gas utilities; and
•changes in control of FERC jurisdictional entities or rate schedules.
The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over the rates charged by Entergy Arkansas and Entergy Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the Utility operating companies. In addition, the FERC regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC regulation of the MISO RTO includes regulation of the design and implementation of the wholesale markets administered by the MISO RTO, as well as the rates, terms, and conditions of open access transmission service over the member systems and the allocation of costs associated with transmission upgrades.
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Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 70 MW of capacity.
State Regulation
Utility
Entergy Arkansas is subject to regulation by the APSC as to the following:
•utility service;
•utility service areas;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery rider;
•terms and conditions of service;
•service standards;
•the acquisition, sale, or lease of any public utility plant or property constituting an operating unit or system;
•certificates of convenience and necessity and certificates of environmental compatibility and public need, as applicable, for generating and transmission facilities;
•avoided cost payments to Qualifying Facilities;
•net energy metering;
•integrated resource planning;
•utility mergers and acquisitions and other changes of control; and
•the issuance and sale of certain securities.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory Authority only if it fails to treat its retail customers in Tennessee in the same manner as its retail customers in Arkansas. Additionally, Entergy Arkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to retail ratemaking or other regulatory jurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment clause and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•certification of certain transmission projects;
•certification of capacity acquisitions, both for owned capacity and purchase power contracts;
•procurement process to acquire over 50 MW;
•audits of the environmental adjustment charge, avoided cost payment to Qualifying Facilities, and energy efficiency rider;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control.
Entergy Mississippi is subject to regulation by the MPSC as to the following:
•utility service;
•utility service areas;
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•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery mechanism;
•terms and conditions of service;
•service standards;
•certification of generating facilities and certain transmission projects;
•avoided cost payments to Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers, acquisitions, and other changes of control.
Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.
Entergy New Orleans is subject to regulation by the City Council as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment charge and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•audit of the environmental adjustment charge;
•certification of the construction or extension of any new plant, equipment, property, or facility that comprises more than 2% of the utility’s rate base;
•integrated resource planning;
•net energy metering;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other changes of control.
To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to the following:
•retail rates and charges, including depreciation rates, and terms and conditions of service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;
•fuel recovery, including reconciliations (audits) of the fuel adjustment charges;
•service standards;
•certification of certain transmission and generation projects;
•utility service areas, including extensions into new areas;
•avoided cost payments to Qualifying Facilities;
•net energy metering; and
•utility mergers, sales/acquisitions/leases of plants over $10 million, sales of greater than 50% voting stock of utilities, and transfers of controlling interest in or operation of utilities.
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Regulation of the Nuclear Power Industry
Atomic Energy Act of 1954 and Energy Reorganization Act of 1974
Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC. Entergy subsidiaries in the Entergy Wholesale Commodities segment are subject to the NRC’s jurisdiction as the owners and operators of Indian Point Energy Center, Palisades, and Big Rock Point.
Nuclear Waste Policy Act of 1982
Spent Nuclear Fuel
Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Entergy’s nuclear owner/licensee subsidiaries have been charged fees for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2020 of $192.0 million for the one-time fee. Entergy accepted assignment of the Pilgrim, FitzPatrick, Indian Point 3, Indian Point 1 and Indian Point 2, Vermont Yankee, Palisades, and Big Rock Point spent fuel disposal contracts with the DOE held by their previous owners. The FitzPatrick spent fuel disposal contract was assigned to Exelon as part of the sale of the plant, completed in March 2017. The Vermont Yankee spent fuel disposal contract was assigned to NorthStar as part of the sale of the plant in January 2019. The Pilgrim spent fuel disposal contract was transferred to Holtec as part of the sale of Entergy Nuclear Generation Company in August 2019. The owners of these plants previous to Entergy have paid or retained liability for the fees for all generation prior to the purchase dates of those plants. The fees payable to the DOE may be adjusted in the future to assure full recovery. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.6 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).
The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing (the DOE filed the license application in June 2008) and, after the license is granted by the NRC, proceed with the repository construction and commencement of receipt of spent fuel. Because the DOE has not begun accepting spent fuel, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts. The DOE continues to delay meeting its obligation. Specific steps were taken to discontinue the Yucca Mountain project, including a motion to the NRC to withdraw the license application with prejudice and the establishment of a commission to develop recommendations for alternative spent fuel storage solutions. In August 2013 the U.S. Court of Appeals for the D.C. Circuit ordered the NRC to continue with the Yucca Mountain license review, but only to the extent of funds previously appropriated by Congress for that purpose and not yet used. Although the NRC completed the safety evaluation report for the license review in 2015, the previously appropriated funds are not sufficient to complete the review, including required hearings. The government has taken no effective action to date related to the recommendations of the appointed spent fuel study commission. Accordingly, large uncertainty remains regarding the time frame under
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which the DOE will begin to accept spent fuel from Entergy’s facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at Entergy’s nuclear sites.
Following the defunding of the Yucca Mountain spent fuel repository program, the National Association of Regulatory Utility Commissioners and others sued the government seeking cessation of collection of the one mill per net kWh generated and sold after April 7, 1983 fee. In November 2013 the D.C. Circuit Court of Appeals ordered the DOE to submit a proposal to Congress to reset the fee to zero until the DOE complies with the Nuclear Waste Policy Act or Congress enacts an alternative waste disposal plan. In January 2014 the DOE submitted the proposal to Congress under protest, and also filed a petition for rehearing with the D.C. Circuit. The petition for rehearing was denied. The zero spent fuel fee went into effect prospectively in May 2014.
As a result of the DOE’s failure to begin disposal of spent nuclear fuel in 1998 pursuant to the Nuclear Waste Policy Act of 1982 and the spent fuel disposal contracts, Entergy’s nuclear owner/licensee subsidiaries have incurred and will continue to incur damages. These subsidiaries have been, and continue to be, involved in litigation to recover the damages caused by the DOE’s delay in performance. See Note 8 to the financial statements for discussion of final judgments recorded by Entergy in 2018, 2019, and 2020 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE. Through 2020, Entergy’s subsidiaries won and collected on judgments against the government totaling approximately $800 million.
Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at Palisades in 1993, at ANO in 1996, at River Bend in 2005, at Grand Gulf in 2006, at Indian Point in 2008, and at Waterford 3 in 2011. These facilities will be expanded as needed.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Louisiana, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, Waterford 3, and Grand Gulf, respectively. In addition, Entergy Louisiana and Entergy Texas are entitled to recover from customers through electric rates the estimated decommissioning costs for the portion of River Bend subject to retail rate regulation. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.
In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In October 2020, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and ANO 2 decommissioning trusts were adequately funded without further collections, and in December 2020, the APSC ordered zero collections for ANO 1 and ANO 2 decommissioning.
In July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend to address previously identified funding shortfalls. This LPSC decision contemplated that the level of decommissioning collections could be revisited should the NRC grant license extensions for both Waterford 3 and River Bend. In July 2019, following the NRC approval of license extensions for Waterford 3 and River Bend, Entergy Louisiana made a filing with the LPSC seeking to adjust decommissioning and depreciation rates for those plants, including one proposed scenario that would adjust Louisiana-jurisdictional decommissioning collections to zero for both plants (including an offsetting increase in depreciation rates). Because of the ongoing public health emergency arising from the COVID-19 pandemic and accompanying economic uncertainty, Entergy Louisiana determined that the relief sought in the filing was no longer appropriate, and in November 2020, filed an unopposed motion to dismiss the proceeding. Following that filing, in a December 2020 order, the LPSC dismissed the proceeding without prejudice.
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In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2018 the PUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning fund was adequate following license renewal.
In September 2016 the NRC issued a 20-year operating license renewal for Grand Gulf. In a 2017 filing at the FERC, System Energy stated that with the renewed operating license, Grand Gulf’s decommissioning trust was sufficiently funded, and proposed, among other things, to cease decommissioning collections for Grand Gulf effective October 1, 2017. The FERC accepted a settlement including the proposed decommissioning revenue requirement by letter order in August 2018.
Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.
In January 2019, Entergy sold 100% of the membership interest in Entergy Nuclear Vermont Yankee to a subsidiary of NorthStar. As a result of the sale, NorthStar assumed ownership of Vermont Yankee and its decommissioning and site restoration trusts, together with complete responsibility for the facility’s decommissioning and site restoration. See Note 9 to the financial statements for further discussion of Vermont Yankee decommissioning costs and see “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the NorthStar transaction.
In August 2019, Entergy sold 100% of the equity interests in Entergy Nuclear Generation Company, LLC to a subsidiary of Holtec International. As a result of the sale, Holtec assumed ownership of Pilgrim and its decommissioning trust, together with complete responsibility for the facility’s decommissioning and site restoration. See Note 14 to the financial statements for further discussion of the sale.
For the Indian Point 3 and FitzPatrick plants purchased in 2000 from NYPA, NYPA retained the decommissioning trust funds and the decommissioning liabilities with the right to require the Entergy subsidiaries to assume each of the decommissioning liabilities provided that it assigns the corresponding decommissioning trust, up to a specified level, to the Entergy subsidiaries. In August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy, which was completed in January 2017. In March 2017, Entergy sold the FitzPatrick plant to Exelon, and as part of the transaction, the FitzPatrick decommissioning trust fund, along with the decommissioning obligation for that plant, was transferred to Exelon. The FitzPatrick spent fuel disposal contract was assigned to Exelon as part of the transaction. See Note 14 to the financial statements for discussion of the FitzPatrick sale.
In March 2020 filings with the NRC were made reporting on decommissioning funding for all of Entergy subsidiaries’ nuclear plants. Those reports showed that decommissioning funding for each of the nuclear plants met the NRC’s financial assurance requirements.
Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 16 to the financial statements.
Price-Anderson Act
The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect the public in the event of a nuclear power plant accident. The costs of this insurance
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are borne by the nuclear power industry. Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025. The Price-Anderson Act limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $137.6 million per reactor (with 97 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, System Energy, or an Entergy Wholesale Commodities company is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units is also purchased. The Price-Anderson Act and insurance applicable to the nuclear programs of Entergy are discussed in more detail in Note 8 to the financial statements.
NRC Reactor Oversight Process
The NRC’s Reactor Oversight Process is a program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response. The NRC evaluates plant performance by analyzing two distinct inputs: inspection findings resulting from the NRC’s inspection program and performance indicators reported by the licensee. The evaluations result in the placement of each plant in one of the NRC’s Reactor Oversight Process Action Matrix columns: “licensee response column,” or Column 1, “regulatory response column,” or Column 2, “degraded cornerstone column,” or Column 3, and “multiple/repetitive degraded cornerstone column,” or Column 4. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject to progressively increasing levels of inspection by the NRC with, in general, progressively increasing levels of associated costs. The nuclear generating plants owned and operated by Entergy’s Utility and Entergy Wholesale Commodities businesses are currently in Column 1, except for Grand Gulf, which is currently in Column 2.
In November 2020 the NRC placed Grand Gulf in Column 2 based on the incidence of three unplanned plant scrams during the second and third quarters of 2020.Two of the scram events related to new turbine control system components that failed, and a third related to a feedwater valve positioner that failed, all of which had been replaced in a refueling outage that ended in May 2020. The NRC plans to conduct a supplemental inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 2. As a consequence of two additional Grand Gulf scrams during the fourth quarter 2020, System Energy expects Grand Gulf to be placed into NRC Column 3 based on plant performance indicators for the four quarters ended December 31, 2020. This will involve an additional supplemental NRC inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 3.
Environmental Regulation
Entergy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy’s businesses are in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted below. Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely estimated. Except to the extent discussed below, at this time compliance with federal, state, and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Entergy’s businesses and is not expected to have a material effect on their competitive position, results of operations, cash flows, or financial position.
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Clean Air Act and Subsequent Amendments
The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a lesser extent, certain operations at nuclear and other facilities. Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements. These programs include:
•New source review and preconstruction permits for new sources of criteria air pollutants, greenhouse gases, and significant modifications to existing facilities;
•Acid rain program for control of sulfur dioxide (SO2) and nitrogen oxides (NOx);
•Nonattainment area programs for control of criteria air pollutants, which could include fee assessments for air pollutant emission sources under Section 185 of the Clean Air Act if attainment is not reached in a timely manner;
•Hazardous air pollutant emissions reduction programs;
•Interstate Air Transport;
•Operating permit programs and enforcement of these and other Clean Air Act programs;
•Regional Haze programs; and
•New and existing source standards for greenhouse gas and other air emissions.
New Source Review (NSR)
Preconstruction permits are required for new facilities and for existing facilities that undergo a modification that results in a significant net emissions increase and is not classified as routine repair, maintenance, or replacement. Units that undergo certain non-routine modifications must obtain a permit modification and may be required to install additional air pollution control technologies. In December 2020 the EPA amended the NSR regulations to clarify when a physical change or change in the method of operation will constitute such a modification. Entergy has an established process for identifying modifications requiring additional permitting approval and is monitoring the regulations and associated guidance provided by the states and the federal government with regard to the determination of routine repair, maintenance, and replacement. Several years ago, however, the EPA implemented an enforcement initiative, aimed primarily at coal plants, to identify modifications that it does not consider routine for which the unit did not obtain a modified permit. Various courts and the EPA have been inconsistent in their judgments regarding modifications that are considered routine and on other legal issues that affect this program.
In February 2011, Entergy received a request from the EPA for several categories of information concerning capital and maintenance projects at the White Bluff and Independence facilities, both located in Arkansas, in order to determine compliance with the Clean Air Act, including NSR requirements and air permits issued by the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ). In August 2011, Entergy’s Nelson facility, located in Louisiana, received a similar request for information from the EPA. In September 2015 an additional request for similar information was received for the White Bluff facility. Entergy responded to all requests. None of these EPA requests for information alleged that the facilities were in violation of law.
In January and February 2018, Entergy Arkansas, Entergy Mississippi, Entergy Power, and other co-owners received 60-day notice of intent to sue letters from the Sierra Club and the National Parks Conservation Association concerning allegations of violations of new source review and permitting provisions of the Clean Air Act at the Independence and White Bluff coal-burning units, respectively. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims as well as other issues facing Entergy Arkansas’s fossil generation plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, is subject to approval by the U.S. District Court for the Eastern District of Arkansas. In October 2019 the District Court requested supplemental briefing on several issues to be resolved prior to addressing the motion to approve the
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settlement; that briefing was completed in May 2020. For further information about the settlement, see “Regional Haze” discussed below.
National Ambient Air Quality Standards
The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide, and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is classified as “marginal,” “moderate,” “serious,” or “severe.” When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.
Ozone Nonattainment
Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area that is not in attainment with the applicable NAAQS for ozone. The ozone nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Both Lewis Creek and the Montgomery County Power Station hold all necessary permits for construction and operation and comply with applicable air quality program regulations. Measures enacted to return the area to ozone attainment could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the ozone NAAQS.
Potential SO2Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. In Entergy’s utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana are designated as nonattainment. In August 2017 the EPA issued a letter indicating that East Baton Rouge and St. Charles parishes would be designated by December 31, 2020, as monitors were installed to determine compliance. In December 2020 the EPA designated East Baton Rouge, St. Charles, St. James, and West Baton Rouge parishes in Louisiana as attainment/unclassifiable, and, in Texas, Jefferson County as attainment/unclassifiable and Orange County as unclassifiable. Challenges to these final designations must be filed within 60 days of publication in the Federal Register. Entergy continues to monitor this situation.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2020 the EPA finalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. The final appropriate and necessary finding does not revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. Entergy will continue to monitor this situation.
Cross-State Air Pollution
In March 2005 the EPA finalized the Clean Air Interstate Rule (CAIR), which was intended to reduce SO2 and NOx emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule required a combination of capital investment to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy.
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Based on several court challenges, CAIR and its subsequent versions, now known as the Cross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions. In September 2016 the EPA finalized the CSAPR Update Rule to address interstate transport for the 2008 ozone NAAQS. Starting in 2017 the final rule requires reductions in summer nitrogen oxides (NOx) emissions. Several states, including Arkansas and Texas, filed a challenge to the Update Rule. In September 2019 the D.C. Circuit upheld the EPA’s underlying approach to the Update Rule, but determined that it was inconsistent with the Clean Air Act because it failed to include deadlines consistent with downwind states’ deadlines for attainment. The court remanded the rule to the EPA for further consideration, but did not vacate so the rule remains in effect pending the EPA’s further review. In October 2020 the EPA issued its proposal intended to address the D.C. Circuit’s remand. The draft rule proposes to finalize interstate transport obligations for 21 states. For nine states, including Arkansas, Mississippi, and Texas, the EPA proposes that additional emission reductions are not necessary. For 12 states, however, including Louisiana, the EPA proposes additional emission reductions through proposed reductions in the number of NOx emission allowances allocated to each state. Entergy, through its various trade associations, filed comments on the proposal and will continue to monitor the rulemaking and its potential impact on its facilities in Louisiana. If the October 2020 proposal is finalized, ozone season NOx emissions may become more expensive in Louisiana.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could result in a requirement to install SO2 and NOx pollution control technology as Best Available Retrofit Control Technology (BART) to continue operating certain of Entergy’s fossil generation units. The rule leaves certain CAVR determinations to the states.
In Arkansas, the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ) prepared a state implementation plan (SIP) for Arkansas facilities to implement its obligations under the CAVR. In April 2012 the EPA finalized a decision addressing the Arkansas Regional Haze SIP, in which it disapproved a large portion of the Arkansas plan, including the emission limits for NOx and SO2 at White Bluff. In April 2015 the EPA published a proposed federal implementation plan (FIP) for Arkansas, taking comment on requiring installation of scrubbers and low NOx burners to continue operating both units at the White Bluff plant and both units at the Independence plant and NOx controls to continue operating the Lake Catherine plant. Entergy filed comments by the deadline in August 2015. Among other comments, including opposition to the EPA’s proposed controls on the Independence units, Entergy proposed to meet more stringent SO2 and NOx limits at both White Bluff and Independence within three years of the effective date of the final FIP and to cease the use of coal at the White Bluff units at a later date.
In September 2016 the EPA published the final Arkansas Regional Haze FIP. In most respects, the EPA finalized its original proposal but shortened the time for compliance for installation of the NOx controls. The FIP required an emission limitation consistent with SO2 scrubbers at both White Bluff and Independence by October 2021 and NOx controls by April 2018. The EPA declined to adopt Entergy’s proposals related to ceasing coal use as an alternative to SO2 scrubbers for White Bluff SO2 BART. In November 2016, Entergy and other interested parties, including the State of Arkansas, filed petitions for administrative reconsideration and stay at the EPA as well as petitions for judicial review in the U.S. Court of Appeals for the Eighth Circuit. The Eighth Circuit granted the stay pending settlement discussions and pending the State’s development of a SIP that, if approved by the EPA, would replace the FIP. The state had proposed its replacement SIP in two parts: Part I considers NOx requirements, and Part II considers SO2 requirements. The EPA approved the Part I NOx SIP in January 2018. The Part I SIP requires that Entergy address NOx impacts on visibility via compliance with the Cross-State Air Pollution Rule ozone-season emission trading program. Arkansas has finalized a Part II SIP which has been approved by the EPA but is currently pending a state court appeal. That appeal has been stayed pending the outcome of a federal court case, which may resolve many of the issues on appeal. The final Part II SIP requires that Entergy achieve SO2 emission reductions via the use of low-sulfur coal at both White Bluff and Independence within three years. The
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Part II SIP also requires that Entergy cease to use coal at White Bluff by December 31, 2028 and notes the current planning assumption that Entergy’s Independence units will cease to use coal by December 31, 2030.
In January and February 2018, Entergy Arkansas, Entergy Mississippi, Entergy Power, and other co-owners received 60-day notice of intent to sue letters from the Sierra Club and the National Parks Conservation Association concerning allegations of violations of new source review and permitting provisions of the Clean Air Act at the Independence and White Bluff coal-burning units, respectively. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims and reducing the risk that Entergy Arkansas, as operator of Independence and White Bluff, might be compelled under the Clean Air Act’s regional haze program to install costly emissions control technologies. Consistent with the terms of the settlement and in many cases also the Part II SIP, Entergy Arkansas, along with co-owners, will begin using only low-sulfur coal at Independence and White Bluff by mid-2021; cease to use coal at White Bluff and Independence by the end of 2028 and 2030, respectively; cease operation of the remaining gas unit at Lake Catherine by the end of 2027; reserve the option to develop new generating sources at each plant site; and commit to install or propose to regulators at least 800 MWs of renewable generation by the end of 2027, with at least half installed or proposed by the end of 2022 (which includes two existing Entergy Arkansas projects) and with all qualifying co-owner projects counting toward satisfaction of the obligation. Under the settlement, the Sierra Club and the National Parks Conservation Association also waive certain potential existing claims under federal and state environmental law with respect to specified generating plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, is subject to approval by the U.S. District Court for the Eastern District of Arkansas. The EPA, which is allowed to comment on such a settlement agreement, has stated that it has no objections to the settlement. In November 2020 the court denied motions by the Arkansas Attorney General and the Arkansas Affordable Energy Coalition to intervene and to stay the proceedings. The proposed intervenors did not appeal the ruling. Still pending before the court is a motion by the plaintiffs to approve the settlement, in support of which Entergy made a filing. The Arkansas Attorney General also filed an application before the APSC in December 2018 seeking an investigation into the effects of the settlement. The Arkansas Affordable Energy Coalition filed to support the Arkansas Attorney General’s application, and Entergy Arkansas filed a motion to dismiss it. The application remains pending before the APSC. In October 2019 the District Court requested supplemental briefing on several issues prior to addressing the motion to approve the settlement; that briefing concluded in May 2020.
In Louisiana, Entergy has worked with the Louisiana Department of Environmental Quality (LDEQ) and the EPA to revise the Louisiana SIP for regional haze, which had been disapproved in part in 2012. The LDEQ submitted a revised SIP in February 2017. In May 2017 the EPA proposed to approve a majority of the revisions. In September 2017 the EPA issued a proposed SIP approval for the Nelson plant, requiring an emission limitation consistent with the use of low-sulfur coal, with a compliance date of January 22, 2021. The EPA issued final approval in December 2017. The EPA approval was appealed to the U.S. Court of Appeals for the Fifth Circuit. In October 2019 the Fifth Circuit affirmed the EPA’s SIP approval. A petition for rehearing filed by plaintiffs was denied by the Fifth Circuit. Plaintiffs did not petition for further review by the Supreme Court.
The second planning period (2018-2028) for the regional haze program requires states to examine sources for impacts on visibility and to prepare SIPs by 2021. Entergy received information collection requests from Arkansas and Louisiana requesting an evaluation of technical and economic feasibility of various NOx and SO2 control technologies for Independence, Nelson 6, and Ninemile. Responses to the information requests have been submitted to the respective state agencies.
New and Existing Source Performance Standards for Greenhouse Gas Emissions
In July 2019 the EPA released the Affordable Clean Energy Rule (ACE), which applies only to existing coal-fired electric generating units. The ACE determines that heat rate improvements are the best system of emission reductions and lists six candidate technologies for consideration by states at each coal unit. The rule and associated rulemakings by the EPA replace the Obama administration’s Clean Power Plan, which established
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national emissions performance rates for existing fossil-fuel fired steam electric generating units and combustion turbines. The ACE rule provides states discretion in determining how the best system for emission reductions applies to individual units, including through the consideration of technical feasibility and the remaining useful life of the facility. The ADEQ and the LDEQ have issued information collection requests to Entergy facilities to help the states collect the information needed to determine the best system of emission reductions for each facility. Entergy responded to the requests and will continue to monitor litigation challenging the rule. In January 2021 the U.S. Court of Appeals for the D.C. Circuit vacated ACE. The court held that ACE relied on an incorrect interpretation of the Clean Air Act that the statute expressly forecloses emission reduction approaches, such as emissions trading and generating shifting, that cannot be applied at and to the individual source. The court remanded ACE to the EPA for further consideration and also vacated the repeal of the Clean Power Plan. The vacatur will not be effective until the court issues its mandate which is being held until after disposition of any petitions for rehearing. Entergy is currently reviewing the court’s opinion.
In 2018 the EPA proposed a revision to the new source performance standard on greenhouse gas emissions that primarily impacts new coal units and, therefore, should not impact Entergy. In January 2021 the EPA finalized a pollutant-specific contribution finding for greenhouse gas emissions from new, modified, and reconstructed electric generating units. The rule establishes a three percent threshold for determining when a pollutant significantly contributes to air pollution and reaffirms the EPA’s position that the Clean Air Act Section 111(b) requires the EPA to make pollutant-specific significant contribution findings before promulgation of a new source performance standard. The EPA did not, however, finalize the new source performance standard on greenhouse gas emissions and intends to address the 2018 proposal in a future action.
Potential Legislative, Regulatory, and Judicial Developments
In addition to the specific instances described above, there are a number of legislative and regulatory initiatives concerning air emissions, as well as other media, that are under consideration at the federal, state, and local level. Because of the nature of Entergy’s business, the imposition of any of these initiatives could affect Entergy’s operations. Entergy continues to monitor these initiatives and activities in order to analyze their potential operational and cost implications. These initiatives include:
•designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;
•introduction of bills in Congress and development of regulations by the EPA proposing further limits on NOx, SO2, mercury, and carbon dioxide and other air emissions. New legislation or regulations applicable to stationary sources could take the form of market-based cap-and-trade programs, direct requirements for the installation of air emission controls onto air emission sources, or other or combined regulatory programs;
•efforts in Congress or at the EPA to establish a federal carbon dioxide emission tax, control structure, or unit performance standards;
•revisions to the estimates of the Social Cost of Carbon and its use for regulatory impact analysis of federal laws and regulations;
•implementation of the Regional Greenhouse Gas Initiative by several states in the northeastern United States and similar actions in other regions of the United States;
•efforts on the local, state, and federal level to codify renewable portfolio standards, clean energy standards, or a similar mechanism requiring utilities to produce or purchase a certain percentage of their power from defined renewable energy sources or energy sources with lower emissions;
•efforts to develop more stringent state water quality standards, effluent limitations for Entergy’s industry sector, stormwater runoff control regulations, and cooling water intake structure requirements;
•efforts to restrict the previously-approved continued use of oil-filled equipment containing certain levels of polychlorinated biphenyls (PCBs);
•efforts by certain external groups to encourage reporting and disclosure of environmental, social, and governance risk;
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•the listing of additional species as threatened or endangered, the protection of critical habitat for these species, and developments in the legal protection of eagles and migratory birds;
•the regulation of the management, disposal, and beneficial reuse of coal combustion residuals; and
•the regulation of the management and disposal and recycling of equipment associated with renewable and clean energy sources such as used solar panels, wind turbine blades, hydrogen usage, or battery storage.
Entergy continues to support national legislation that would increase planning certainty for electric utilities while addressing carbon dioxide emissions in an economy-wide, responsible, and flexible manner. By virtue of its proportionally large investment in low-emitting generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020. In 2020, Entergy succeeded in achieving its initial climate commitment to reduce carbon dioxide cumulative emissions by 20% from 2000 levels. Total carbon dioxide emissions representing Entergy’s ownership share of power plants and controllable power purchases in the United States were approximately 39.1 million tons in 2020 and 40.7 million tons in 2019. Since its original commitment in 2001, Entergy’s cumulative emissions are approximately 7.6% below its 2020 goal.
Entergy voluntarily conducted a climate scenario analysis and published a comprehensive report in March 2019. The report follows the framework and recommendations of the Task Force on Climate-related Disclosures, describing climate-related governance, strategy, risk management, and metrics and targets. Scenario analyses resulted in Entergy developing and publishing a new goal of reducing the Utility’s emission rate by 50 percent from 2000 levels by 2030. In September 2020, Entergy committed to achieving net-zero carbon emissions by 2050, while continuing its commitment to grid reliability and affordability for customers. In December 2020, Entergy published a report regarding this long-term commitment that describes its approach and technology point-of-view. Technology research and development, innovation, and advancement are critical to Entergy’s ability to meet this climate commitment.
Entergy participates in the M.J. Bradley & Associates’ Annual Benchmarking Air Emissions Report, an annual analysis of the 100 largest U.S. electric power producers. The report is available on the M.J. Bradley website. Entergy’s annual greenhouse gas emissions inventory is also third-party verified, and that certification is made available on the American Carbon Registry website. Entergy participates annually in the Dow Jones Sustainability Index and in 2020 was listed on the North American Index. Entergy has been listed on the World or North American Index, or both, for nineteen consecutive years. Entergy also participated in the 2020 CDP and CDP Water evaluations, receiving a ‘B’ for both responses.
Clean Water Act
The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act) provide the statutory basis for the National Pollutant Discharge Elimination System permit program, section 402, and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The Clean Water Act requires virtually all discharges of pollutants to waters of the United States to be permitted. Section 316(b) of the Clean Water Act regulates cooling water intake structures, section 401 of the Clean Water Act requires a water quality certification from the state in support of certain federal actions and approvals, and section 404 regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.
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Steam Electric Effluent Guidelines
The 2015 Steam Electric Effluent Limitations Guidelines (ELG) rule required, among other things, that there be no discharge of bottom ash transport water. In October 2020 the EPA issued its final rule revision on bottom ash transport water allowing the discharge of up to 10% system volume for certain purge waters, including storm events and non-routine operations. The final rule requires compliance as soon as possible beginning October 31, 2021, but no later than December 31, 2025. Several challenges to the final rule have been filed. Additionally, the Fifth Circuit Court of Appeals previously vacated and remanded the provisions of the rule related to legacy wastewater and leachate, which the EPA plans to address in a separate rulemaking. Despite the final rule and pending challenges, Entergy is implementing projects at its White Bluff and Independence plants to convert to zero-discharge systems to comply with the ELG rule and the coal combustion residuals restrictions on impoundments. Additionally, the Nelson Unit 6 facility is implementing operational and maintenance measures to minimize the potential for discharge of bottom ash transport water from the existing bottom ash handling system at the site, and is reviewing the effectiveness of these changes for compliance with the requirements of the October 2020 final rule.
Federal Jurisdiction of Waters of the United States
In February 2019 the EPA published its proposed revised definition of Waters of the United States, which proposes to narrow the scope of Clean Water Act jurisdiction, as compared to a 2015 definition which had been stayed by several federal courts. The final rule was released in January 2020 and effective in June 2020. In October 2019 the EPA repealed the 2015 rule and re-codified the pre-existing regulations. That rule was effective late December 2019. Numerous challenges have been filed against both rules.
Groundwater at Certain Nuclear Sites
The NRC requires nuclear power plants to monitor and report regularly the presence of radioactive material in the environment. Entergy joined other nuclear utilities and the Nuclear Energy Institute in 2006 to develop a voluntary groundwater monitoring and protection program. This initiative began after detection of very low levels of radioactive material, primarily tritium, in groundwater at several plants in the United States. Tritium is a radioactive form of hydrogen that occurs naturally and is also a byproduct of nuclear plant operations. In addition to tritium, other radionuclides have been found in site groundwater at nuclear plants.
As part of the groundwater monitoring and protection program, Entergy has: (1) performed reviews of plant groundwater characteristics (hydrology) and historical records of past events on site that may have potentially impacted groundwater; (2) implemented fleet procedures on how to handle events that could impact groundwater; and (3) installed groundwater monitoring wells and began periodic sampling. The program also includes protocols for notifying local officials if contamination is found. To date, radionuclides such as tritium have been detected at Arkansas Nuclear One, Indian Point, Palisades, Grand Gulf, and River Bend. Each of these sites has installed groundwater monitoring wells and implemented a program for testing groundwater at the sites for the presence of tritium and other radionuclides. Based on current information, the concentrations and locations of radionuclides detected at these plants pose no threat to public health or safety, but each site continues to evaluate the results from its groundwater monitoring program.
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint, and several liability on responsible parties. Many states have adopted programs similar to CERCLA. Entergy subsidiaries in the Utility and Entergy Wholesale Commodities businesses have sent waste materials to various
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disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been or will be sold to decommissioning companies. In addition, environmental laws now regulate certain of Entergy’s operating procedures and maintenance practices that historically were not subject to regulation. Some disposal sites used by Entergy subsidiaries have been the subject of governmental action under CERCLA or similar state programs, resulting in site clean-up activities. Entergy subsidiaries have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs. The affected Entergy subsidiaries have established provisions for the liabilities for such environmental clean-up and restoration activities. Details of potentially material CERCLA and similar state program liabilities are discussed in the “Other Environmental Matters” section below.
Coal Combustion Residuals
In June 2010 the EPA issued a proposed rule on coal combustion residuals (CCRs) that contained two primary regulatory options: (1) regulating CCRs destined for disposal in landfills or received (including stored) in surface impoundments as so-called “special wastes” under the hazardous waste program of Resource Conservation and Recovery Act (RCRA) Subtitle C; or (2) regulating CCRs destined for disposal in landfills or surface impoundments as non-hazardous wastes under Subtitle D of RCRA. Under both options, CCRs that are beneficially reused in certain processes would remain excluded from hazardous waste regulation. In April 2015 the EPA published the final CCR rule with the material being regulated under the second scenario presented above - as non-hazardous wastes regulated under RCRA Subtitle D.
The final regulations create new compliance requirements including modified storage, new notification and reporting practices, product disposal considerations, and CCR unit closure criteria. Entergy believes that on-site disposal options will be available at its facilities, to the extent needed for CCR that cannot be transferred for beneficial reuse. As of December 31, 2020, Entergy has recorded asset retirement obligations related to CCR management of $20.1 million.
In December 2016 the Water Infrastructure Improvements for the Nation Act (WIIN Act) was signed into law, which authorizes states to regulate coal ash rather than leaving primary enforcement to citizen suit actions. States may submit to the EPA proposals for a permit program.
Pursuant to the EPA Rule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area, but has not indicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and detection monitoring will continue as the rule requires. In late-2017, Entergy determined that certain in-ground wastewater treatment system recycle ponds at its White Bluff and Independence facilities require management under the new EPA regulations. Consequently, in order to move away from using the recycle ponds, White Bluff and Independence each have installed a new permanent bottom ash handling system that does not fall under the CCR rule. As of November 2020, both sites are operating the new system and no longer are sending waste to the recycle ponds. Each site has commenced closure of one of its two recycle ponds, with the remaining pond being held in reserve during initial operation of the new bottom ash handling system. Closure of the remaining recycle pond at each site will commence as soon as possible, but no later than April 11, 2021, which is the deadline under the finalized CCR rule to commence closure of any unlined recycle ponds. Any potential requirements for corrective action or operational changes under the new CCR rule continue to be assessed. Notably, ongoing litigation has resulted in the EPA’s continuing review of the rule. Consequently, the nature and cost of additional corrective action requirements may depend, in part, on the outcome of the EPA’s review.
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Other Environmental Matters
Entergy Louisiana and Entergy Texas
Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, currently is involved in the second phase of the remedial investigation of the Lake Charles Service Center site, located in Lake Charles, Louisiana. A manufactured gas plant (MGP) is believed to have operated at this site from approximately 1916 to 1931. Coal tar, a by-product of the distillation process employed at MGPs, apparently was routed to a portion of the property for disposal. The same area also has been used as a landfill. In 1999, Entergy Gulf States, Inc. signed a second administrative consent order with the EPA to perform a removal action at the site. Removal actions addressed contaminated source material, soil, and sediment and included capping certain soil on and off-site. In 2002 approximately 7,400 tons of contaminated soil and debris were excavated and disposed of from an area within the service center. In 2003 a cap was constructed over the remedial area to prevent the migration of contamination to the surface. In August 2005 an administrative order was issued by the EPA requiring that a 10-year groundwater study be conducted at this site. The groundwater monitoring study commenced in January 2006. The EPA released the second Five Year Review in 2015. In that review, the EPA indicated that the remediation technique was insufficient and that Entergy would need to utilize other remediation technologies on the site. In July 2015, Entergy submitted a Focused Feasibility Study to the EPA outlining the potential remedies and suggesting installation of the new remedial method, a waterloo barrier. The estimated cost for this remedy is approximately $2 million, to be allocated between Entergy Louisiana and Entergy Texas. In early 2017 the EPA indicated that the waterloo barrier may not be necessary and requested revisions to the Focused Feasibility Study. The EPA released the third Five Year Review in late-2019 confirming that a new remedial method is not necessary but requiring continuation of the current groundwater monitoring. The site’s remedy includes monitored natural attenuation of groundwater, and institutional controls to restrict groundwater and land use. The EPA has determined that no additional actions are needed for the remedy to be protective over the long-term, and the remedy is protective of human health and the environment.
Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas
The Texas Commission on Environmental Quality (TCEQ) notified Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas that the TCEQ believes those entities are potentially responsible parties (PRPs) concerning contamination existing at the San Angelo Electric Service Company (SESCO) facility in San Angelo, Texas. The facility operated as a transformer repair and scrapping facility from the 1930s until 2003. Both soil and groundwater contamination existed at the site. Entergy subsidiaries sent transformers to this facility. Entergy Arkansas, Entergy Louisiana, and Entergy Texas responded to an information request from the TCEQ. Entergy Louisiana and Entergy Texas joined a group of PRPs responding to site conditions in cooperation with the State of Texas, creating cost allocation models based on review of SESCO documents and employee interviews, and investigating contribution actions against other PRPs. Entergy Louisiana and Entergy Texas have agreed to contribute to the remediation of contaminated soil and groundwater at the site in a measure proportionate to those companies’ involvement at the site. Current estimates, although variable depending on ultimate remediation design and performance, indicate that Entergy’s total share of remediation costs likely will be approximately $1.5 million to $2 million. Groundwater monitoring wells at the site were plugged and abandoned in December 2019 following receipt of a certificate of completion issued by the TCEQ. Site decommissioning activities are complete and final disposition of the property will be determined at a later time.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas
The EPA notified Entergy that the EPA believes Entergy is a PRP concerning PCB contamination at the F.J. Doyle Salvage facility in Leonard, Texas. The facility operated as a scrap salvage business during the 1970s to the 1990s. In May 2018 the EPA investigated the site surface and sub-surface soils and, in November 2018 the EPA conducted a removal action, including disposal of PCB contaminated soils. Entergy responded to the EPA’s information requests in May and July 2019. In November 2020 the EPA sent Entergy and other PRPs a demand
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letter seeking reimbursement for response costs totaling $4 million expended at the site. The demand letter is being evaluated and liability and PRP allocation of response costs are yet to be determined.
Entergy Texas
In December 2016 a transformer inside the Hartburg, Texas Substation had an internal fault resulting in a release of approximately 15,000 gallons of non-PCB mineral oil. Cleanup ensued immediately; however, rain caused much of the oil to spread across the substation yard and into a nearby wetland. The TCEQ and the National Response Center were immediately notified, and the TCEQ responded to the site approximately two hours after the cleanup was initiated. The remediation liability is estimated at $2.2 million; however, this number could fluctuate depending on the remediation extent and wetland mitigation requirements. In July 2017, Entergy entered into the Voluntary Cleanup Program with the TCEQ. In November 2017, additional soil sampling was completed in the wetland area and, in February 2018, a site summary report of findings was submitted to the TCEQ. The TCEQ responded in June 2018 and requested an ecological exclusion criteria checklist/Tier II screening-level ecological risk assessment, and additional site assessment, additional soil samples, groundwater samples, and some additional diagrams and maps. In October 2018, Entergy submitted the requested information to the TCEQ. In January 2019 the TCEQ responded with another request for information. In March 2019, Entergy submitted the requested information to the TCEQ. In August 2019 the TCEQ responded with a request for additional information including an Affected Property Assessment Report (APAR) and water well survey. The TCEQ has agreed that the necessity of the water well survey is dependent on the results of the groundwater resampling that will occur. Groundwater sampling was completed in December 2019 and results were submitted to the TCEQ for review. Based on the groundwater sampling results, the TCEQ confirmed in February 2020 that a water well survey is not necessary and requested the APAR and an Ecological Risk Assessment by August 2020. Due to COVID-19 delays, the TCEQ extended the APAR and Ecological Risk Assessment submittal dates to December 2020, which Entergy timely met.
Litigation
Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but certain states in which Entergy operates have proven to be unusually litigious environments. Judges and juries in Louisiana, Mississippi, and Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. The litigation environment in these states poses a significant business risk to Entergy.
Asbestos Litigation(Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)
See Note 8 to the financial statements for a discussion of this litigation.
Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
See Note 8 to the financial statements for a discussion of these proceedings.
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Human Capital
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2020, Entergy subsidiaries employed 13,400 people.
| | | | | |
Utility: | |
Entergy Arkansas | 1,244 | |
Entergy Louisiana | 1,654 | |
Entergy Mississippi | 750 | |
Entergy New Orleans | 303 | |
Entergy Texas | 658 | |
System Energy | — | |
Entergy Operations | 3,529 | |
Entergy Services | 3,859 | |
Entergy Nuclear Operations | 1,356 | |
Other subsidiaries | 47 | |
Total Entergy | 13,400 | |
Approximately 3,900 employees are represented by the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the International Brotherhood of Teamsters, the United Government Security Officers of America, and the International Union, Security, Police, and Fire Professionals of America.
Below is the breakdown of Entergy’s employees by gender and race/ethnicity:
| | | | | | | | | | | |
Gender (%) | 2020 | | 2019 |
Female | 21 | | 20 |
Male | 79 | | 80 |
| 100 | | 100 |
| | | | | | | | | | | |
Race/Ethnicity (%) | 2020 | | 2019 |
White | 78 | | 79 |
Black/African American | 15 | | 15 |
Hispanic/Latino | 3 | | 2 |
Asian | 2 | | 2 |
Other | 2 | | 2 |
| 100 | | 100 |
Entergy’s Approach to Human Resources
Entergy’s people and culture enable its success; that is why acquiring, retaining, and developing talent are important components of Entergy’s human resources strategy. Entergy focuses on an approach that includes, among other things, governance and oversight; safety; organizational health, including diversity, inclusion and belonging; and talent management.
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Governance and Oversight
Ensuring that workplace processes support the desired culture and strategy begins with the Board of Directors and the Office of the Chief Executive. The Personnel Committee establishes priorities and reviews performance on a range of topics. It oversees Entergy’s incentive plan design and administers its executive compensation plans to incentivize the behaviors and outcomes that support achievement of Entergy’s corporate objectives. Annually, it reviews executive performance, development and succession plans to align a high performing executive team with Entergy’s priorities. The Personnel Committee also oversees Entergy’s performance through regular briefings on a wide variety of human resources topics including Entergy’s safety culture and performance; organizational health; and diversity, inclusion, and belonging initiatives and performance.
Other committees of the Board oversee other key aspects of Entergy’s culture. For example, the Audit Committee reviews reports on ethics and compliance training and performance, as well as regular reports on calls made to Entergy’s ethics line and related investigations. To maximize the sharing of information and facilitate the participation of all Board members in these discussions, the Board schedules its regular committee meetings in a manner such that all directors can attend.
The Office of the Chief Executive, which includes the Senior Vice President and Chief Human Resources Officer, ensures annual business plans are designed to support Entergy’s talent objectives, reviews workforce-related metrics, and regularly discusses the development, succession planning, and performance of their direct reports and other company officers.
Safety
Entergy’s safety objective is: Everyone Safe. All Day. Every Day. While the COVID-19 pandemic and historical hurricane season presented significant challenges, Entergy’s safety strategy and commitment to excellence showed results in 2020. Entergy employees achieved a total recordable incident rate of 0.40 in 2020 compared to 0.56 in 2019 and 0.48 in 2018. The recordable incident rate equals the number of recordable incidents per 100 full-time equivalents. Recordable incidents include fatalities, lost-time accidents, restricted-duty accidents, and medical attentions and is not inclusive of potential work-related COVID-19 cases. This marked improvement in total recordable incident rate placed Entergy in top-decile in safety performance when benchmarked amongst peers within the Edison Electric Institute.
Organizational Health, including Diversity, Inclusion and Belonging
Entergy believes that organizational health fosters an engaged and productive culture that positions Entergy to deliver sustainable value to its stakeholders. Entergy measures its progress through an organizational health survey coordinated by an external third party. Since initially administering the survey in 2014, Entergy improved from an initial score of 49 (fourth quartile) to a score in 2020 of 72 (near top quartile). In addition to significantly improved scores, initial employee participation of 66 percent in 2014 rose to and remains at 90 percent in 2018-2020.
Entergy believes that a culture focused on diversity, inclusion, and belonging drives foundational engagement. Entergy is committed to developing and retaining a workforce that reflects the rich diversity of the communities it serves. In 2019, Entergy embarked on a three-year phased approach to enhance inclusion for individuals and teams. Among other actions, the primary focus of its 2020 actions was taking a stand against social injustice, reinforcing expectations, training and leading by example, starting at the top of the organization and cascading through management ranks.
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Talent Management
Entergy’s focus on talent management is organized in three areas: developing and attracting a diverse pool of talent, equipping its leaders to develop the organization, and building premier utility capability through employee performance management and succession programs. Entergy believes that developing a diverse pool of local talent equipped with the skills needed, today and in the future, and reflecting the communities Entergy serves will give it a long-term competitive advantage. The focus of Entergy’s leadership development programs is to equip managers with the skills needed to effectively develop their teams and improve the leader-employee relationship. Entergy’s talent development infrastructure, which includes a combination of business function-specific and enterprise-wide learning and development programs, is designed to ensure Entergy has qualified staff with the skills, experiences, and behaviors needed to perform today and prepare for the future. Entergy strives to achieve its strategic priorities by aligning and enhancing team and individual performance with business objectives, effectively deploying talent through succession planning, and managing workforce transitions.
Availability of SEC filings and other information on Entergy’s website
Entergy electronically files reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies, and amendments to such reports. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. Copies of the reports that Entergy files with the SEC can be obtained at the SEC’s website.
Entergy uses its website, http://www.entergy.com, as a routine channel for distribution of important information, including news releases, analyst presentations and financial information. Filings made with the SEC are posted and available without charge on Entergy’s website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These filings include annual and quarterly reports on Forms 10-K and 10-Q (including related filings in Inline XBRL format) and current reports on Form 8-K; proxy statements; and any amendments to those reports or statements. All such postings and filings are available on Entergy’s Investor Relations website free of charge. Entergy is providing the address to its internet site solely for the information of investors and does not intend the address to be an active link. The contents of the website are not incorporated into this report.
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RISK FACTORS
See “RISK FACTOR SUMMARY” in Part I Item 1 for a summary of Entergy’s and the Registrant Subsidiaries’ risk factors.
Investors should review carefully the following risk factors and the other information in this Form 10-K. The risks that Entergy faces are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect Entergy’s financial condition, results of operations, and liquidity. See “FORWARD-LOOKING INFORMATION.”
Utility Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The impacts of the COVID-19 pandemic and responsive measures taken on Entergy’s and its Utility operating companies’ business, results of operations, and financial condition are highly uncertain and cannot be predicted.
In December 2019 a novel strain of coronavirus was reported to have surfaced in Wuhan, China. Since then, COVID-19 has spread throughout most countries in the world, including the United States. Public health officials in the United States have both recommended and mandated wearing of masks, precautions to mitigate the spread of COVID-19, including prohibitions on congregating in heavily-populated areas, mandated closure or limitations on the functions of non-essential business, and shelter-in-place orders or similar measures, including throughout Entergy’s service areas. While some of these mitigation measures have been lifted, it is unclear how long certain forms of mitigation measures will remain in place, whether they will be reinstated in the future, and how they will ultimately impact the general economy, Entergy’s customers, and its operations.
Entergy and its Utility operating companies have experienced a decline in commercial and industrial sales and an increase in arrearages and bad debt expense due to non-payment by customers, and expect such reduced levels of sales and increased arrearages and bad debt expense to continue, the extent and duration of which management cannot predict. The Utility operating companies temporarily suspended disconnecting customers for non-payment of bills, and the suspension remains in place at Entergy Arkansas, has been re-instituted at Entergy New Orleans, and could be re-instituted at the other Utility operating companies should their regulators mandate. While they are working with regulators to ensure ultimate recovery for those and other COVID-19 related costs, the amount, method, and timing of such recovery is unknown. Entergy and its Registrant Subsidiaries also could experience, and in some cases have experienced, among other challenges, supply chain, vendor, and contractor disruptions; delays in completion of capital or other construction projects, maintenance, and other operations activities, including prolonged or delayed outages; delays in regulatory proceedings; workforce availability, health or safety issues; increased storm recovery costs; increased cybersecurity risks as a result of many employees telecommuting; increased late or uncollectible customer payments; volatility in the credit or capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available credit facilities); or other adverse impacts on their ability to execute on business strategies and initiatives.
A sustained or further economic decline could adversely impact Entergy’s and the Utility operating companies’ liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, or increased bad debt expense. The Utility operating companies also may experience regulatory outcomes that require them to postpone planned investment and otherwise reduce costs due to the impact of the COVID-19 pandemic on their customers. In addition, if the COVID-19 pandemic continues to create disruptions or turmoil in the credit or financial markets, or adversely impacts Entergy’s credit metrics or ratings, such developments could adversely affect its ability to access capital on favorable terms and continue to meet its
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liquidity needs, or cause a decrease in the value of its defined benefit pension trust funds, as well as its nuclear decommissioning trust funds, all of which are highly uncertain and cannot be predicted.
Entergy cannot predict the extent or duration of the outbreak, the impact of new variants of COVID-19, the timing, availability, distribution or effectiveness of a vaccine, anti-viral or other treatments for COVID-19, governmental responsive measures, or the extent of the effects or ultimate impacts on the global, national or local economy, the capital markets, or its customers, suppliers, operations, financial condition, results of operations, or cash flows.
The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that can be lengthy and subject to appeal, potentially resulting in delays in effecting rate changes, lengthy litigation and uncertainty as to ultimate results.
The Utility operating companies are regulated on a cost-of-service and rate of return basis and are subject to statutes and regulatory commission rules and procedures. The rates that the Utility operating companies and System Energy charge reflect their capital expenditures, operations and maintenance costs, allowed rates of return, financing costs, and related costs of service. These rates significantly influence the financial condition, results of operations, and liquidity of Entergy and each of the Utility operating companies and System Energy. These rates are determined in regulatory proceedings and are subject to periodic regulatory review and adjustment, including adjustment upon the initiative of a regulator or affected stakeholders.
In addition, regulators may initiate proceedings to investigate the prudence of costs in the Utility operating companies’ and System Energy’s base rates and examine, among other things, the reasonableness or prudence of the companies’ operation and maintenance practices, level of expenditures (including storm costs and costs associated with capital projects), allowed rates of return and rate base, proposed resource acquisitions, and previously incurred capital expenditures that the operating companies seek to place in rates. The regulators may disallow costs subject to their jurisdiction found not to have been prudently incurred or found not to have been incurred in compliance with applicable tariffs, creating some risk to the ultimate recovery of those costs. Regulatory proceedings relating to rates and other matters typically involve multiple parties seeking to limit or reduce rates. Traditional base rate proceedings, as opposed to formula rate plans, generally have long timelines, are primarily based on historical costs, and may or may not be limited in scope or duration by statute. The length of these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates, such that the Utility operating companies may not fully recover all costs during the rate effective period and the Utility operating companies may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings.
The Utility operating companies have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including the operation of their assets and infrastructure or the quality of their service. Criticism or adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view the applicable operating company in a favorable light and could potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements.
The base rates of Entergy Texas are established largely in traditional base rate case proceedings.Between base rate proceedings, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs.These riders include a distribution cost recovery factor rider mechanism for the recovery of distribution-related capital investment and certain non-fuel MISO charges, a transmission cost recovery factor rider mechanism for the recovery of transmission-related capital investments, a generation cost recovery rider mechanism for the recovery of generation-related capital investments, and a fixed fuel factor mechanism for the recovery of MISO fuel and energy-related costs.Entergy Texas also is required to make a filing every three years,
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at a minimum, reconciling its fuel and purchased power costs and fuel factor revenues.In the course of this reconciliation, the PUCT determines whether eligible fuel and fuel-related expenses and revenues are necessary and reasonable, and makes a prudence finding for each of the fuel-related contracts for the reconciliation period.Entergy Texas also is required to file full base rate case proceedings every four years and within eighteen months of utilizing its generation cost recovery rider for investments above $200 million.
Between base rate cases, Entergy Arkansas and Entergy Mississippi are able to adjust base rates annually through formula rate plans that utilize a forward test year (Entergy Arkansas) or forward-looking features (Entergy Mississippi).In response to Entergy Arkansas’s application for a general change in rates in 2015, the APSC approved the formula rate plan tariff proposed by Entergy Arkansas including its use of a projected year test period and an initial five-year term.The initial five-year term expires in 2021. Entergy Arkansas has requested APSC approval of the extension of the formula rate plan tariff for an additional five years through 2026.If Entergy Arkansas’s formula rate plan were terminated or not extended beyond the initial term, Entergy Arkansas could file an application for a general change in rates that may include a request for continued regulation under a formula rate review mechanism.If Entergy Mississippi’s formula rate plan is terminated, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan.Entergy Arkansas and Entergy Mississippi recover fuel and purchased energy and certain non-fuel costs through other APSC-approved and MPSC-approved tariffs, respectively.
Entergy Louisiana historically sets electric base rates annually through a formula rate plan using an historic test year.The form of the formula rate plan, on a combined basis, was approved in connection with the business combination of Entergy Louisiana and Entergy Gulf States Louisiana and largely followed the formula rate plans that were approved by the LPSC in connection with the full electric base rate cases filed by those companies in February 2013.The formula rate plan was most recently extended through the test year 2019; certain modifications were made in that extension, including a decrease to the allowed return on equity and the addition of a transmission cost recovery mechanism.The formula rate plan continues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities and purchase power agreements approved by the LPSC and as noted, for certain transmission investment, among other items.MISO fuel and energy-related costs are recoverable in Entergy Louisiana’s fuel adjustment clause.Entergy Louisiana has a pending request to extend its formula rate plan with certain modifications, including implementation of a distribution investment recovery mechanism and use of end of period rate base.In the event that the electric formula rate plan is not renewed or extended, Entergy Louisiana would revert to the more traditional rate case environment.
Entergy New Orleans previously operated under a formula rate plan that ended with the 2011 test year.Based on a settlement agreement approved by the City Council, with limited exceptions, the base rates of Entergy New Orleans were frozen until rates were implemented in connection with the base rate case filed by Entergy New Orleans in 2018.In November 2019 the City Council issued a resolution resolving the rate case, with rates to become effective retroactive to August 2019.The resolution allows Entergy New Orleans to implement a three-year formula rate plan, beginning with the 2019 test year as adjusted for forward-looking known and measurable changes.In November 2020 the City Council issued a resolution approving a settlement of the 2018 rate case.As part of this settlement, Entergy New Orleans agreed to postpone the filing of its first test year formula rate plan to 2021 and, in return, to be provided an additional test year for the three-year cycle.See Note 2 to the financial statements for further discussion.
The rates of System Energy are established by the FERC, and the costs allowed to be charged pursuant to these rates are, in turn, passed through to the participating Utility operating companies through the Unit Power Sales Agreement, which has monthly billings that reflect the current operating costs of, and investment in, Grand Gulf. Retail regulators and other parties may seek to initiate proceedings at FERC to investigate the prudence of costs included in the rates charged under the Unit Power Sales Agreement and examine, among other things, the
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reasonableness or prudence of the operation and maintenance practices, level of expenditures, allowed rates of return and rate base, and previously incurred capital expenditures. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a separate request for FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings nor can it predict whether any outcome could have a material effect on Entergy’s or System Energy’s results of operations, financial condition or liquidity. See Note 2 to the financial statements for further discussion of the proceedings. System Energy has received FERC acceptance for billing protocols to provide retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
The Utility operating companies and System Energy, and the energy industry as a whole, have experienced a period of rising costs and investments, and an upward trend in spending, especially with respect to infrastructure investments, which is likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms. For information regarding rate case proceedings and formula rate plans applicable to the Utility operating companies, see Note 2 to the financial statements.
Changes to state or federal legislation or regulation affecting electric generation, electric and natural gas transmission, distribution, and related activities could adversely affect Entergy and the Utility operating companies’ financial position, results of operations, or cash flows and their utility businesses.
If legislative and regulatory structures evolve in a manner that erodes the Utility operating companies’ exclusive rights to serve their regulated customers, they could lose customers and sales and their results of operations, financial position, or cash flows could be materially affected. Additionally, technological advances in energy efficiency and distributed energy resources are reducing the costs of these technologies and together with ongoing state and federal subsidies, the increasing penetration of these technologies could result in reduced sales by the Utility operating companies. Such loss of sales could put upward pressure on rates, resulting in adverse regulatory actions to mitigate such effects on rates. Entergy and the Utility operating companies cannot predict if or when they may be subject to changes in legislation or regulation, or the extent and timing of reductions of the cost of distributed energy resources, nor can they predict the impact of these changes on their results of operations, financial position, or cash flows.
The Utility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings.
The Utility operating companies recover their fuel, purchased power, and associated costs from their customers through rate mechanisms subject to periodic regulatory review and adjustment. Because regulatory review can result in the disallowance of incurred costs found not to have been prudently incurred, including the cost of replacement power purchased when generators experience outages or when planned outages are extended, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs, particularly when there are substantial or sudden increases in such costs. Regulators also may initiate proceedings to investigate the continued usage or the adequacy and operation of the fuel and purchased power recovery clauses of the Utility operating companies and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.
The Utility operating companies’ cash flows can be negatively affected by the time delays between when gas, power, or other commodities are purchased and the ultimate recovery from customers of the costs in rates. On occasion, when the level of incurred costs for fuel and purchased power rises very dramatically, some of the Utility operating companies may agree to defer recovery of a portion of that period’s fuel and purchased power costs for recovery at a later date, which could increase the near-term working capital and borrowing requirements of those companies. For a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power costs recovery, see Note 2 to the financial statements.
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There remains uncertainty regarding the effect of the termination of the System Agreement on the Utility operating companies.
The Utility operating companies historically engaged in the coordinated planning, construction, and operation of generating resources and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that had been approved by the FERC. The System Agreement terminated in its entirety on August 31, 2016.
There remains uncertainty regarding the long-term effect of the termination of the System Agreement on the Utility operating companies because of the significant effect of the agreement on the generation and transmission functions of the Utility operating companies and the significant period of time (over 30 years) that it had been in existence. In the absence of the System Agreement, there remains uncertainty around the effectiveness of governance processes and the potential absence of federal authority to resolve certain issues among the Utility operating companies and their retail regulators.
In addition, although the System Agreement terminated in its entirety in August 2016, there are a few outstanding System Agreement proceedings at the FERC and at the D.C. Circuit that may require future adjustments, including challenges to the level and timing of payments made by Entergy Arkansas under the System Agreement. The outcome and timing of these FERC proceedings and resulting recovery and impact on rates cannot be predicted at this time.
For further information regarding the regulatory proceedings relating to the System Agreement, see Note 2 to the financial statements.
The Utility operating companies are subject to economic risks associated with participation in the MISO markets and the allocation of transmission upgrade costs. The operation of the Utility operating companies’ transmission system pursuant to the MISO RTO tariff and their participation in the MISO RTO’s wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
On December 19, 2013, the Utility operating companies integrated into the MISO RTO. MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. The Utility operating companies are subject to economic risks associated with participation in the MISO markets. MISO tariff rules and system conditions, including transmission congestion, could affect the Utility operating companies’ ability to sell capacity, energy, and/or ancillary services in certain regions and/or the economic value of such sales, or the cost of serving the Utility operating companies’ respective loads, and MISO market rules may change in ways that cause additional risk.
The Utility operating companies participate in the MISO regional transmission planning process and are subject to risks associated with planning decisions that MISO makes in the exercise of control over the planning of the Utility operating companies’ transmission assets that are under MISO’s functional control. The Utility operating companies pay transmission rates that reflect the cost of transmission projects that the Utility operating companies do not own, which could increase cash or financing needs. In addition to the cash and financing-related risks arising from the potential additional cost allocation to the Utility operating companies from transmission projects of others, there is a risk that the Utility operating companies’ business and financial position could be harmed as a result of lost investment opportunities and other effects that flow from an increased number of competitive projects being approved and constructed that are interconnected with their transmission systems. Further, the terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets, the
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allocation of transmission upgrade costs, the MISO-wide allowed base rate of return on equity, and any required MISO-related charges and credits are subject to regulation by the FERC. The operation of the Utility operating companies’ transmission system pursuant to the MISO tariff and their participation in the MISO wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements. In addition, orders from each of the Utility operating companies’ respective retail regulators generally require that the Utility operating companies make periodic filings, or generally allow the retail regulator to direct the making of such filings, setting forth the results of analysis of the costs and benefits realized from MISO membership as well as the projected costs and benefits of continued membership in MISO and/or requesting approval of their continued membership in MISO. These filings have been submitted periodically by each of the Utility operating companies as required by their respective retail regulators, and the outcome of the resulting proceedings may affect the Utility operating companies’ continued membership in MISO.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather (including from Hurricane Laura, Hurricane Delta, and Hurricane Zeta), or the impact on customer bills of permitted storm cost recovery, could have material effects on Entergy and its Utility operating companies.
Entergy’s and its Utility operating companies’ results of operations, liquidity, and financial condition can be materially affected by the destructive effects of severe weather. Severe weather can also result in significant outages for the customers of the Utility operating companies and, therefore, reduced revenues for the Utility operating companies during the period of the outages. A delay or failure in recovering amounts for storm restoration costs incurred or revenues lost as a result of severe weather could have a material effect on Entergy and those Utility operating companies affected by severe weather. In addition, the recovery of major storm restoration costs from customers could effectively limit our ability to make planned capital or other investments due to the impact of such storm cost recovery on customer bills.
In August and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of the Utility’s service territories in Louisiana, including New Orleans, Texas, and to a lesser extent, in Arkansas and Mississippi. The storms resulted in widespread power outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild. Total restoration costs for the repair and/or replacement of the electrical system damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta are currently estimated to be approximately $2.4 billion. Because Entergy has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Nuclear Operating, Shutdown, and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)
Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities must consistently operate their nuclear power plants at high capacity factors in order to be successful, and lower capacity factors could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Nuclear capacity factors significantly affect the results of operations of certain Utility operating companies, System Energy, and Entergy Wholesale Commodities. Nuclear plant operations involve substantial fixed operating
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costs. Consequently, to be successful, a plant owner must consistently operate its nuclear power plants at high capacity factors, consistent with safety requirements. For the Utility operating companies that own nuclear plants, lower capacity factors can increase production costs by requiring the affected companies to generate additional energy, sometimes at higher costs, from their owned or contractually controlled facilities or purchase additional energy in the spot or forward markets in order to satisfy their supply needs. For the Entergy Wholesale Commodities nuclear plants, lower capacity factors directly affect revenues and cash flow from operations. Entergy Wholesale Commodities’ forward sales are comprised of various hedge products, many of which have some degree of operational-contingent price risk. Certain unit-contingent contracts guarantee specified minimum capacity factors. In the event plants with these contracts were operating below the guaranteed capacity factors, Entergy would be subject to price risk for the undelivered power. Further, Entergy Wholesale Commodities’ nuclear forward sales contracts can also be on a firm LD basis, which subjects Entergy to increasing price risk as capacity factors decrease. Many of these firm hedge products have damages risk.
Certain of the Utility operating companies and System Energy periodically shut down their nuclear power plants to replenish fuel. Plant maintenance and upgrades are often scheduled during such refueling outages. If refueling outages last longer than anticipated or if unplanned outages arise, Entergy’s and their results of operations, financial condition, and liquidity could be materially affected.
Outages at nuclear power plants to replenish fuel require the plant to be “turned off.” Refueling outages generally are planned to occur once every 18 to 24 months. Plant maintenance and upgrades are often scheduled during such planned outages, which typically extends the planned outage duration. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease, and maintenance costs may increase.
Certain of the Utility operating companies and System Energy face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication). These risks could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Based upon currently planned fuel cycles, Entergy’s nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable prices through 2020 and beyond. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. While there are a number of possible alternate suppliers that may be accessed to mitigate any supplier performance failure, the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S. Market prices for nuclear fuel have been extremely volatile from time to time in the past and may be subject to increased volatility due to the imposition of tariffs, domestic purchase requirements or limitations on importation of uranium or uranium products from foreign countries, or shifting trade arrangements between countries. Although Entergy’s nuclear fuel contract portfolio provides a degree of hedging against market risks for several years, costs for nuclear fuel in the future cannot be predicted with certainty due to normal inherent market uncertainties, and price changes could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance and reliability of conversion, enrichment, and fabrication services providers. These service providers are fewer in number than uranium suppliers. For conversion and enrichment services, Entergy diversifies its supply by supplier and country and may take special measures to ensure a reliable supply of enriched uranium for fabrication into nuclear fuel. For fabrication services, each plant is dependent upon the performance of the fabricator of that plant’s nuclear fuel; therefore, Entergy relies upon additional monitoring, inspection, and oversight of the fabrication process to assure reliability and quality of its nuclear fuel. Certain of the suppliers and service providers are located in or dependent upon countries, such as Russia, in which international sanctions or tariffs could further restrict the ability of such
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suppliers to continue to supply fuel or provide such services at acceptable prices or at all. The inability of such suppliers or service providers to perform such obligations could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business face the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants, which could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Under the Atomic Energy Act and Energy Reorganization Act, the NRC regulates the operation of nuclear power plants. The NRC may modify, suspend, or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations, or the terms of the licenses for nuclear facilities. Interested parties may also intervene which could result in prolonged proceedings. A change in the Atomic Energy Act, other applicable statutes, or the applicable regulations or licenses, or the NRC’s interpretation thereof, may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially affect the results of operations, liquidity, or financial condition of Entergy (through Entergy Wholesale Commodities), its Utility operating companies, or System Energy. A change in the classification of a plant owned by one of these companies under the NRC’s Reactor Oversight Process, which is the NRC’s program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response, also could cause the owner of the plant to incur material additional costs as a result of the increased oversight activity and potential response costs associated with the change in classification.For additional information concerning the current classification of the plants owned by Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business, see “Regulation of Entergy’s Business- Regulation of the Nuclear Power Industry - NRC Reactor Oversight Process” in Part I, Item 1.
Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate actions to modify, suspend, or revoke licenses, shut down a nuclear facility, or impose civil penalties. As a result, if an incident were to occur at any nuclear generating unit, whether an Entergy nuclear generating unit or not, it could materially affect the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, System Energy, or Entergy Wholesale Commodities.
Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities are exposed to risks and costs related to operating and maintaining their nuclear power plants, and their failure to maintain operational efficiency at their nuclear power plants could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
The nuclear generating units owned by certain of the Utility operating companies, System Energy,and the Entergy Wholesale Commodities business began commercial operations in the 1970s-1980s. Older equipment may require more capital expenditures to keep each of these nuclear power plants operating safely and efficiently. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages, or any unanticipated capital expenditures, could result in increased costs, some of which costs may not be fully recoverable by the Utility operating companies and System Energy in regulatory proceedings should there be a determination of imprudence. Operations at any of the nuclear generating units owned and operated by Entergy’s subsidiaries could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. A decision may be made to close a unit rather than incur the expense of restarting it or returning the unit to full capacity. For the Utility operating companies and System Energy, this could result in certain costs being stranded and potentially not fully recoverable in regulatory proceedings. For Entergy Wholesale Commodities, this could result in lost revenue and increased fuel and purchased power expense to meet
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supply commitments and penalties for failure to perform under their contracts with customers. In addition, the operation and maintenance of Entergy’s nuclear facilities require the commitment of substantial human resources that can result in increased costs.
The nuclear industry continues to address susceptibility to the effects of stress corrosion cracking and other corrosion mechanisms on certain materials within plant systems. The issue is applicable at all nuclear units to varying degrees and is managed in accordance with industry standard practices and guidelines that include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.
Moreover, Entergy is becoming more dependent on fewer suppliers for key parts of Entergy’s nuclear power plants that may need to be replaced or refurbished, and in some cases, parts are no longer available and have to be reverse-engineered for replacement. In addition, certain major parts have long lead-times to manufacture if an unplanned replacement is needed. This dependence on a reduced number of suppliers and long lead-times on certain major parts for unplanned replacements could result in delays in obtaining qualified replacement parts and, therefore, greater expense for Entergy.
The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities nuclear power plants, as well as the costs of and their ability to fully decommission their nuclear power plants, could be significantly affected by the timing of the opening of a spent nuclear fuel disposal facility, as well as interim storage and transportation requirements.
Certain of the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities nuclear plants incur costs for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the disposal of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, or any interim storage facility, and the timing of such facility opening, will significantly affect the costs associated with on-site storage of spent nuclear fuel. For example, while the DOE is required by law to proceed with the licensing of Yucca Mountain and, after the license is granted by the NRC, to construct the repository and commence the receipt of spent fuel, the NRC licensing of the Yucca Mountain repository is effectively at a standstill. These actions are prolonging the time before spent fuel is removed from Entergy’s plant sites. Because the DOE has not accomplished its objectives, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts, and Entergy has sued the DOE for such breach. Furthermore, Entergy is uncertain as to when the DOE will commence acceptance of spent fuel from its facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at the companies’ nuclear sites and maintenance costs on existing storage facilities, including aging management of fuel storage casks, may increase. The costs of on-site storage are also affected by regulatory requirements for such storage. In addition, the availability of a repository or other off-site storage facility for spent nuclear fuel may affect the ability to fully decommission the nuclear units and the costs relating to decommissioning. For further information regarding spent fuel storage, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs – Spent Fuel Disposal” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 8 to the financial statements.
Certain of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities nuclear plant owners may be required to pay substantial retrospective premiums imposed under the Price-Anderson Act in the event of a nuclear incident, and losses not covered by insurance could have a material effect on Entergy’s and their results of operations, financial condition, or liquidity.
Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere. The Price-Anderson Act limits each reactor owner’s public liability (off-site) for a single nuclear incident to the payment of retrospective premiums into a secondary insurance pool, which is referred to as Secondary Financial Protection, up to approximately $137.6 million per reactor. With 97 reactors currently
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participating, this translates to a total public liability cap of approximately $14 billion per incident. The limit is subject to change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As required by the Price-Anderson Act, the Utility operating companies, System Energy, and Entergy Wholesale Commodities carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers, which is $450 million for each operating site. Claims for any nuclear incident exceeding that amount are covered under Secondary Financial Protection. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the primary insurance coverage, each owner of a nuclear plant reactor, including Entergy’s Utility operating companies, System Energy, and the Entergy Wholesale Commodities plant owners, regardless of fault or proximity to the incident, will be required to pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary insurance level, up to a maximum of approximately $137.6 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.101 billion). The retrospective premium payment is currently limited to approximately $21 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $137.6 million cap.
NEIL is a utility industry mutual insurance company, owned by its members, including the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities plants. All member plants could be subject to an annual assessment (retrospective premium of up to 10 times current annual premium for all policies) should the NEIL surplus (reserve) be significantly depleted due toinsured losses. As of December 31, 2020, the maximum annual assessment amounts total $104 million for the Utility plants. Retrospective premium insurance available through NEIL’s reinsurance treaty can cover the potential assessments and the Entergy Wholesale Commodities plants currently maintain the retrospective premium insurance to cover those potential assessments.
As an owner of nuclear power plants, Entergy participates in industry self-insurance programs and could be liable to fund claims should a plant owned by a different company experience a major event. Any resulting liability from a nuclear accident may exceed the applicable primary insurance coverage and require contribution of additional funds through the industry-wide program that could significantly affect the results of operations, financial condition, or liquidity of Entergy, certain of the Utility operating companies, System Energy, or the Entergy Wholesale Commodities subsidiaries.
The decommissioning trust fund assets for the nuclear power plants owned by the Utility operating companies, System Energy, and the Entergy Wholesale Commodities nuclear plant owners may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts, if one or more of Entergy’s nuclear power plants is retired earlier than the anticipated shutdown date, if the plants cost more to decommission than estimated, or if current regulatory requirements change, which then could require significant additional funding.
Owners of nuclear generating plants have an obligation to decommission those plants. Certain of the Utility operating companies, System Energy, and owners of the Entergy Wholesale Commodities nuclear power plants maintain decommissioning trust funds for this purpose. Certain of the Utility operating companies collect funds from their customers, which are deposited into the trusts covering the units operated for or on behalf of those companies. Those rate collections, as adjusted from time to time by rate regulators, are generally based upon operating license lives and trust fund balances as well as estimated trust fund earnings and decommissioning costs. Assets in these trust funds are subject to market fluctuations, will yield uncertain returns that may fall below projected return rates, and may result in losses resulting from the recognition of impairments of the value of certain securities held in these trust funds.
Under NRC regulations, nuclear plant owners are permitted to project the NRC-required decommissioning amount, based on an NRC formula or a site-specific estimate, and the amount that will be available in each nuclear power plant’s decommissioning trusts combined with any other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent
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decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used. If the projected amount of each individual plant’s decommissioning trusts exceeds the NRC-required decommissioning amount, then its NRC license termination decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs required to decommission these nuclear power plants, or funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources or commitments would be required. Furthermore, depending upon the level of funding available in the trust funds, the NRC may not permit the trust funds to be used to pay for related costs such as the management of spent nuclear fuel that are not included in the NRC’s formula. The NRC may also require a plan for the provision of separate funding for spent fuel management costs. In addition to NRC requirements, there are other decommissioning-related obligations for certain of the Entergy Wholesale Commodities nuclear power plants, which management believes it will be able to satisfy.
Further, federal or state regulatory changes, including mandated increases in decommissioning funding or changes in the methods or standards for decommissioning operations, may also increase the funding requirements of, or accelerate the timing for funding of, the obligations related to the decommissioning of the Utility operating companies, System Energy, or Entergy Wholesale Commodities nuclear power plants or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. Such changes also could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. As a result, under any of these circumstances, Entergy’s results of operations, liquidity, and financial condition could be materially affected.
An early plant shutdown (either generally or relative to current expectations), poor investment results, or higher than anticipated decommissioning costs (including as a result of changing regulatory requirements) could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that the Utility operating companies, System Energy, or the Entergy Wholesale Commodities nuclear plant owners may be required to provide significant additional funds or credit support to satisfy regulatory requirements for decommissioning, which, with respect to the Utility operating companies, may not be recoverable from customers in a timely fashion or at all.
For further information regarding nuclear decommissioning costs, management’s decision to exit the merchant power business, the impairment charges that resulted from such decision, and the planned sales of Palisades and Indian Point Energy Center (which, in each case, will include the transfer of the associated decommissioning trusts), see the “Critical Accounting Estimates- Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy, the “Entergy Wholesale Commodities Exit from the Merchant Power Business” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries, and Notes 9 and 14 to the financial statements.
New or existing safety concerns regarding operating nuclear power plants and nuclear fuel could lead to restrictions upon the operation and decommissioning of Entergy’s nuclear power plants.
New and existing concerns are being expressed in public forums about the safety of nuclear generating units and nuclear fuel. These concerns have led to, and may continue to lead to, various proposals to Federal regulators and governing bodies in some localities where Entergy’s subsidiaries own nuclear generating units for legislative and regulatory changes that might lead to the shutdown of nuclear units, additional requirements or restrictions related to spent nuclear fuel on-site storage and eventual disposal, or other adverse effects on owning, operating, and decommissioning nuclear generating units. Entergy vigorously responds to these concerns and proposals. If any of the existing proposals, or any proposals that may arise in the future with respect to legislative and regulatory changes, become effective, they could have a material effect on Entergy’s results of operations and financial condition.
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(Entergy Corporation)
Entergy Wholesale Commodities nuclear power plants are exposed to price risk.
Entergy and its subsidiaries do not have a regulator-authorized rate of return on their capital investments in non-utility businesses. As a result, the sale of capacity and energy from the Entergy Wholesale Commodities nuclear power plants, unless otherwise contracted, is subject to the fluctuation of market power prices. In order to reduce future price risk to desired levels, Entergy Wholesale Commodities utilizes contracts that are unit-contingent and Firm LD and various products such as forward sales, options, and collars. As of December 31, 2020, Entergy Wholesale Commodities’ nuclear power generation plants had sold forward 98% in 2021 and 99% in 2022 of its generation portfolio’s planned energy output, reflecting the planned shutdown and sale of the remaining Entergy Wholesale Commodities nuclear power plants by mid-2022.
Market conditions such as product cost, market liquidity, and other portfolio considerations influence the product and contractual mix. The obligations under unit-contingent agreements depend on a generating asset that is operating; if the generation asset is not operating, the seller generally is not liable for damages. For some unit-contingent obligations, however, there is also a guarantee of availability that provides for the payment to the power purchaser of contract damages, if incurred, in the event the unit owner fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. Firm LD sales transactions may be exposed to substantial operational price risk, a portion of which may be capped through the use of risk management products, to the extent that the plants do not run as expected and market prices exceed contract prices.
Market prices may fluctuate substantially, sometimes over relatively short periods of time, and at other times experience sustained increases or decreases. Demand for electricity and its fuel stock can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply, prices might be depressed. Also, from time to time there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, credit requirements, bidding rules, and other mechanisms to address volatility and other issues in these markets.
The effects of sustained low natural gas prices and power market structure challenges have resulted in lower market prices for electricity in the power regions where the Entergy Wholesale Commodities nuclear power plants are located. In addition, currently the market design under which the plants operate does not adequately compensate merchant nuclear plants for their environmental and fuel diversity benefits in the region. These conditions were primary factors leading to Entergy’s decision to shut down (or sell) Entergy Wholesale Commodities’ nuclear power plants before the end of their operating licenses.
The price that different counterparties offer for various products including forward sales is influenced both by market conditions as well as the contract terms such as damage provisions, credit support requirements, and the number of available counterparties interested in contracting for the desired forward period. Depending on differences between market factors at the time of contracting versus current conditions, Entergy Wholesale Commodities’ contract portfolio may have average contract prices above or below current market prices, including at the expiration of the contracts, which may significantly affect Entergy Wholesale Commodities’ results of operations, financial condition, or liquidity. New hedges are generally layered into on a rolling forward basis, which tends to drive hedge over-performance to market in a falling price environment, and hedge underperformance to market in a rising price environment; however, hedge timing, product choice, and hedging costs will also affect these results. See the “Market and Credit Risk Sensitive Instruments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries. Since Entergy Wholesale Commodities has announced the closure (or sale) of its nuclear plants, Entergy Wholesale Commodities may enter into fewer forward sales contracts for output from such plants.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The Entergy Wholesale Commodities business is subject to substantial governmental regulation and may be adversely affected by legislative, regulatory, or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
The Entergy Wholesale Commodities business is subject to extensive regulation under federal, state, and local laws. Compliance with the requirements under these various regulatory regimes may cause the Entergy Wholesale Commodities business to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines, and/or civil or criminal liability.
Public utilities under the Federal Power Act are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Each of the owners of the Entergy Wholesale Commodities nuclear power plants that generates electricity, as well as Entergy Nuclear Power Marketing, LLC, is a “public utility” under the Federal Power Act by virtue of making wholesale sales of electric energy and/or owning wholesale electric transmission facilities. The FERC has granted these generating and power marketing companies the authority to sell electricity at market-based rates. The FERC’s orders that grant the Entergy Wholesale Commodities’ generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that the Entergy Wholesale Commodities business can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, the Entergy Wholesale Commodities’ market-based sales are subject to certain market behavior rules, and if any of its generating and power marketing companies were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority and potential penalties of up to $1.29 million per day per violation. If the Entergy Wholesale Commodities’ generating or power marketing companies were to lose their market-based rate authority, such companies would be required to obtain the FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates the Entergy Wholesale Commodities business charges for power from its facilities.
The Entergy Wholesale Commodities business is also affected by legislative and regulatory changes, as well as changes to market design, market rules, tariffs, cost allocations, and bidding rules imposed by the existing Independent System Operators. The Independent System Operators that oversee most of the wholesale power markets may impose, and in the future may continue to impose, mitigation, including price limitations, offer caps and other mechanisms, to address some of the volatility and the potential exercise of market power in these markets. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of the Entergy Wholesale Commodities business’ generation facilities that sell energy and capacity into the wholesale power markets. For further information regarding federal, state, and local laws and regulation applicable to the Entergy Wholesale Commodities business, see the “Regulation of Entergy’s Business” section in Part I, Item 1.
The regulatory environment applicable to the electric power industry is subject to changes as a result of restructuring initiatives at both the state and federal levels. Entergy cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on the Entergy Wholesale Commodities business. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism, have raised claims that the competitive marketplace is not working because energy prices in wholesale markets exceed the marginal cost of operating nuclear power plants, and have made proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process, which could require material changes to business planning models. If competitive restructuring of the electric power markets is reversed, modified, discontinued, or delayed, the Entergy Wholesale Commodities business’ results of operations, financial condition, and liquidity could be materially affected.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The power plants owned by the Entergy Wholesale Commodities business are subject to impairment charges in certain circumstances, which could have a material effect on Entergy’s results of operations, financial condition, or liquidity.
Entergy reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from the operations of such assets. Projected net cash flows depend on the expected operating life of the assets, the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy and capacity over the remaining life of the assets. In particular, the remaining assets of the Entergy Wholesale Commodities business are subject to further impairment in connection with the closure and sale of its nuclear power plants. Moreover, prior to the closure and sale of these plants, the failure of the Entergy Wholesale Commodities business to achieve forecasted operating results and cash flows, an unfavorable change in forecasted operating results or cash flows, a reduction in the expected remaining useful life of a unit, or a decline in observable industry market multiples could all result in potential additional impairment charges for the affected assets.
If Entergy concludes that any of its nuclear power plants is unlikely to operate through its planned shutdown date, which conclusion would be based on a variety of factors, such a conclusion could result in a further impairment of part or all of the carrying value of the plant. Any impairment charge taken by Entergy with respect to its long-lived assets, including the remaining power plants owned by the Entergy Wholesale Commodities business, would likely be material in the quarter that the charge is taken and could otherwise have a material effect on Entergy’s results of operations, financial condition, or liquidity. For further information regarding evaluating long-lived assets for impairment, see the “Critical Accounting Estimates - Impairment of Long-lived Assets” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries and for further discussion of the impairment charges, see Note 14 to the financial statements.
General Business
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Entergy and the Utility operating companies depend on access to the capital markets and, at times, may face potential liquidity constraints, which could make it more difficult to handle future contingencies such as natural disasters or substantial increases in gas and fuel prices. Disruptions in the capital and credit markets may adversely affect Entergy’s and its subsidiaries’ ability to meet liquidity needs, access capital and operate and grow their businesses, and the cost of capital.
Entergy’s business is capital intensive and dependent upon its ability to access capital at reasonable rates and other terms. At times there are also spikes in the price for natural gas and other commodities that increase the liquidity requirements of the Utility operating companies and Entergy Wholesale Commodities. In addition, Entergy’s and the Utility operating companies’ liquidity needs could significantly increase in the event of a hurricane or other weather-related or unforeseen disaster similar to that experienced in Entergy’s service territory with Hurricane Katrina and Hurricane Rita in 2005, Hurricane Gustav and Hurricane Ike in 2008, Hurricane Isaac in 2012, and Hurricane Laura, Hurricane Delta, and Hurricane Zeta in 2020. The occurrence of one or more contingencies, including a delay in regulatory recovery of fuel or purchased power costs or storm restoration costs, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, changes in regulation or governmental policy (including tax and trade policy), or other unknown events, could cause the financing needs of Entergy and its subsidiaries to increase. In addition, accessing the debt capital markets more frequently in these situations may result in an increase in leverage. Material leverage increases could negatively affect the credit ratings of Entergy and the Utility operating companies, which in turn could negatively affect access to the capital markets.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The inability to raise capital on favorable terms, particularly during times of high interest rates, and uncertainty or reduced liquidity in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses. Access to capital markets could be restricted and/or borrowing costs could be increased due to certain sources of debt and equity capital being unwilling to invest in companies that experience extreme weather events, that rely on fossil fuels or offerings to fund fossil fuel projects, or due to risks related to climate change. Events beyond Entergy’s control may create uncertainty that could increase its cost of capital or impair its ability to access the capital markets, including the ability to draw on its bank credit facilities. Entergy and its subsidiaries are unable to predict the degree of success they will have in renewing or replacing their credit facilities as they come up for renewal. Moreover, the size, terms, and covenants of any new credit facilities may not be comparable to, and may be more restrictive than, existing facilities. If Entergy and its subsidiaries are unable to access the credit and capital markets on terms that are reasonable, they may have to delay raising capital, issue shorter-term securities and/or bear an unfavorable cost of capital, which, in turn, could impact their ability to grow their businesses, decrease earnings, significantly reduce financial flexibility and/or limit Entergy Corporation’s ability to sustain its current common stock dividend level.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
A downgrade in Entergy Corporation’s or its subsidiaries’ credit ratings could negatively affect Entergy Corporation’s and its subsidiaries’ ability to access capital and/or could require Entergy Corporation or its subsidiaries to post collateral, accelerate certain payments, or repay certain indebtedness.
There are a number of factors that rating agencies evaluate to arrive at credit ratings for each of Entergy Corporation and the Registrant Subsidiaries, including each Registrant’s regulatory framework, ability to recover costs and earn returns, diversification and financial strength and liquidity. If one or more rating agencies downgrade Entergy Corporation’s, any of the Utility operating companies’, or System Energy’s ratings, particularly below investment grade, borrowing costs would increase, the potential pool of investors and funding sources would likely decrease, and cash or letter of credit collateral demands may be triggered by the terms of a number of commodity contracts, leases, and other agreements.
Most of Entergy Corporation’s and its subsidiaries’ suppliers and counterparties require sufficient creditworthiness to enter into transactions. If Entergy Corporation’s or its subsidiaries’ ratings decline, particularly below investment grade, or if certain counterparties believe Entergy Corporation or the Utility operating companies are losing creditworthiness and demand adequate assurance under fuel, gas, and purchased power contracts, the counterparties may require posting of collateral in cash or letters of credit, prepayment for fuel, gas or purchased power or accelerated payment, or counterparties may decline business with Entergy Corporation or its subsidiaries. At December 31, 2020 based on power prices at that time, Entergy had liquidity exposure of $62 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $6 million of posted cash collateral. In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as of December 31, 2020, Entergy would have been required to provide approximately $30 million of additional cash or letters of credit under some of the agreements. As of December 31, 2020, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $22 million for a $1 per MMBtu increase in gas prices in both the short- and long-term markets.
Recent U.S. tax legislation may materially adversely affect Entergy’s financial condition, results of operations, and cash flows.
The Tax Cuts and Jobs Act of 2017 and CARES Act of 2020 significantly changed the U.S. Internal Revenue Code, including taxation of U.S. corporations, by, among other things, reducing the federal corporate income tax rate, limiting interest deductions, and altering the expensing of capital expenditures. The interpretive
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
guidance issued by the IRS and state tax authorities may be inconsistent with Entergy’s own interpretation and the legislation could be subject to amendments, which could lessen or increase certain impacts of the legislation.
As further described in Note 3 to the financial statements, as a result of amortization of accumulated deferred income taxes and payment of such amounts to customers in 2019, Entergy’s net regulatory liability for income taxes balance is $1.6 billion as of December 31, 2020. Depending on the outcome of IRS examinations or tax positions and elections that Entergy may make, Entergy and the Registrant Subsidiaries may be required to record additional charges or credits to income tax expense. Further, there may be other material effects resulting from the legislation that have not been identified.
See Note 3 to the financial statements for discussion of the effects of the Tax Cuts and Jobs Act on 2018, 2019 and 2020 results of operations and financial condition, the provisions of the Tax Cuts and Jobs Act, and the uncertainties associated with accounting for the Tax Cuts and Jobs Act, and Note 2 to the financial statements for discussion of the regulatory proceedings that have considered the effects of the Tax Cuts and Jobs Act.
Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s, the Utility operating companies’, and System Energy’s results of operations, financial condition, and liquidity.
Entergy and its subsidiaries make judgments regarding the potential tax effects of various transactions and results of operations to estimate their obligations to taxing authorities. These tax obligations include income, franchise, real estate, sales and use, and employment-related taxes. These judgments include provisions for potential adverse outcomes regarding tax positions that have been taken. Entergy and its subsidiaries also estimate their ability to utilize tax benefits, including those in the form of carryforwards for which the benefits have already been reflected in the financial statements. Changes in federal, state, or local tax laws, adverse tax audit results or adverse tax rulings on positions taken by Entergy and its subsidiaries could negatively affect Entergy’s, the Utility operating companies’, and System Energy’s results of operations, financial condition, and liquidity. For further information regarding Entergy’s income taxes, see Note 3 to the financial statements.
Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to complete strategic transactions, is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies, which could materially affect their future prospects, results of operations, and benefits that they anticipate from such transactions.
Entergy and its subsidiaries’ future prospects and results of operations significantly depend on their ability to successfully implement their business strategies, which are subject to business, regulatory, economic, and other risks and uncertainties, many of which are beyond their control. As a result, Entergy and its subsidiaries may be unable to fully achieve the anticipated results of such strategies.
Additionally, Entergy and its subsidiaries have pursued and may continue to pursue strategic transactions including merger, acquisition, divestiture, joint venture, restructuring, or other strategic transactions. For example, Entergy has entered into an agreement to sell its equity interests in the subsidiary that owns the Palisades Nuclear Plant and the decommissioned Big Rock Point Nuclear Power Plant and an agreement to sell the equity interests of Indian Point 1, Indian Point 2, and Indian Point 3, in each case after each of the plants has been shut down and defueled. Also, a significant portion of Entergy’s utility business over the next several years includes the construction and/or purchase of a variety of generating units. These transactions and plans are or may become subject to regulatory approval and other material conditions or contingencies. The failure to complete these transactions or plans or any future strategic transaction successfully or on a timely basis could have an adverse effect on Entergy’s or its subsidiaries’ financial condition or results of operations and the market’s perception of Entergy’s ability to execute its strategy. Further, these transactions, and any completed or future strategic transactions, involve substantial risks, including the following:
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
•acquired businesses or assets may not produce revenues, earnings, or cash flow at anticipated levels;
•acquired businesses or assets could have environmental, permitting, or other problems for which contractual protections prove inadequate;
•Entergy and/or its subsidiaries may assume liabilities that were not disclosed to them, that exceed their estimates, or for which their rights to indemnification from the seller are limited;
•Entergy may experience issues integrating businesses into its internal controls over financial reporting;
•the disposition of a business, including Entergy’s planned exit from the merchant power business, could divert management’s attention from other business concerns;
•Entergy and/or its subsidiaries may be unable to obtain the necessary regulatory or governmental approvals to close a transaction, such approvals may be granted subject to terms that are unacceptable, or Entergy or its subsidiaries otherwise may be unable to achieve anticipated regulatory treatment of any such transaction or acquired business or assets; and
•Entergy or its subsidiaries otherwise may be unable to achieve the full strategic and financial benefits that they anticipate from the transaction, or such benefits may be delayed or may not occur at all.
Entergy and its subsidiaries may not be successful in managing these or any other significant risks that they may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material effect on their business, financial condition or results of operations.
The completion of capital projects, including the construction of power generation facilities, and other capital improvements involve substantial risks. Should such efforts be unsuccessful, the financial condition, results of operations, or liquidity of Entergy and the Utility operating companies could be materially affected.
Entergy’s and the Utility operating companies’ ability to complete capital projects, including the construction of power generation facilities, or make other capital improvements, in a timely manner and within budget is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise, escalating costs for materials, labor, and environmental compliance, and reliance on suppliers for timely and satisfactory performance. Delays in obtaining permits, shortages in materials and qualified labor, levels of public support or opposition, suppliers and contractors not performing as expected or required under their contracts and/or experiencing financial problems that inhibit their ability to fulfill their obligations under contracts, changes in the scope and timing of projects, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in law or regulation, including environmental compliance requirements, and other events beyond the control of the Utility operating companies or the Entergy Wholesale Commodities business may occur that may materially affect the schedule, cost, and performance of these projects. If these projects or other capital improvements are significantly delayed or become subject to cost overruns or cancellation, Entergy and the Utility operating companies could incur additional costs and termination payments, or face increased risk of potential write-off of the investment in the project. In addition, the Utility operating companies could be exposed to higher costs and market volatility, which could affect cash flow and cost recovery, should their respective regulators decline to approve the construction of the project or new generation needed to meet the reliability needs of customers at the lowest reasonable cost.
For further information regarding capital expenditure plans and other uses of capital in connection with capital projects, including the potential construction and/or purchase of additional generation supply sources within the Utility operating companies’ service territory, and as to the Entergy Wholesale Commodities business, see the “Capital Expenditure Plans and Other Uses of Capital” section of Management’s Financial Discussion and Analysis for Entergy and each of the Registrant Subsidiaries.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Failure to attract, retain and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
We rely on a large and changing workforce of team members, including employees, contractors and temporary staffing. Certain events, such as an aging workforce, mismatching of skill sets, failing to appropriately anticipate future workforce needs, or the unavailability of contract resources may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge base, and the time required for skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, and safety costs, may increase. Failure to hire and adequately train replacement employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate the business, especially considering the workforce needs associated with nuclear generation facilities and new skills required to operate a modernized, technology-enabled power grid. If Entergy and its subsidiaries are unable to successfully attract, retain, and manage an appropriately qualified workforce, their results of operations, financial position, and cash flows could be negatively affected.
The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs to fulfill their obligations related to environmental and other matters.
The businesses in which the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business operate are subject to extensive environmental regulation by local, state, and federal authorities. These laws and regulations affect the manner in which the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business conduct their operations and make capital expenditures. These laws and regulations also affect how the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business manage air emissions, discharges to water, wetlands impacts, solid and hazardous waste storage and disposal, cooling and service water intake, the protection of threatened and endangered species, certain migratory birds and eagles, hazardous materials transportation, and similar matters. Federal, state, and local authorities continually revise these laws and regulations, and the laws and regulations are subject to judicial interpretation and to the permitting and enforcement discretion vested in the implementing agencies. Developing and implementing plans for facility compliance with these requirements can lead to capital, personnel, and operation and maintenance expenditures. Violations of these requirements can subject the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. In addition, the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business potentially are subject to liability under these laws for the costs of remediation of environmental contamination of property now or formerly owned or operated by the Utility operating companies, System Energy, and Entergy Wholesale Commodities and of property contaminated by hazardous substances they generate. The Utility operating companies currently are involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future. The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business have incurred and expect to incur significant costs related to environmental compliance.
Emissions of nitrogen and sulfur oxides, mercury, particulates, greenhouse gases, and other regulated air emissions from generating plants potentially are subject to increased regulation, controls, and mitigation expenses. In addition, existing air regulations and programs promulgated by the EPA often are challenged legally, or are revised or withdrawn by the EPA, sometimes resulting in large-scale changes to anticipated regulatory regimes and the resulting need to shift course, both operationally and economically, depending on the nature of the changes. Risks relating to global climate change, initiatives to compel greenhouse gas emission reductions, and water availability issues are discussed below.
Entergy and its subsidiaries may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if Entergy and its subsidiaries fail to obtain, maintain, or comply with any such approval, the operation of its facilities could be
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
stopped or become subject to additional costs. For further information regarding environmental regulation and environmental matters, see the “Regulation of Entergy’s Business– Environmental Regulation” section of Part I, Item 1.
The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs related to reliability standards.
Entergy’s business is subject to extensive and mandatory reliability standards. Such standards, which are established by the NERC, the SERC, and other regional enforcement entities, are approved by the FERC and frequently are reviewed, amended, and supplemented. Failure to comply with such standards could result in the imposition of fines or civil penalties, and potential exposure to third party claims for alleged violations of such standards. The standards, as well as the laws and regulations that govern them, are subject to judicial interpretation and to the enforcement discretion vested in the implementing agencies. In addition to exposure to civil penalties and fines, the Utility operating companies have incurred and expect to incur significant costs related to compliance with new and existing reliability standards, including costs associated with the Utility operating companies’ transmission system and generation assets. In addition, the retail regulators of the Utility operating companies possess the jurisdiction, and in some cases have exercised such jurisdiction, to impose standards governing the reliable operation of the Utility operating companies’ distribution systems, including penalties if these standards are not met. The changes to the reliability standards applicable to the electric power industry are ongoing, and Entergy cannot predict the ultimate effect that the reliability standards will have on its Utility and Entergy Wholesale Commodities businesses.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas usage and otherwise materially affect the Utility operating companies’ results of operations and system reliability.
Temperatures above normal levels in the summer tend to increase electric cooling demand and revenues, and temperatures below normal levels in the winter tend to increase electric and gas heating demand and revenues. As a corollary, mild temperatures in either season tend to decrease energy usage and resulting revenues. Higher consumption levels coupled with seasonal pricing differentials typically cause the Utility operating companies to report higher revenues in the third quarter of the fiscal year than in the other quarters. Extreme weather conditions including hurricanes or tropical storms, flooding events, or ice storms may stress the Utility operating companies’ generation facilities and transmission and distribution systems, resulting in increased maintenance and capital costs (and potential increased financing needs), limits on their ability to meet peak customer demand, increased regulatory oversight, and reduced customer satisfaction. These extreme conditions could have a material effect on the Utility operating companies’ financial condition, results of operations, and liquidity.
Entergy’s electricity sales volumes are affected by a number of factors including weather and economic conditions, trends in energy efficiency, new technologies, and self-generation alternatives, including the willingness and ability of large industrial customers to develop co-generation facilities that greatly reduce their grid demand. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and rarely have a long-lasting effect on Entergy’s operating results. Others, such as the organic turnover of appliances and their replacement with more efficient ones, adoption of newer technologies including smart thermostats, new building codes, distributed energy resources, energy storage, demand side management, and rooftop solar are having a more permanent effect by reducing sales growth rates from historical norms. As a result of these emerging efficiencies and technologies, the Utility operating companies may lose customers or experience lower average use per customer in the residential and commercial classes, and continuing advances have the potential to further limit sales growth in the future. The Utility operating companies also may face competition from other companies offering products and services to Entergy’s customers. Electricity sales to industrial
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
customers, in particular, benefit from steady economic growth and favorable commodity markets; however, industrial sales are sensitive to changes in conditions in the markets in which its customers operate. Negative changes in any of these or other factors, particularly sustained economic downturns or sluggishness, have the potential to result in slower sales growth or sales declines and increased bad debt expense, which could materially affect Entergy’s and the Utility operating companies’ results of operations, financial condition, and liquidity.
The effects of climate change, environmental and regulatory obligations intended to compel greenhouse gas emission reductions or increase clean or renewable energy requirements or to place a price on greenhouse gas emissions, or achieving voluntary climate commitments could materially affect the financial condition, results of operations, and liquidity of Entergy, the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business.
In an effort to address climate change concerns, some federal, state, and local authorities are calling for additional laws and regulations aimed at known or suspected causes of climate change. For example, in response to the United States Supreme Court’s 2007 decision holding that the EPA has authority to regulate emissions of CO2 and other “greenhouse gases” under the Clean Air Act, the EPA, various environmental interest groups, and other organizations focused considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. Since that ruling, the EPA has promulgated regulations controlling greenhouse gas emissions from certain vehicles, and from new, existing, and significantly modified stationary sources of emissions, including electric generating units. As examples of state action, in the Northeast, the Regional Greenhouse Gas Initiative establishes a cap on CO2 emissions from electric power plants and requires generators to purchase emission permits to cover their CO2 emissions, and a similar program has been developed in California. In Louisiana, the Office of the Governor announced the creation of a Climate Initiatives Task Force and issued an executive order that established a path to net-zero emissions by 2050 while the City Council of New Orleans passed a renewable and clean portfolio standard that sets a goal of net-zero emissions by 2040 and absolute zero emissions by 2050. The impact that continued changes in the governmental response to climate change risk will have on existing and pending environmental laws and regulations related to greenhouse gas emissions is currently unclear.
Developing and implementing plans for compliance with greenhouse gas emissions reduction, clean/renewable energy requirements, or for achieving voluntary climate commitments can lead to additional capital, personnel, and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects. The operations of low or non-emitting generating units (such as nuclear units) at lower than expected capacity factors could require increased generation from higher emitting units, thus increasing the company’s greenhouse gas emission rate. Moreover, long-term planning to meet environmental requirements can be negatively impacted and costs may increase to the extent laws and regulations change prior to full implementation. These requirements could, in turn, lead to changes in the planning or operations of balancing authorities or organized markets in areas where the Utility operating companies, System Energy, or Entergy Wholesale Commodities do business. Violations of such requirements may subject Entergy Wholesale Commodities and the Utility operating companies to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. To the extent Entergy believes any of these costs are recoverable in rates, however, additional material rate increases for customers could be resisted by Entergy’s regulators and, in extreme cases, Entergy’s regulators might attempt to deny or defer timely recovery of these costs. Future changes in regulation or policies governing the emission of CO2 and other greenhouse gases or mix of generation sources could (i) result in significant additional costs to Entergy’s utility operating companies, their suppliers or customers, (ii) make some of Entergy’s electric generating units uneconomical to maintain or operate, (iii) result in the early retirement of generation facilities and stranded costs if Entergy’s utility operating companies are unable to fully recover the costs and investment in generation and (iv) could increase the difficulty that Entergy and its utility operating companies have with obtaining or maintaining required environmental regulatory approvals, each of which could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries. In addition, lawsuits have occurred or are reasonably expected against emitters of greenhouse gases alleging that these
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
companies are liable for personal injuries and property damage caused by climate change. These lawsuits may seek injunctive relief, monetary compensation, and punitive damages.
In addition to the regulatory and financial risks associated with climate change discussed above, potential physical risks from climate change include an increase in sea level, wind and storm surge damages, wildfires, wetland and barrier island erosion, risks of flooding and changes in weather conditions, (such as increases in precipitation, drought, or changes in average temperatures), and potential increased impacts of extreme weather conditions or storms. Entergy subsidiaries own assets in, and serve, communities that are at risk from sea level rise, changes in weather conditions, storms, and loss of the protection offered by coastal wetlands. A significant portion of the nation’s oil and gas infrastructure is located in these areas and susceptible to storm damage that could be aggravated by the physical impacts of climate change, which could give rise to fuel supply interruptions and price spikes. Entergy and its subsidiaries also face the risk that climate change could impact the availability and quality of water supply necessary for operations.
These and other physical changes could result in changes in customer demand, increased costs associated with repairing and maintaining generation facilities and transmission and distribution systems resulting in increased maintenance and capital costs (and potential increased financing needs), limits on the Entergy System’s ability to meet peak customer demand, more frequent and longer lasting outages, increased regulatory oversight, and lower customer satisfaction. Also, to the extent that climate change adversely impacts the economic health of a region or results in energy conservation or demand side management programs, it may adversely impact customer demand and revenues. Such physical or operational risks could have a material effect on Entergy’s, Entergy Wholesale Commodities’, System Energy’s, and the Utility operating companies’ financial condition, results of operations, and liquidity.
In September 2020, Entergy voluntarily committed to achieving net zero carbon emissions by 2050. Technology research and development, innovation, and advancement are critical to Entergy’s ability to achieve this commitment. Moreover, Entergy cannot predict the ultimate impact of achieving this objective, or the various implementation aspects, on its system reliability, or its results of operations, financial condition or liquidity.
Continued and future availability and quality of water for cooling, process, and sanitary uses could materially affect the financial condition, results of operations, and liquidity of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business.
Water is a vital natural resource that is also critical to the Utility operating companies’, System Energy’s, and Entergy Wholesale Commodities’ business operations. Entergy’s facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Entergy’s Utility operating companies also own and/or operate hydroelectric facilities. Accordingly, water availability and quality are critical to Entergy’s business operations. Impacts to water availability or quality could negatively impact both operations and revenues.
Entergy secures water through various mechanisms (ground water wells, surface waters intakes, municipal supply, etc.) and operates under the provisions and conditions set forth by the provider and/or regulatory authorities. Entergy also obtains and operates in substantial compliance with water discharge permits issued under various provisions of the Clean Water Act and/or state water pollution control provisions. Regulations and authorizations for both water intake and use and for waste discharge can become more stringent in times of water shortages, low flows in rivers, low lake levels, low groundwater aquifer volumes, and similar conditions. The increased use of water by industry, agriculture, and the population at large, population growth, and the potential impacts of climate change on water resources may cause water use restrictions that affect Entergy and its subsidiaries.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices, which could materially affect Entergy’s and its subsidiaries’ results of operations, financial condition, and liquidity.
To manage near-term financial exposure related to commodity price fluctuations, Entergy and its subsidiaries, including the Utility operating companies and the Entergy Wholesale Commodities business, may enter into contracts to hedge portions of their purchase and sale commitments, fuel requirements, and inventories of natural gas, uranium and its conversion and enrichment, coal, refined products, and other commodities, within established risk management guidelines. As part of this strategy, Entergy and its subsidiaries may utilize fixed- and variable-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. However, Entergy and its subsidiaries normally cover only a portion of the exposure of their assets and positions to market price volatility, and the coverage will vary over time. In addition, Entergy also elects to leave certain volumes during certain years unhedged. To the extent Entergy and its subsidiaries have unhedged positions, fluctuating commodity prices can materially affect Entergy’s and its subsidiaries’ results of operations and financial position.
Although Entergy and its subsidiaries devote a considerable effort to these risk management strategies, they cannot eliminate all the risks associated with these activities. As a result of these and other factors, Entergy and its subsidiaries cannot predict with precision the impact that risk management decisions may have on their business, results of operations, or financial position.
Entergy’s over-the-counter financial derivatives are subject to rules implementing the Dodd-Frank Wall Street Reform and Consumer Protection Act that are designed to promote transparency, mitigate systemic risk, and protect against market abuse. Entergy cannot predict the impact any proposed or not fully-implemented final rules will have on its ability to hedge its commodity price risk or on over-the-counter derivatives markets as a whole, but such rules and regulations could have a material effect on Entergy's risk exposure, as well as reduce market liquidity and further increase the cost of hedging activities.
Entergy has guaranteed or indemnified the performance of a portion of the obligations relating to hedging and risk management activities. Reductions in Entergy’s or its subsidiaries’ credit quality or changes in the market prices of energy commodities could increase the cash or letter of credit collateral required to be posted in connection with hedging and risk management activities, which could materially affect Entergy’s or its subsidiaries’ liquidity and financial position.
The Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties may not meet their obligations, which may materially affect the Utility operating companies and Entergy Wholesale Commodities.
The hedging and risk management practices of the Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties that owe Entergy and its subsidiaries money, energy, or other commodities will not perform their obligations. Currently, some hedging agreements contain provisions that require the counterparties to provide credit support to secure all or part of their obligations to Entergy or its subsidiaries. If the counterparties to these arrangements fail to perform, Entergy or its subsidiaries may enforce and recover the proceeds from the credit support provided and acquire alternative hedging arrangements, which credit support may not always be adequate to cover the related obligations. In such event, Entergy and its subsidiaries might incur losses in addition to amounts, if any, already paid to the counterparties. In addition, the credit commitments of Entergy’s lenders under its bank facilities may not be honored for a variety of reasons, including unexpected periods of financial distress affecting such lenders, which could materially affect the adequacy of its liquidity sources.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.
The performance of the capital markets affects the values of the assets held in trust under Entergy’s pension and postretirement benefit plans. A decline in the market value of the assets may increase the funding requirements relating to Entergy’s benefit plan liabilities and also result in higher benefit costs. As the value of the assets decreases, the “expected return on assets” component of benefit costs decreases, resulting in higher benefits costs. Additionally, asset losses are incorporated into benefit costs over time, thus increasing benefits costs. Volatility in the capital markets has affected the market value of these assets, which may affect Entergy’s planned levels of contributions in the future. Additionally, changes in interest rates affect the liabilities under Entergy’s pension and postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding and recognition of higher liability carrying costs. The funding requirements of the obligations related to the pension benefit plans can also increase as a result of changes in, among other factors, retirement rates, life expectancy assumptions, or Federal regulations. For further information regarding Entergy’s pension and other postretirement benefit plans, refer to the “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” section of Management’s Financial Discussion and Analysis for Entergy and each of its Registrant Subsidiaries and Note 11 to the financial statements.
The litigation environment in the states in which certain Entergy subsidiaries operate poses a significant risk to those businesses.
Entergy and its subsidiaries are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, asbestos, hazardous material and ratepayer matters, and injuries and damages issues, among other matters. The states in which the Utility operating companies operate have proven to be unusually litigious environments. Judges and juries in these states have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. Entergy and its subsidiaries use legal and appropriate means to contest litigation threatened or filed against them, but the litigation environment in these states poses a significant business risk.
Terrorist attacks, cyber attacks, system failures or data breaches of Entergy’s and its subsidiaries’ or our suppliers’ technology systems may adversely affect Entergy’s results of operations.
Entergy and its subsidiaries operate in a business that requires evolving information technology systems that include sophisticated data collection, processing systems, software, network infrastructure, and other technologies that are becoming more complex and may be subject to mandatory and prescriptive reliability and security standards. The functionality of Entergy’s technology systems depends on its own and its suppliers’ and their contractors’ technology. Suppliers’ and their contractors’ technology systems to which Entergy is connected directly or indirectly support a variety of business processes and activities to store sensitive data, including (i) intellectual property, (ii) proprietary business information, (iii) personally identifiable information of customers and employees, and (iv) data with respect to invoicing and the collection of payments, accounting, procurement, and supply chain activities. Any significant failure or malfunction of such information technology systems could result in loss of data or disruptions of operations.
There have been attacks and threats of attacks on energy infrastructure by cyber actors, including those associated with foreign governments. As an operator of critical infrastructure, Entergy and its subsidiaries face heightened risk of an act or threat of terrorism, cyber attacks, and data breaches, whether as a direct or indirect act against one of Entergy’s generation, transmission or distribution facilities, operations centers, infrastructure, or information technology systems used to manage, monitor, and transport power to customers and perform day-to-day business functions. An actual act could affect Entergy’s ability to operate, including its ability to operate the information technology systems and network infrastructure on which it relies to conduct business.
Given the rapid technological advancements of existing and emerging threats, Entergy’s technology systems remain inherently vulnerable despite implementations and enhancements of the multiple layers of security
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
and controls. If Entergy’s or its subsidiaries’ technology systems were compromised and unable to detect or recover in a timely fashion to a normal state of operations, Entergy or its subsidiaries could be unable to perform critical business functions that are essential to the company’s well-being and could result in a loss of its confidential, sensitive, and proprietary information, including personal information of its customers, employees, suppliers, and others in Entergy’s care.
Any such attacks, failures or data breaches could have a material effect on Entergy’s and the Utility operating companies’ business, financial condition, results of operations or reputation. Although we purchase insurance coverage for cyber-attacks or data breaches, such insurance may not be adequate to cover all losses that might arise in connection with these events. Such events may also expose Entergy to an increased risk of litigation (and associated damages and fines).
(Entergy New Orleans)
The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidity.
Gas rates charged to retail gas customers are comprised primarily of purchased gas cost charges, which provide no return or profit to Entergy New Orleans, and distribution charges, which provide a return or profit to the utility. Distribution charges recover fixed costs on a volumetric basis and, thus, are affected by the amount of gas sold to customers. When purchased gas cost charges increase due to higher gas procurement costs, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy New Orleans, which could adversely affect results of operations. Purchased gas cost charges, which comprise most of a customer’s bill and may be adjusted monthly, represent gas commodity costs that Entergy New Orleans recovers from its customers. Entergy New Orleans’s cash flows can be affected by differences between the time period when gas is purchased and the time when ultimate recovery from customers occurs.
(System Energy)
System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings.
System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. Charges under the Unit Power Sales Agreement are paid by the Utility operating companies as consideration for their respective entitlements to receive capacity and energy. The useful economic life of Grand Gulf is finite and is limited by the terms of its operating license, which expires in November 2044. System Energy’s financial condition depends both on the receipt of payments from the Utility operating companies under the Unit Power Sales Agreement and on the continued commercial operation of Grand Gulf. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a request in a separate proceeding for FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement. The LPSC has also authorized the filing of a prudence complaint at the FERC relating to Grand Gulf operations. Entergy cannot predict the outcome of any of these proceedings nor can it predict whether any outcome could have a material effect on Entergy’s or System Energy’s results of operations, financial condition or liquidity. See Note 2 to the financial statements for further discussion of the proceedings. The Utility operating companies have agreed to implement certain protocols for providing retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
For information regarding the Unit Power Sales Agreement, the sale and leaseback transactions and certain other agreements relating to the Entergy System companies’ support of System Energy, see Notes 5 and 8 to the
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
financial statements and the “Utility - System Energy and Related Agreements” section of Part I, Item 1.
(Entergy Corporation)
As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock.
Entergy Corporation is a holding company with no material revenue generating operations of its own or material assets other than the stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Entergy Corporation’s ability to satisfy its financial obligations, including the payment of interest and principal on its outstanding debt, and to pay dividends on its common stock depends on the payment to it of dividends or distributions by its subsidiaries. The subsidiaries of Entergy Corporation are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make distributions to Entergy Corporation. The ability of such subsidiaries to make payments of dividends or distributions to Entergy Corporation depends on their results of operations and cash flows and other items affecting retained earnings, and on any applicable legal, regulatory, or contractual limitations on subsidiaries’ ability to pay such dividends or distributions. Prior to providing funds to Entergy Corporation, such subsidiaries have financial and regulatory obligations that must be satisfied, including among others, debt service and, in the case of Entergy Utility Holding Company and Entergy Texas, dividends and distributions on preferred securities. Any distributions from the Registrant Subsidiaries other than Entergy Texas and System Energy are paid directly to Entergy Utility Holding Company and are therefore subject to prior payment of distributions on its preferred securities.
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
The COVID-19 Pandemic
See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the COVID-19 pandemic.
February 2021 Winter Storms
See the “February 2021 Winter Storms” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the February 2021 winter storms. Entergy Arkansas’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $10 million. Natural gas purchases for Entergy Arkansas for February 1st through 25th, 2021 are approximately $105 million compared to natural gas purchases for February 2020 of $10 million.
Results of Operations
2020 Compared to 2019
Net Income
Net income decreased $17.7 million primarily due to lower volume/weather, a formula rate plan provision recorded in 2020 to reflect the 2019 historical year netting adjustment, and higher depreciation and amortization expenses, partially offset by higher retail electric price and lower other operation and maintenance expenses. See Note 2 to the financial statements for discussion of the 2019 historical year netting adjustment.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2020 to 2019:
| | | | | |
| Amount |
| (In Millions) |
2019 operating revenues | $2,259.6 | |
Fuel, rider, and other revenues that do not significantly affect net income | (278.5) | |
Volume/weather | (72.2) | |
Retail electric price | 57.4 | |
Return of unprotected excess accumulated deferred income taxes to customers | 118.2 | |
2020 operating revenues | $2,084.5 | |
Entergy Arkansas’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The volume/weather variance is primarily due to a decrease of 1,069 GWh, or 5%, in billed electricity usage, including decreased commercial and industrial usage as a result of the COVID-19 pandemic, and the effect of less favorable weather on residential and commercial sales, partially offset by an increase in residential usage as a
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
result of the COVID-19 pandemic. See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the COVID-19 pandemic.
The retail electric price variance is primarily due to the $56.5 million annual formula rate plan increase related to the 2020 projected test year included in the 2019 formula rate plan filing effective with the first billing cycle of January 2020. See Note 2 to the financial statements for further discussion of the formula rate plan filing.
The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through a tax adjustment rider beginning in April 2018. In 2020, $8.1 million was returned to customers as compared to $126.3 million in 2019. There is no effect on net income as the reduction in operating revenues in each period was offset by a reduction in income tax expense. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
Other Income Statement Variances
Nuclear refueling outage expenses decreased primarily due to the amortization of lower costs associated with the most recent outages as compared to previous outages.
Other operation and maintenance expenses decreased primarily due to:
•a decrease of $18.3 million in nuclear generation expenses primarily due to lower nuclear labor costs, including contract labor, in part as a result of the COVID-19 pandemic;
•a decrease of $13.2 million in non-nuclear generation expenses primarily due to lower long-term service agreement expenses;
•an $11.2 million write-off in 2019 of specific costs related to the potential construction of scrubbers at the White Bluff plant. See Note 2 to the financial statements for discussion of the write-off;
•higher nuclear insurance refunds of $7.8 million;
•a decrease of $5.9 million primarily due to contract costs in 2019 related to initiatives to explore new customer products and services; and
•a decrease of $5.8 million in energy efficiency costs.
The decrease was partially offset by the effects of recording in 2019 a final judgment to resolve claims in the ANO damages case against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $11.9 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expense. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Other income increased primarily due to changes in decommissioning trust fund investment activity.
Other regulatory credits - net for 2020 includes a provision of $43.5 million to reflect the 2019 historical year netting adjustment included in the APSC’s December 2020 order in the 2020 formula rate plan proceeding. See Note 2 to the financial statements for discussion of the 2020 formula rate plan proceeding.
The effective income tax rates were 16.3% for 2020 and (21.6%) for 2019. The difference in the effective income tax rate versus the federal statutory rate of 21% for 2019 was primarily due to the amortization of excess accumulated deferred income taxes. See Notes 2 and 3 to the financial statements for a discussion of the effects and regulatory activity regarding the Tax Cuts and Jobs Act. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2019 Compared to 2018
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 21, 2020, for discussion of results of operations for 2019 compared to 2018.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2020, 2019, and 2018 were as follows:
| | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 | |
| (In Thousands) |
Cash and cash equivalents at beginning of period | $3,519 | | | $119 | | | $6,216 | | |
| | | | | | |
Net cash provided by (used in): | | | | | | |
Operating activities | 659,818 | | | 677,766 | | | 211,825 | | |
Investing activities | (795,709) | | | (676,293) | | | (688,727) | | |
Financing activities | 324,500 | | | 1,927 | | | 470,805 | | |
Net increase (decrease) in cash and cash equivalents | 188,609 | | | 3,400 | | | (6,097) | | |
| | | | | | |
Cash and cash equivalents at end of period | $192,128 | | | $3,519 | | | $119 | | |
2020 Compared to 2019
Operating Activities
Net cash flow provided by operating activities decreased $17.9 million in 2020 primarily due to:
•the timing of recovery of fuel and purchased power costs;
•lower collections of receivables from customers, in part due to the COVID-19 pandemic; and
•the timing of payments to vendors.
The decrease was partially offset by:
•a decrease in the return of unprotected excess accumulated deferred income taxes to customers in 2020 as compared to 2019. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act;
•$25 million in proceeds received from the DOE in 2020 resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
•a decrease of $15.8 million in pension contributions in 2020. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Investing Activities
Net cash flow used in investing activities increased $119.4 million in 2020 primarily due to:
•an increase of $79.5 million in storm spending;
•an increase of $47.3 million in non-nuclear generation construction expenditures primarily due to increased spending on various projects in 2020;
•an increase of $39.4 million in nuclear construction expenditures primarily as a result of work performed in 2020 on various ANO 2 outage projects;
•an increase of $38.5 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and service deliveries, and the timing of cash payments during the nuclear fuel cycle; and
•an increase of $30.3 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of Entergy Arkansas’s distribution system, including increased spending on advanced metering infrastructure.
The increase was partially offset by:
•a decrease of $56 million in transmission construction expenditures primarily due to a lower scope of work performed in 2020 as compared to 2019; and
•$55 million in proceeds received from the DOE in 2020 resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.
Financing Activities
Net cash flow provided by financing activities increased $322.6 million in 2020 primarily due to:
•issuances of $100 million of 4.0% Series mortgage bonds in March 2020 and $675 million of 2.65% Series mortgage bonds in September 2020;
•money pool activity;
•a decrease of $41.6 million in net long-term repayments in 2020 on the Entergy Arkansas nuclear fuel company variable interest entity credit facility; and
•a decrease of $20 million in common equity distributions in 2020 in order to maintain Entergy Arkansas’s capital structure.
The increase was partially offset by:
•the issuance of $350 million of 4.20% Series mortgage bonds in March 2019;
•the repayment in October 2020 of $200 million of 4.90% Series mortgage bonds due December 2052; and
•the repayment in October 2020 of $125 million of 4.75% Series mortgage bonds due June 2063.
Decreases in Entergy Arkansas’s payable to the money pool are a use of cash flow, and Entergy Arkansas’s payable to the money pool decreased by $21.6 million in 2020 compared to decreasing by $161.1 million in 2019. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
See Note 5 to the financial statements for further details of long-term debt.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2019 Compared to 2018
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 21, 2020, for discussion of operating, investing, and financing cash flow activities for 2019 compared to 2018.
Capital Structure
Entergy Arkansas’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio is primarily due to the net issuances of long-term debt in 2020.
| | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
Debt to capital | 54.8 | % | | 53.0 | % |
Effect of excluding the securitization bonds | — | % | | — | % |
Debt to capital, excluding securitization bonds (a) | 54.8 | % | | 53.0 | % |
Effect of subtracting cash | (1.2 | %) | | — | % |
Net debt to net capital, excluding securitization bonds (a) | 53.6 | % | | 53.0 | % |
(a)Calculation excludes the securitization bonds, which are non-recourse to Entergy Arkansas.
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because the securitization bonds, which have been repaid as of December 31, 2020, were non-recourse to Entergy Arkansas, as more fully described in Note 5 to the financial statements. Entergy Arkansas also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because net debt indicates Entergy Arkansas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Arkansas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing distributions, Entergy Arkansas may receive equity contributions to maintain its capital structure.
Uses of Capital
Entergy Arkansas requires capital resources for:
•construction and other capital investments;
•debt maturities or retirements;
•working capital purposes, including the financing of fuel and purchased power costs; and
•distribution and interest payments.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| 2021 | | 2022 | | 2023 |
| (In Millions) |
Planned construction and capital investment: | | | | | |
Generation | $340 | | | $355 | | | $430 | |
Transmission | 40 | | | 45 | | | 190 | |
Distribution | 95 | | | 255 | | | 420 | |
Utility Support | 105 | | | 80 | | | 75 | |
Total | $580 | | | $735 | | | $1,115 | |
Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2022-2023 | | 2024-2025 | | After 2025 | | Total |
| (In Millions) |
Long-term debt (a) | $611 | | | $543 | | | $581 | | | $4,713 | | | $6,448 | |
Operating leases (b) | $14 | | | $21 | | | $15 | | | $11 | | | $61 | |
Finance leases (b) | $3 | | | $5 | | | $3 | | | $2 | | | $13 | |
Purchase obligations (c) | $452 | | | $618 | | | $509 | | | $3,882 | | | $5,461 | |
(a)Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.
(b)Lease obligations are discussed in Note 10 to the financial statements.
(c)Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Arkansas, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which are discussed in Note 8 to the financial statements.
In addition to the contractual obligations given above, Entergy Arkansas currently expects to contribute approximately $66.6 million to its qualified pension plans and approximately $517 thousand to its other postretirement health care and life insurance plans in 2021, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations, Entergy Arkansas has $252 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Arkansas includes specific investments in renewables such as the Searcy Solar Facility, Walnut Bend Solar Facility, and West Memphis Solar Facility; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including advanced meters and related investments; resource planning, including potential generation and renewables projects; system improvements; investments in ANO 1 and 2; software and security; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt maturities in Note 5 to the financial statements.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Arkansas pays distributions from its earnings at a percentage determined monthly.
Renewables
Searcy Solar Facility
In March 2019, Entergy Arkansas announced that it signed an agreement for the purchase of an approximately 100 MW solar energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. The purchase is contingent upon, among other things, obtaining necessary approvals from applicable federal and state regulatory and permitting agencies. The project is being constructed by a subsidiary of NextEra Energy Resources. Entergy Arkansas will purchase the facility upon mechanical completion and after the other purchase contingencies have been met. Closing is expected to occur by the end of 2021. In May 2019, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. In September 2019 other parties filed testimony largely supporting the resource acquisition but disputing Entergy Arkansas’s proposed method of cost recovery. Entergy Arkansas filed its rebuttal testimony in October 2019. In February 2020, Entergy Arkansas, the Attorney General, and the APSC general staff filed a partial settlement agreement asking the APSC to approve, based on the record in the proceeding, all issues except certain issues that are submitted to the APSC for determination. In April 2020 the APSC issued an order approving Entergy Arkansas’s acquisition of the Searcy Solar facility as being in the public interest, but declined to approve Entergy Arkansas’s preferred cost recovery rider mechanism, finding instead, based on the particular facts and circumstances presented, that the formula rate plan rider was a sufficient recovery mechanism for this resource.
Walnut Bend Solar Facility
In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 100 MW Walnut Bend Solar Facility is in the public interest. Entergy Arkansas requested a decision by the APSC by June 15, 2021 and primarily requests cost recovery through the formula rate plan rider. A procedural schedule was established with a hearing scheduled in April 2021. Closing is expected to occur in 2022.
West Memphis Solar Facility
In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 180 MW West Memphis Solar Facility is in the public interest. Entergy Arkansas requested a decision by the APSC by September 7, 2021 and primarily requests cost recovery through the formula rate plan rider. Closing is expected to occur in 2023.
Sources of Capital
Entergy Arkansas’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Entergy Arkansas may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest rates are favorable.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
All debt and common and preferred membership interest issuances by Entergy Arkansas require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in Entergy Arkansas’s bond indentures and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Arkansas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| | | | | | | | | | | | | | | | | | | | |
2020 | | 2019 | | 2018 | | 2017 |
(In Thousands) |
$3,110 | | ($21,634) | | ($182,738) | | ($166,137) |
See Note 4 to the financial statements for a description of the money pool.
Entergy Arkansas has a credit facility in the amount of $150 million scheduled to expire in September 2024. Entergy Arkansas also has a $25 million credit facility scheduled to expire in April 2021. The $150 million credit facility includes fronting commitments for the issuance of letters of credit against $5 million of the borrowing capacity of the facility. As of December 31, 2020, there were no cash borrowings and no letters of credit outstanding under the credit facilities. In addition, Entergy Arkansas is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2020, a $1 million letter of credit was outstanding under Entergy Arkansas’s uncommitted letter of credit facility. See Note 4 to the financial statements for further discussion of the credit facilities.
The Entergy Arkansas nuclear fuel company variable interest entity has a credit facility in the amount of $80 million scheduled to expire in September 2022. As of December 31, 2020, $12.2 million in loans were outstanding under the credit facility for the Entergy Arkansas nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of the nuclear fuel company variable interest entity credit facility.
Entergy Arkansas obtained authorization from the FERC through July 2022 for short-term borrowings not to exceed an aggregate amount of $250 million at any time outstanding and borrowings by its nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of Entergy Arkansas’s short-term borrowing limits. The long-term securities issuances of Entergy Arkansas are limited to amounts authorized by the FERC. The APSC has concurrent jurisdiction over Entergy Arkansas’s first mortgage bond/secured issuances. Entergy Arkansas has obtained long-term financing authorization from the FERC that extends through July 2022. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2022.
State and Local Rate Regulation and Fuel-Cost Recovery
Retail Rates
2018 Formula Rate Plan Filing
In July 2018, Entergy Arkansas filed with the APSC its 2018 formula rate plan filing to set its formula rate for the 2019 calendar year. The filing showed Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2019 test period to be below the formula rate plan bandwidth. Additionally, the filing included the first netting adjustment under the current formula rate plan for the historical test year 2017, reflecting the change in formula rate plan revenues associated with actual 2017 results when compared to the allowed rate of return on equity. The filing included a projected $73.4 millionrevenue deficiency for 2019 and a $95.6 million revenue deficiency for the 2017 historical test year, for a total revenue requirement of $169 million for this filing. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to four percent of total revenue, which originally was $65.4 million but was increased to $66.7 million based upon the APSC staff’s updated calculation of 2018 revenue. In October 2018, Entergy Arkansas and the parties to the proceeding filed joint motions to approve a partial settlement agreement as to certain factual issues and agreed to brief contested legal issues. In November 2018 the APSC held a hearing and was briefed on a contested legal issue. In December 2018 the APSC issued a decision related to the initial legal brief, approved the partial settlement agreement and $66.7 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan, with updated rates going into effect for the first billing cycle of January 2019.
2019 Formula Rate Plan Filing
In July 2019, Entergy Arkansas filed with the APSC its 2019 formula rate plan filing to set its formula rate for the 2020 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2020 and a netting adjustment for the historical year 2018. The total proposed formula rate plan rider revenue change designed to produce a target rate of return on common equity of 9.75% is $15.3 million, which is based upon a deficiency of approximately $61.9 million for the 2020 projected year, netted with a credit of approximately $46.6 million in the 2018 historical year netting adjustment. During 2018 Entergy Arkansas experienced higher-than expected sales volume, and actual costs were lower than forecasted. These changes, coupled with a reduced income tax rate resulting from the Tax Cuts and Jobs Act, resulted in the credit for the historical year netting adjustment. In the fourth quarter 2018, Entergy Arkansas recorded a provision of $35.1 million that reflected the estimate of the historical year netting adjustment that was expected to be included in the 2019 filing. In 2019, Entergy Arkansas recorded additional provisions totaling $11.5 million to reflect the updated estimate of the historical year netting adjustment included in the 2019 filing. In October 2019 other parties in the proceeding filed their errors and objections requesting certain adjustments to Entergy Arkansas’s filing that would reduce or eliminate Entergy Arkansas’s proposed revenue change. Entergy Arkansas filed its response addressing the requested adjustments in October 2019. In its response, Entergy Arkansas accepted certain of the adjustments recommended by the General Staff of the APSC that would reduce the proposed formula rate plan rider revenue change to $14 million. Entergy Arkansas disputed the remaining adjustments proposed by the parties. In October 2019, Entergy Arkansas filed a unanimous settlement agreement with the other parties in the proceeding seeking APSC approval of a revised total formula rate plan rider revenue change of $10.1 million. In its July 2019 formula rate plan filing, Entergy Arkansas proposed to recover an $11.2 million regulatory asset, amortized over five years, associated with specific costs related to the potential construction of scrubbers at the White Bluff plant. Although Entergy Arkansas does not concede that the regulatory asset lacks merit, for purposes of reaching a settlement on the total formula rate plan rider amount, Entergy Arkansas agreed not to include the White Bluff scrubber regulatory asset cost in the 2019 formula rate plan filing or future filings. Entergy Arkansas recorded a write-off in 2019 of the $11.2 million White Bluff scrubber regulatory asset. In December 2019 the APSC approved the settlement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2020.
2020 Formula Rate Plan Filing
In July 2020, Entergy Arkansas filed with the APSC its 2020 formula rate plan filing to set its formula rate for the 2021 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2021, as amended through subsequent filings in the proceeding, and a netting adjustment for the historical year 2019. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2021 projected year is 8.22% resulting in a revenue deficiency of $64.3 million. The earned rate of return on common equity for the 2019 historical year was 9.07% resulting in a $23.9 million netting adjustment. The total proposed revenue change for the 2021 projected year and 2019 historical year netting adjustment was $88.2 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $74.3 million. In October 2020 other parties in the proceeding filed their errors
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
and objections recommending certain adjustments, and Entergy Arkansas filed responsive testimony disputing these adjustments. As part of the formula rate plan tariff the calculation for the revenue constraint was updated based on actual revenues which had the effect of reducing the initially-proposed $74.3 million revenue requirement increase to $72.6 million. In October 2020, Entergy Arkansas filed with the APSC a unanimous settlement agreement reached with the other parties that resolved all but one issue. As a result of the settlement agreement, Entergy Arkansas’s requested revenue increase was $68.4 million, including a $44.5 million increase for the projected 2021 year and a $23.9 million netting adjustment. The remaining issue litigated concerned the methodology used to calculate the netting adjustment within the formula rate plan. In December 2020 the APSC issued an order rejecting the netting adjustment method used by Entergy Arkansas. Applying the approach ordered by the APSC changed the netting adjustment for the 2019 historical year from a $23.9 million deficiency to $43.5 million excess. Overall, the decision reduced Entergy Arkansas’s revenue adjustment for 2021 to $1 million. In December 2020, Entergy Arkansas filed a petition for rehearing of the APSC’s decision, and in January 2021 the APSC granted further consideration of Entergy Arkansas’s petition. Based on the progress of the proceeding to date, in December 2020, Entergy Arkansas recorded a regulatory liability of $43.5 million to reflect the netting adjustment for 2019, as included in the APSC’s December 2020 order, which would be returned to customers in 2021. Also with the formula rate plan filing, Entergy Arkansas is requesting an extension of the formula rate plan rider for a second five-year term. Decisions by the APSC on the netting adjustment rehearing and the extension are expected in March 2021.
Internal Restructuring
In November 2017, Entergy Arkansas filed an application with the APSC seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy Arkansas to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. In July 2018, Entergy Arkansas filed a settlement, reached by all parties in the APSC proceeding, resolving all issues. The APSC approved the settlement agreement and restructuring in August 2018. Pursuant to the settlement agreement, Entergy Arkansas will credit retail customers $39.6 million over six years, beginning in 2019. Entergy Arkansas also received the required FERC and NRC approvals.
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Production Cost Allocation Rider
The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section below. These costs cause an increase in Entergy Arkansas’s deferred fuel cost balance because Entergy Arkansas pays the costs over seven months but collects the costs from customers over twelve months.
In May 2014, Entergy Arkansas filed its annual redetermination of the production cost allocation rider to recover the $3 million unrecovered retail balance as of December 31, 2013 and the $67.8 million System Agreement bandwidth remedy payment made in May 2014 as a result of the compliance filing pursuantNote 2 to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period. In January 2015 the APSC issued an order approving Entergy Arkansas’s request for recovery of the $3 million under-recovered amount based on the true-up of the production cost allocation rider and the $67.8 million May 2014 System Agreement bandwidth remedy payment subject to refund with interest, with recovery of these payments concluding with the last billing cycle in December 2015. The APSC also found that Entergy Arkansas is entitled to carrying charges pursuant to the current terms of the production cost allocation rider. Entergy Arkansas made its compliance filing pursuant to the order in January 2015 and the APSC issued its approval order, also in January 2015. The redetermined rate went into effect with the first billing cycle of February 2015.financial statements.
In May 2015, Entergy Arkansas filed its annual redetermination of the production cost allocation rider, which included a $38 million payment made by Entergy Arkansas as a result of the FERC’s February 2014 order related to the comprehensive bandwidth recalculation for calendar year 2006, 2007, and 2008 production costs. The redetermined rate for the 2015 production cost allocation rider update was added to the redetermined rate from the 2014 production
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
cost allocation rider update and the combined rate was effective with the first billing cycle of July 2015. This combined rate was effective through December 2015. The collection of the remainder of the redetermined rate for the 2015 production cost allocation rider update continued through June 2016.
In May 2016, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the production cost allocation rider true-up adjustment of the 2014 and 2015 unrecovered retail balance in the amount of $1.9 million. Additionally, the redetermined rates reflected the recovery of a $1.9 million System Agreement bandwidth remedy payment resulting from a compliance filing pursuant to the FERC’s December 2015 order related to test year 2009 production costs. The rates for the 2016 production cost allocation rider update became effective with the first billing cycle of July 2016, and the rates were effective through June 2017.
In May 2017, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected a credit amount of $0.3 million resulting from a compliance filing pursuant to the FERC’s September 2016 order. Additionally, the redetermined rate reflected recovery of the production cost allocation rider true-up adjustment of the 2016 unrecovered retail balance in the amount of $0.3 million. Because of the small effect of the 2017 production cost allocation rider update, Entergy Arkansas proposed to reduce the effective period of the update to one month, July 2017. After the one month collection period, rates were set to zero for all rate classes for the period August 2017 through June 2018.
Energy Cost Recovery Rider
Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly customer bills. The rider utilizes the prior calendar-year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over- or under-recovery, including carrying charges, of the energy costs for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs.
In January 2014, Entergy Arkansas filed a motion with the APSC relating to its redetermination of itsupcoming energy cost rate redetermination filing that was subsequently filedmade in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude $65.9 million of deferred fuel and purchased energy costs incurred in 2013 from the redetermination of its 2014 energy cost rate. Therate $65.9 million is an estimate of the incremental fuel and replacement energy costs that Entergy Arkansas incurred in 2013 as a result of the ANO stator incident. Entergy Arkansas requested that the APSC authorize Entergy Arkansas to retain that amount in its deferred fuel balance, with recovery to be reviewed in a later period after more information iswas available regarding various claims associated with the ANO stator incident. TheIn February 2014 the APSC approved Entergy Arkansas’s request to retain that amount in February 2014.its deferred fuel balance. In July 2017, Entergy Arkansas filed for a change in rates pursuant to its formula rate plan rider. In that proceeding, the APSC approved a settlement agreement agreed upon by the parties, including a provision that requires Entergy Arkansas to initiate a regulatory proceeding for the purpose of recovering funds currently withheld from rates and related to the stator incident, including the $65.9 million of deferred fuel and purchased energy costs previously noted, subject to certain timelines and conditions set forth in the settlement agreement. See the “ANO Damage, Outage, and NRC Reviews” section in Note 8 to the financial statements for further discussion of the ANO stator incident.
In March 2017, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01164 per kWh to $0.01547 per kWh. The APSC staff filed testimony in March 2017 recommending that the redetermined rate be implemented with the first billing cycle of April 2017 under the normal operation of the tariff. Accordingly, the redetermined rate went into effect on March 31, 2017 pursuant to the tariff. In July 2017 the Arkansas Attorney General requested additional information to support certain of the costs included in Entergy Arkansas’s 2017 energy cost rate redetermination.
In March 2018, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Arkansas’s annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of the redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for suspension were questions pertaining to how Entergy Arkansas forecasted sales and potential implications of the Tax Act. Entergy Arkansas replied to the Attorney General’s filing and stated that, to the extent there are questions pertaining to its load forecasting or the operation of the energy cost recovery rider, those issues exceed the scope of the instant rate redetermination. Entergy Arkansas also stated that potential effects of the Tax Act are appropriately considered in the APSC’s separate proceeding regarding potential implications of the tax law. The APSC general staff filed a reply to the Attorney General’s filing and agreed that Entergy Arkansas’s filing complied with the terms of the energy cost recovery rider. The redetermined rate became effective with the first billing cycle of April 2018. Subsequently in April 2018 the APSC issued an order declining to suspend Entergy Arkansas’s energy cost recovery rider rate and declining to require further investigation at that time of the issues suggested by the Attorney General in the
Entergy Arkansas, Inc.LLC and Subsidiaries
Management’s Financial Discussion and Analysis
proceeding. Following a period of discovery, the Attorney General filed a supplemental response in October 2018 raising new issues with Entergy Arkansas’s March 2018 rate redetermination and asserting that $45.7 million of the increase should be collected subject to refund pending further investigation. Entergy Arkansas filed to dismiss the Attorney General’s supplemental response, the APSC general staff filed a motion to strike the Attorney General’s filing, and the Attorney General filed a supplemental response disputing Entergy Arkansas and the APSC staff’s filing. Applicable APSC rules and processes authorize its general staff to initiate periodic audits of Entergy Arkansas’s energy cost recovery rider. In late-2018 the APSC general staff notified Entergy Arkansas it has initiated an audit of the 2017 fuel costs. The time in which the audit will be complete is uncertain at this time.
In March 2019, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01882 per kWh to $0.01462 per kWh and became effective with the first billing cycle in April 2019. In March 2019 the Arkansas Attorney General filed a response to Entergy Arkansas’s annual adjustment and included with its filing a motion for investigation of alleged overcharges to customers in connection with the FERC’s October 2018 order in the opportunity sales proceeding. Entergy Arkansas filed its response to the Attorney General’s motion in April 2019 in which Entergy Arkansas stated its intent to initiate a proceeding to address recovery issues related to the October 2018 FERC order. In May 2019, Entergy Arkansas initiated the opportunity sales recovery proceeding, discussed below, and requested that the APSC establish that proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC October 2018 order and related FERC orders in the opportunity sales proceeding. In June 2019 the APSC granted Entergy Arkansas’s request and also denied the Attorney General’s motion in the energy cost recovery proceeding seeking an investigation into Entergy Arkansas’s annual energy cost recovery rider adjustment and referred the evaluation of such matters to the opportunity sales recovery proceeding.
In March 2020, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01462 per kWh to $0.01052 per kWh. The redetermined rate became effective with the first billing cycle in April 2020 through the normal operation of the tariff.
Opportunity Sales Proceeding
In June 2009 the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocated the energy generated by Entergy System resources,resources; (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity,capacity; and (c) violated the provision of the System Agreement that prohibited sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challenged sales made beginning in 2002 and requestsrequested refunds. In July 2009 the Utility operating companies filed a response to the complaint requesting that the FERC dismiss the complaint on the merits without hearing because the LPSC has failed to meet its burden of showing any violation of the System Agreement and failed to produce any evidence of imprudent action by the Entergy System. In their response, the Utility operating companies explainedarguing among other things that the System Agreement clearly contemplates that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company. The FERC subsequently ordered a hearing in the proceeding.
The LPSC filed direct testimony in the proceeding alleging, among other things, (1) that Entergy violated the System Agreement by permitting Entergy Arkansas to make non-requirements sales to non-affiliated third parties rather than making such energy available to the other Utility operating companies’ customers; and (2) that over the period 2000 - 2009, these non-requirements sales caused harm to the Utility operating companies’ customers and these customers should be compensated for this harm by Entergy. In subsequent testimony, the LPSC modified its original damages claim in favor of quantifying damages by re-running intra-system bills. The Utility operating companies believe the LPSC’s allegations are without merit. AAfter a hearing, in the matter was held in August 2010.
In December 2010 the ALJ issued an initial decision.decision in December 2010. The ALJ found that the System Agreement allowed for Entergy Arkansas to make the sales to third parties but concluded that the sales should be accounted for in the same manner as joint account sales. The ALJ concluded that “shareholders” should make refunds of the damages to the Utility operating companies, along with interest. Entergy disagreed with several aspects of the ALJ’s initial decision and in January 2011 filed with the FERC exceptions to the decision.
The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith. The FERC found, however, that the System Agreement does not provide authority for an individual Utility operating company to allocate the energy associated
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
with such opportunity sales as part of its load but provides a different allocation authority. The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement. Quantifying the effect of the FERC’s decision requires re-running intra-system bills for a ten-year period, and theThe FERC in its decision established further hearing procedures to determine the calculation of the effects. In July 2012, Entergy and the LPSC filed requests for rehearing of the FERC’s June 2012 decision. A hearing was held in May 2013 to quantify the effect of repricing the opportunity sales in accordance with the FERC’s June 2012 decision.
In August The hearing was held in May 2013 and the presiding judgeALJ issued an initial decision in the calculation proceeding. The initial decision concluded that the methodology proposed by the LPSC, rather than the methodologies proposed by Entergy or the FERC Staff, should be used to calculate the payments that Entergy Arkansas is to make to the other Utility operating companies. The initial decision also concluded that the other System Agreement service schedules should not be adjusted and that payments by Entergy Arkansas should not be reflected in the rough production cost equalization bandwidth calculations for the applicable years. The initial decision recognized that the LPSC’s methodology would result in an inequitable windfall to the other Utility operating companies and, therefore, concluded that any payments by Entergy Arkansas should be reduced by 20%.August 2013. The LPSC, the APSC, the City Council, and FERC staff filed briefs on exceptions and/or briefs opposing exceptions. Entergy filed a brief on exceptions requesting that the FERC reverse the initial decision and a brief opposing certain exceptions taken by the LPSC and FERC staff.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
In April 2016 the FERC issued orders addressing requests for rehearing filed in July 2012 and the ALJ’s August 2013 initial decision. The first order denied Entergy’s request for rehearing and affirmed the FERC’s earlier rulings that Entergy’s original methodology for allocating energy costs to the opportunity sales was incorrect and, as a result, Entergy Arkansas must make payments to the other Utility operating companies to put them in the same position that they would have been in absent the incorrect allocation. The FERC clarified that interest should be included with the payments. The second order affirmed in part, and reversed in part, the rulings in the ALJ’s August 2013 initial decision regarding the methodology that should be used to calculate the payments Entergy Arkansas is to make to the other Utility operating companies. The FERC affirmed the ALJ’s ruling that a full re-run of intra-system bills should be performed but required that methodology be modified so that the sales have the same priority for purposes of energy allocation as joint account sales. The FERC reversed the ALJ’s decision that any payments by Entergy Arkansas should be reduced by 20%. The FERC also reversed the ALJ’s decision that adjustments to other System Agreement service schedules and excess bandwidth payments should not be taken into account when calculating the payments to be made by Entergy Arkansas. The FERC held that such adjustments and excess bandwidth payments should be taken into account but ordered further proceedings before an ALJ to address whether a cap on any reduction due to bandwidth payments was necessary and to implement the other adjustments to the calculation methodology.
In May 2016, Entergy Services filed a request for rehearing of the FERC’s April 2016 order arguing that payments made by Entergy Arkansas should be reduced as a result of the timing of the LPSC’s approval of certain contracts. Entergy Services also filed a request for clarification and/or rehearing of the FERC’s April 2016 order addressing the ALJ’s August 2013 initial decision. The APSC and the LPSC also filed requests for rehearing of the FERC’s April 2016 order. In September 2017 the FERC issued an order denying the request for rehearing on the issue of whether any payments by Entergy Arkansas to the other Utility operating companies should be reduced due to the timing of the LPSC’s approval of Entergy Arkansas’s wholesale baseload contract with Entergy Louisiana. In November 2017 the FERC issued an order denying all of the remaining requests for rehearing of the April 2016 order. In November 2017, Entergy Services filed a petition for review in the D.C. Circuit of the FERC’s orders in the first two phases of the opportunity sales case. In December 2017 the D.C. Circuit granted Entergy Services’sServices’ request to hold the appeal in abeyance pending final resolution of the related proceeding still pending withbefore the FERC. In January 2018 the APSC and the LPSC filed separate petitions for review in the D.C. Circuit, and the D.C. Circuit consolidated the appeals with Entergy Services’s appeal and held all ofServices’ appeal.
The hearing required by the appeals in abeyance.
Pursuant to the procedural schedule established in the case, Entergy Services re-ran intra-system bills for the ten-year period 2000-2009 to quantify the effects of the FERC's ruling. In NovemberFERC’s April 2016 the LPSC submitted testimony disputing certain aspects of the calculations. A hearingorder was held in May 2017. In July 2017 the ALJ issued an initial decision concluding that Entergy Arkansas should pay $86 million plus interestaddressing whether a cap on any reduction due to bandwidth payments was necessary and whether to implement the other adjustments to the other Utility operating companies.calculation methodology. In August 2017 the Utility operating companies, the LPSC, the APSC, and FERC staff filed individual briefs on exceptions challenging various aspects of the initial decision. In September 2017 the Utility operating companies, the LPSC, the APSC, the MPSC, the City Council, and FERC staff filed separate briefs opposing exceptions taken by various parties. The case is pending before the FERC. No payments will be made or received by the Utility operating companies until the FERC issues an order reviewing the initial decision and Entergy submits a subsequent filing to comply with that order.
The effect of the FERC’s decisions thus far in the case would be that Entergy Arkansas will make payments to some or all of the other Utility operating companies. Because further proceedings will still occur in the case, the amount and recipients of payments by Entergy Arkansas are unknown at this time. Based on testimony previously submitted in the case and its assessment of the April 2016 FERC orders, in the first quarter 2016, Entergy Arkansas recorded a liability of $87 million, which includesincluded interest, for its estimated increased costs and payment to the other Utility operating companies. This estimate is subject to change depending on how the FERC resolves the issues that are still outstanding in the case, including its review of the July 2017 initial decision. Entergy Arkansas’s increased costs will be attributed to Entergy Arkansas’s retailcompanies, and wholesale businesses, and it is not probable that Entergy Arkansas will recover the wholesale portion. Entergy Arkansas, therefore, recorded a deferred fuel regulatory asset in the first quarter 2016 of approximately $75 million, which represents its estimate of the retail portion of the costs.million. Following its assessment of the course of the proceedings, including the FERC’s denial of rehearing in November 2017
Entergy Arkansas, Inc.LLC and Subsidiaries
Management’s Financial Discussion and Analysis
November 2017 described above, in the fourth quarter 2017, Entergy Arkansas recorded an additional liability of $35 million and a regulatory asset of $31 million. Because management currently expects
In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to recovercap the retail portionreduction in Entergy Arkansas’s payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ’s decision that Grand Gulf sales from January through September 2000 should be included in the calculation of Entergy Arkansas’s payment. The FERC affirmed on other grounds the ALJ’s rejection of the costs throughLPSC’s claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.
In December 2018, Entergy made a base rate proceeding or newly proposed rider,compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. The December 2018 compliance filing is pending FERC action. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:
| | | | | | | | | | | |
| Total refunds including interest |
| Payment/(Receipt) |
| (In Millions) |
| Principal | Interest | Total |
Entergy Arkansas | $68 | $67 | $135 |
Entergy Louisiana | ($30) | ($29) | ($59) |
Entergy Mississippi | ($18) | ($18) | ($36) |
Entergy New Orleans | ($3) | ($4) | ($7) |
Entergy Texas | ($17) | ($16) | ($33) |
Entergy Arkansas previously recognized a regulatory asset is reflected as Other regulatory assetswith a balance of $116 million as of December 31, 2017.2018 for a portion of the payments due as a result of this proceeding.
As described above, the FERC’s opportunity sales orders have been appealed to the D.C. Circuit. In February 2020 all of the appeals were consolidated and in April 2020 the D.C. Circuit established a briefing schedule. Briefing was completed in September 2020 and oral argument was heard in December 2020.
In February 2019 the LPSC filed a new complaint relating to two issues that were raised in the opportunity sales proceeding, but that, in its October 2018 order, the FERC held were outside the scope of the proceeding. In March 2019, Entergy Services filed an answer and motion to dismiss the new complaint. In November 2019 the FERC issued an order denying the LPSC’s complaint. The order concluded that the settlement agreement approved by the FERC in December 2015 terminating the System Agreement barred the LPSC’s new complaint. In December 2019 the LPSC requested rehearing of the FERC’s November 2019 order, and in July 2020 the FERC issued an order dismissing the LPSC’s request for rehearing. In September 2020 the LPSC appealed to the D.C. Circuit the FERC’s orders dismissing the new opportunity sales complaint. In November 2020 the D.C. Circuit issued an order establishing that briefing will occur in January 2021 through April 2021.
In May 2019, Entergy Arkansas filed an application and supporting testimony with the APSC requesting approval of a special rider tariff to recover the costs of these payments from its retail customers over a 24-month period. The application requested that the APSC approve the rider to take effect within 30 days or, if suspended by the APSC as allowed by commission rule, approve the rider to take effect in the first billing cycle of the first month occurring 30 days after issuance of the APSC’s order approving the rider. In June 2019 the APSC suspended
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Arkansas’s tariff and granted Entergy Arkansas’s motion asking the APSC to establish the proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC’s October 2018 order and related FERC orders in the opportunity sales proceeding. In January 2020 the APSC adopted a procedural schedule with a hearing in April 2020. In January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed a joint motion seeking to dismiss Entergy Arkansas’s application alleging that the APSC, in a prior proceeding, ruled on the issues addressed in the application and determined that Entergy Arkansas’s requested relief violates the filed rate doctrine and the prohibition against retroactive ratemaking. Entergy Arkansas responded to the joint motion in February 2020 rebutting these arguments, including demonstrating that the claims in this proceeding differ substantially from those the APSC addressed previously and that the payment resulting from a FERC tariff violation for which Entergy Arkansas seeks retail cost recovery in this proceeding differs materially from the refunds resulting from a FERC tariff amendment that the APSC previously rejected on filed rate doctrine and the retroactive ratemaking grounds. In addition, in January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed testimony opposing the recovery by Entergy Arkansas of the opportunity sales payment but also claiming that certain components of the payment should be segregated and refunded to customers. In March 2020, Entergy Arkansas filed rebuttal testimony.
In July 2020 the APSC issued a decision finding that Entergy Arkansas’s application is not in the public interest. The order also directed Entergy Arkansas to refund to its retail customers within 30 days of the order the FERC-determined over-collection of $13.7 million, plus interest, associated with a recalculated bandwidth remedy. In addition to these primary findings, the order also denied the Attorney General’s request for Entergy Arkansas to prepare a compliance filing detailing all of the retail impacts from the opportunity sales and denied a request by the Arkansas Electric Energy Consumers to recalculate all costs using the revised responsibility ratio. Entergy Arkansas filed a motion for temporary stay of the 30-day requirement to allow Entergy Arkansas a reasonable opportunity to seek rehearing of the APSC order, but in July 2020 the APSC denied Entergy Arkansas’s request for a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas’s stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. In September 2020, Entergy Arkansas filed a complaint in the U. S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments. In October 2020 the APSC filed a motion to dismiss Entergy Arkansas’s complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court scheduled a hearing for February 26, 2021 regarding issues addressed in the pre-trial conference report.
Net Metering Legislation
An Arkansas law was enacted effective July 2019 that, among other things, expands the definition of a “net metering customer” to include two additional types of customers: (1) customers that lease net metering facilities, subject to certain leasing arrangements, and (2) government entities or other entities exempt from state and federal income taxes that enter into a service contract for a net metering facility. The latter provision would allow eligible entities, many of whom are small and large general service customers, to purchase renewable energy directly from third party providers and receive bill credits for these purchases. The APSC was given authority under this law to address certain matters, such as cost shifting and the appropriate compensation for net metered energy and has initiated proceedings for this purpose. Because of the size and number of customers eligible under this new law, there is a risk of loss of load and the shifting of costs to customers. A hearing was held in December 2019, with utilities, cooperatives, the Arkansas Attorney General, industrial customers, and Entergy Arkansas advocating the need for establishment of a reasonable rate structure that takes into account impacts to non-net metering customers; an additional hearing was conducted in February 2020 for purposes of public comment only. The APSC issued an order in June 2020, and in July 2020 several parties, including Entergy Arkansas, filed for rehearing on multiple
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
grounds, including for the reasons that it imposes an unreasonable rate structure and allows facilities to net meter that do not meet the statutory definition of net metering facilities. After granting the rehearing requests, the APSC issued an order in September 2020 largely upholding its June 2020 order. In October 2020, Entergy Arkansas and several other parties filed an appeal of the APSC’s September 2020 order.
Separately, as directed by the APSC general staff, the APSC opened a proceeding to compel utilities to amend their net metering tariffs to incorporate the provisions of the legislation that the APSC general staff considered “black letter law.” Entergy Arkansas, the Arkansas Attorney General, and other intervenors opposed this directive pending the development of the rules for implementation that are being considered in the separate net metering rulemaking docket. Nevertheless, reserving its rights, Entergy Arkansas has complied with the directive to amend its tariffs. Asserting procedural and due process violations, in January 2020, Entergy Arkansas and the Arkansas Attorney General separately appealed certain APSC orders in the proceeding.
COVID-19 Orders
In April 2020, in light of the COVID-19 pandemic, the APSC issued an order requiring utilities, to the extent they had not already done so, to suspend service disconnections during the remaining pendency of the Arkansas Governor’s emergency declaration or until the APSC rescinds the directive. The order also authorizes utilities to establish a regulatory asset to record costs resulting from the suspension of service disconnections, directs that in future proceedings the APSC will consider whether the request for recovery of these regulatory assets is reasonable and necessary, and requires utilities to track and report the costs and any savings directly attributable to suspension of disconnects. In May 2020 the APSC approved Entergy Arkansas expanding deferred payment agreements to assist customers during the COVID-19 pandemic. Quarterly reporting began in August 2020 and the APSC ordered additional reporting in October 2020 regarding utilities’ transitional plans for ending the moratorium on service disconnects. In February 2021 the APSC issued an order finding that it is not in the public interest to immediately lift the moratorium on service disconnects, but to announce a target date of May 3, 2021. In March 2021 the APSC will issue an order either confirming the lifting of the moratorium on service disconnects or extending the moratorium. As of December 31, 2020, Entergy Arkansas recorded a regulatory asset of $10.5 million for costs associated with the COVID-19 pandemic.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation– Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Nuclear Matters
Entergy Arkansas owns and, through an affiliate, operates the ANO 1 and ANO 2 nuclear power plants. Entergy Arkansas is, therefore, subject to the risks related to owning and operating nuclear plants. These include risks related to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, to position Entergy’s nuclear fleet to meet its operational goals,goals; the performance and capacity factors of these nuclear plants including the financial requirements to address emerging issues like stress corrosion cracking of certain materials within the plant systems and the Fukushima event;systems; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license renewal and amendments, and decommissioning; the performance and capacity factors of these nuclear plants; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts and types of insurance commercially available for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident. In the event of an unanticipated early shutdown of either ANO 1 or ANO 2, Entergy Arkansas may be required to
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
file with the APSC a rate mechanism to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. ANO 1’s operating license expires in 2034 and ANO 2’s operating license expires in 2038.
See Note 8 to the financial statements for discussion of the NRC’s decision in March 2015 to move ANO into the “multiple/repetitive degraded cornerstone column,” or Column 4, of the NRC’s Reactor Oversight Process Action Matrix, and the resulting significant additional NRC inspection activities at the ANO site.
Environmental Risks
Entergy Arkansas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Arkansas is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Arkansas’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Arkansas’s financial position or results of operations.
In the first quarter 2019, Entergy Arkansas Inc.recorded a revision to its estimated decommissioning cost liabilities for ANO 1 and SubsidiariesANO 2 as a result of a revised decommissioning cost study. The revised estimates resulted in a $126.2 million increase in its decommissioning cost liabilities, along with corresponding increases in the related asset retirement cost assets that will be depreciated over the remaining lives of the units.
Management’s Financial Discussion and Analysis
Nuclear Decommissioning Costs
See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Unbilled Revenue
See “Unbilled Revenue” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the unbilled revenue amounts.
Impairment of Long-lived Assets and Trust Fund Investments
See “Impairment of Long-lived Assets and Trust Fund Investments” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets and trust fund investments.assets.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Qualified Pension and Other Postretirement Benefits
Entergy Arkansas’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Costs and Sensitivities
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
Actuarial Assumption | | Change in Assumption | | Impact on 2021 Qualified Pension Cost | | Impact on 2020 Qualified Projected Benefit Obligation |
| | | | Increase/(Decrease) | | |
Discount rate | | (0.25%) | | $2,406 | | $46,791 |
Rate of return on plan assets | | (0.25%) | | $2,914 | | $— |
Rate of increase in compensation | | 0.25% | | $1,838 | | $8,922 |
|
| | | | | | |
Actuarial Assumption | | Change in Assumption | | Impact on 2018 Qualified Pension Cost | | Impact on 2017 Qualified Projected Benefit Obligation |
| | | | Increase/(Decrease) | | |
Discount rate | | (0.25%) | | $3,107 | | $47,040 |
Rate of return on plan assets | | (0.25%) | | $2,914 | | $- |
Rate of increase in compensation | | 0.25% | | $1,353 | | $6,446 |
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
Actuarial Assumption | | Change in Assumption | | Impact on 2021 Postretirement Benefit Cost | | Impact on 2020 Accumulated Postretirement Benefit Obligation |
| | | | Increase/(Decrease) | | |
Discount rate | | (0.25%) | | $174 | | $6,576 |
Health care cost trend | | 0.25% | | $225 | | $4,516 |
|
| | | | | | | | |
Actuarial Assumption | | Change in Assumption | | Impact on 2018 Postretirement Benefit Cost | | Impact on 2017 Accumulated Postretirement Benefit Obligation |
| | | | Increase/(Decrease) | | |
Discount rate | | (0.25%) | | $506 | |
| $7,552 |
|
Health care cost trend | | 0.25% | | $782 | |
| $5,513 |
|
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and FundingEmployer Contributions
Total qualified pension cost for Entergy Arkansas in 20172020 was $37 million.$81.7 million, including $21.1 million in settlement costs. Entergy Arkansas anticipates 20182021 qualified pension cost to be $43 million. In 2016, Entergy Arkansas refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $13.3$61.6 million. Entergy Arkansas contributed $79.6$60 million to its qualified pension planplans in 20172020 and estimates pension contributions will be approximately $64.1$66.6 million in 2018,2021, although the 20182021 required pension contributions will be known with more certainty when the January 1, 20182021 valuations are completed, which is expected by April 1, 2018.2021.
Total other postretirement health care and life insurance benefit income for Entergy Arkansas in 20172020 was $4$10.1 million. Entergy Arkansas expects 20182021 postretirement health care and life insurance benefit income of approximately $10.2 million. In 2016, Entergy Arkansas refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $2.5$11.1 million. Entergy Arkansas contributed $695 thousand$2.2 million to its other postretirement plans in 20172020 and estimates 20182021 contributions will be approximately $472$517 thousand.
Federal Healthcare Legislation
See “Qualified Pension and Other Postretirement Benefits -Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy CorporationArkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholdersmember and Board of Directors of
Entergy Arkansas, Inc.LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Arkansas, Inc.LLC and Subsidiaries (the “Company”) as of December 31, 20172020 and 2016,2019, the related consolidated statements of income, cash flows and changes in commonmember’s equity (pages 319332 through 324336 and applicable items in pages 5551 through 230)238), for each of the three years in the period ended December 31, 2017,2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172020 and 2016,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2020, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate and Regulatory Matters —Entergy Arkansas, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Arkansas Public Service Commission (the “APSC”), which has jurisdiction with respect to the rates of electric companies in Arkansas, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment;
regulatory assets and liabilities; income taxes; operating revenues; operation and maintenance expense; and depreciation and amortization expense.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the APSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the APSC and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs, including costs related to the Opportunity Sales Proceeding and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the APSC and the FERC, involved especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the APSC and the FERC included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the APSC and the FERC for the Company and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the APSC’s and the FERC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, including the Opportunity Sales Proceeding, we inspected the Company’s filings with the APSC and the FERC, including the annual formula rate plan filing, and considered the filings with the APSC and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
•We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order, including the Opportunity Sales Proceeding, to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 20182021
We have served as the Company’s auditor since 2001.
|
| | | | | | | | | | | | |
ENTERGY ARKANSAS, INC. AND SUBSIDIARIES |
CONSOLIDATED INCOME STATEMENTS |
| | |
| | For the Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In Thousands) |
| | | | | | |
OPERATING REVENUES | | | | | | |
Electric | |
| $2,139,919 |
| |
| $2,086,608 |
| |
| $2,253,564 |
|
| | | | | | |
OPERATING EXPENSES | | |
| | |
| | |
|
Operation and Maintenance: | | |
| | |
| | |
|
Fuel, fuel-related expenses, and gas purchased for resale | | 402,777 |
| | 325,036 |
| | 535,919 |
|
Purchased power | | 230,652 |
| | 233,350 |
| | 380,081 |
|
Nuclear refueling outage expenses | | 83,968 |
| | 56,650 |
| | 51,411 |
|
Other operation and maintenance | | 707,825 |
| | 706,573 |
| | 734,118 |
|
Decommissioning | | 56,860 |
| | 53,610 |
| | 50,414 |
|
Taxes other than income taxes | | 103,662 |
| | 93,109 |
| | 99,926 |
|
Depreciation and amortization | | 277,146 |
| | 264,215 |
| | 246,897 |
|
Other regulatory charges (credits) - net | | (16,074 | ) | | 7,737 |
| | (24,608 | ) |
TOTAL | | 1,846,816 |
| | 1,740,280 |
| | 2,074,158 |
|
| | | | | | |
OPERATING INCOME | | 293,103 |
| | 346,328 |
| | 179,406 |
|
| | | | | | |
OTHER INCOME | | |
| | |
| | |
|
Allowance for equity funds used during construction | | 18,452 |
| | 17,099 |
| | 14,227 |
|
Interest and investment income | | 35,882 |
| | 19,087 |
| | 22,382 |
|
Miscellaneous - net | | (299 | ) | | (1,446 | ) | | (3,385 | ) |
TOTAL | | 54,035 |
| | 34,740 |
| | 33,224 |
|
| | | | | | |
INTEREST EXPENSE | | |
| | |
| | |
|
Interest expense | | 122,075 |
| | 115,311 |
| | 105,622 |
|
Allowance for borrowed funds used during construction | | (8,585 | ) | | (9,228 | ) | | (7,805 | ) |
TOTAL | | 113,490 |
| | 106,083 |
| | 97,817 |
|
| | | | | | |
INCOME BEFORE INCOME TAXES | | 233,648 |
| | 274,985 |
| | 114,813 |
|
| | | | | | |
Income taxes | | 93,804 |
| | 107,773 |
| | 40,541 |
|
| | | | | | |
NET INCOME | | 139,844 |
| | 167,212 |
| | 74,272 |
|
| | | | | | |
Preferred dividend requirements | | 1,428 |
| | 5,270 |
| | 6,873 |
|
| | | | | | |
EARNINGS APPLICABLE TO COMMON STOCK | |
| $138,416 |
| |
| $161,942 |
| |
| $67,399 |
|
| | | | | | |
See Notes to Financial Statements. | | |
| | |
| | |
|
(Page left blank intentionally) | | | | | | | | | | | | | | | | | | | | |
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
CONSOLIDATED INCOME STATEMENTS |
| | |
| | For the Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | (In Thousands) |
| | | | | | |
OPERATING REVENUES | | | | | | |
Electric | | $2,084,494 | | | $2,259,594 | | | $2,060,643 | |
| | | | | | |
OPERATING EXPENSES | | | | | | |
Operation and Maintenance: | | | | | | |
Fuel, fuel-related expenses, and gas purchased for resale | | 271,896 | | | 458,907 | | | 517,245 | |
Purchased power | | 187,690 | | | 204,640 | | | 252,390 | |
Nuclear refueling outage expenses | | 55,737 | | | 68,769 | | | 77,915 | |
Other operation and maintenance | | 669,518 | | | 720,217 | | | 724,831 | |
Decommissioning | | 73,319 | | | 68,030 | | | 60,420 | |
Taxes other than income taxes | | 121,057 | | | 115,869 | | | 104,771 | |
Depreciation and amortization | | 338,029 | | | 307,351 | | | 292,649 | |
Other regulatory credits - net | | (35,310) | | | (11,186) | | | (14,807) | |
TOTAL | | 1,681,936 | | | 1,932,597 | | | 2,015,414 | |
| | | | | | |
OPERATING INCOME | | 402,558 | | | 326,997 | | | 45,229 | |
| | | | | | |
OTHER INCOME | | | | | | |
Allowance for equity funds used during construction | | 15,019 | | | 15,499 | | | 16,557 | |
Interest and investment income | | 35,579 | | | 26,020 | | | 25,406 | |
Miscellaneous - net | | (21,908) | | | (18,566) | | | (14,874) | |
TOTAL | | 28,690 | | | 22,953 | | | 27,089 | |
| | | | | | |
INTEREST EXPENSE | | | | | | |
Interest expense | | 144,834 | | | 140,087 | | | 124,459 | |
Allowance for borrowed funds used during construction | | (6,595) | | | (6,332) | | | (7,781) | |
TOTAL | | 138,239 | | | 133,755 | | | 116,678 | |
| | | | | | |
INCOME (LOSS) BEFORE INCOME TAXES | | 293,009 | | | 216,195 | | | (44,360) | |
| | | | | | |
Income taxes | | 47,777 | | | (46,769) | | | (297,067) | |
| | | | | | |
NET INCOME | | 245,232 | | | 262,964 | | | 252,707 | |
| | | | | | |
Preferred dividend requirements | | 0 | | | 0 | | | 1,249 | |
| | | | | | |
EARNINGS APPLICABLE TO COMMON EQUITY | | $245,232 | | | $262,964 | | | $251,458 | |
| | | | | | |
See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
ENTERGY ARKANSAS, INC. AND SUBSIDIARIES |
CONSOLIDATED STATEMENTS OF CASH FLOWS |
|
|
|
|
| For the Years Ended December 31, |
|
| 2017 |
| 2016 |
| 2015 |
|
| (In Thousands) |
OPERATING ACTIVITIES | | | | | | |
Net income | |
| $139,844 |
| |
| $167,212 |
| |
| $74,272 |
|
Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 427,394 |
| | 414,933 |
| | 400,156 |
|
Deferred income taxes, investment tax credits, and non-current taxes accrued | | 67,711 |
| | 201,219 |
| | (4,330 | ) |
Changes in assets and liabilities: | | |
| | |
| | |
|
Receivables | | (23,397 | ) | | (39,118 | ) | | 20,813 |
|
Fuel inventory | | 3,402 |
| | 29,929 |
| | (11,791 | ) |
Accounts payable | | 16,011 |
| | 143,645 |
| | (2,528 | ) |
Prepaid taxes and taxes accrued | | 40,127 |
| | 37,485 |
| | (54,531 | ) |
Interest accrued | | 1,635 |
| | (3,303 | ) | | (367 | ) |
Deferred fuel costs | | 33,190 |
| | (105,741 | ) | | 151,332 |
|
Other working capital accounts | | 15,087 |
| | (46,490 | ) | | (44,784 | ) |
Provisions for estimated losses | | 16,047 |
| | 13,130 |
| | (137 | ) |
Other regulatory assets | | (76,762 | ) | | (95,464 | ) | | 60,279 |
|
Other regulatory liabilities | | 1,043,507 |
| | 62,994 |
| | (11,123 | ) |
Deferred tax rate change recognized as regulatory liability/asset | | (1,047,837 | ) | | — |
| | — |
|
Pension and other postretirement liabilities | | (70,826 | ) | | (36,805 | ) | | (110,936 | ) |
Other assets and liabilities | | (29,577 | ) | | (67,115 | ) | | 8,565 |
|
Net cash flow provided by operating activities | | 555,556 |
| | 676,511 |
| | 474,890 |
|
INVESTING ACTIVITIES | | |
| | |
| | |
|
Construction expenditures | | (735,816 | ) | | (666,289 | ) | | (624,546 | ) |
Allowance for equity funds used during construction | | 19,211 |
| | 17,754 |
| | 15,882 |
|
Nuclear fuel purchases | | (151,424 | ) | | (102,050 | ) | | (132,252 | ) |
Proceeds from sale of nuclear fuel | | 51,029 |
| | 39,313 |
| | 52,281 |
|
Proceeds from nuclear decommissioning trust fund sales | | 339,434 |
| | 197,390 |
| | 212,954 |
|
Investment in nuclear decommissioning trust funds | | (352,138 | ) | | (213,093 | ) | | (223,357 | ) |
Payment for purchase of plant | | — |
| | (237,323 | ) | | — |
|
Changes in money pool receivable - net | | — |
| | — |
| | 2,218 |
|
Insurance proceeds | | — |
| | 10,404 |
| | 11,654 |
|
Other | | 392 |
| | 5,899 |
| | (108 | ) |
Net cash flow used in investing activities | | (829,312 | ) |
| (947,995 | ) |
| (685,274 | ) |
FINANCING ACTIVITIES | | |
| | |
| | |
|
Proceeds from the issuance of long-term debt | | 294,656 |
| | 817,563 |
| | — |
|
Retirement of long-term debt | | (175,560 | ) | | (628,433 | ) | | (13,234 | ) |
Capital contribution from parent | | — |
| | 200,000 |
| | — |
|
Redemption of preferred stock | | — |
| | (85,283 | ) | | — |
|
Change in money pool payable - net | | 114,905 |
| | (1,510 | ) | | 52,742 |
|
Changes in short-term borrowings - net | | 49,974 |
| | (11,690 | ) | | (36,278 | ) |
Dividends paid: | | |
| | |
| | |
|
Common stock | | (15,000 | ) | | — |
| | — |
|
Preferred stock | | (1,428 | ) | | (6,631 | ) | | (6,873 | ) |
Other | | (8,084 | ) | | (1,158 | ) | | 4,657 |
|
Net cash flow provided by financing activities | | 259,463 |
| | 282,858 |
| | 1,014 |
|
Net increase (decrease) in cash and cash equivalents | | (14,293 | ) | | 11,374 |
| | (209,370 | ) |
Cash and cash equivalents at beginning of period | | 20,509 |
| | 9,135 |
| | 218,505 |
|
Cash and cash equivalents at end of period | |
| $6,216 |
| |
| $20,509 |
| |
| $9,135 |
|
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | |
| | |
|
Cash paid (received) during the period for: | | |
| | |
| | |
|
Interest - net of amount capitalized | |
| $115,162 |
| |
| $112,912 |
| |
| $100,435 |
|
Income taxes | |
| ($8,141 | ) | |
| ($135,709 | ) | |
| $103,296 |
|
See Notes to Financial Statements. |
| |
|
| |
|
| |
|
| | | | | | | | | | | | | | | | | | | | |
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | For the Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | (In Thousands) |
OPERATING ACTIVITIES | | | | | | |
Net income | | $245,232 | | | $262,964 | | | $252,707 | |
Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 490,457 | | | 465,299 | | | 443,698 | |
Deferred income taxes, investment tax credits, and non-current taxes accrued | | 87,019 | | | 94,368 | | | 129,524 | |
Changes in assets and liabilities: | | | | | | |
Receivables | | (24,507) | | | (58,077) | | | 4,294 | |
Fuel inventory | | (10,066) | | | (10,597) | | | 6,210 | |
Accounts payable | | (22,773) | | | 3,059 | | | (126,405) | |
Prepaid taxes and taxes accrued | | 6 | | | 24,942 | | | 9,568 | |
Interest accrued | | (43) | | | 3,895 | | | 678 | |
Deferred fuel costs | | (1,186) | | | 72,560 | | | 43,869 | |
Other working capital accounts | | (11,061) | | | 18,783 | | | (30,118) | |
Provisions for estimated losses | | 6,289 | | | 14,901 | | | 14,250 | |
Other regulatory assets | | (165,534) | | | (131,873) | | | 32,460 | |
Other regulatory liabilities | | 106,878 | | | 39,293 | | | (341,682) | |
| | | | | | |
Pension and other postretirement liabilities | | 42,576 | | | 5,831 | | | (40,157) | |
Other assets and liabilities | | (83,469) | | | (127,582) | | | (187,071) | |
Net cash flow provided by operating activities | | 659,818 | | | 677,766 | | | 211,825 | |
INVESTING ACTIVITIES | | | | | | |
Construction expenditures | | (775,595) | | | (641,525) | | | (660,044) | |
Allowance for equity funds used during construction | | 15,019 | | | 15,306 | | | 17,013 | |
Nuclear fuel purchases | | (100,678) | | | (54,344) | | | (99,417) | |
Proceeds from sale of nuclear fuel | | 30,638 | | | 22,782 | | | 54,810 | |
| | | | | | |
Proceeds from nuclear decommissioning trust fund sales | | 321,360 | | | 317,377 | | | 300,801 | |
Investment in nuclear decommissioning trust funds | | (336,392) | | | (336,519) | | | (315,163) | |
Payment for purchase of assets | | (5,988) | | | 0 | | | 0 | |
Changes in money pool receivable - net | | (3,110) | | | 0 | | | 0 | |
| | | | | | |
| | | | | | |
| | | | | | |
Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | 55,001 | | | 0 | | | 0 | |
| | | | | | |
Insurance proceeds | | 0 | | | 0 | | | 14,790 | |
Other | | 4,036 | | | 630 | | | (1,517) | |
Net cash flow used in investing activities | | (795,709) | | | (676,293) | | | (688,727) | |
FINANCING ACTIVITIES | | | | | | |
Proceeds from the issuance of long-term debt | | 1,071,121 | | | 834,038 | | | 958,434 | |
Retirement of long-term debt | | (632,175) | | | (548,952) | | | (690,488) | |
Capital contribution from parent | | 0 | | | 0 | | | 350,000 | |
Redemption of preferred stock | | 0 | | | 0 | | | (32,660) | |
Change in money pool payable - net | | (21,634) | | | (161,104) | | | 16,601 | |
Changes in short-term borrowings - net | | 0 | | | 0 | | | (49,974) | |
Distributions/dividends paid: | | | | | | |
Common equity | | (95,000) | | | (115,000) | | | (91,751) | |
Preferred stock | | 0 | | | 0 | | | (1,606) | |
Other | | 2,188 | | | (7,055) | | | 12,249 | |
Net cash flow provided by financing activities | | 324,500 | | | 1,927 | | | 470,805 | |
Net increase (decrease) in cash and cash equivalents | | 188,609 | | | 3,400 | | | (6,097) | |
Cash and cash equivalents at beginning of period | | 3,519 | | | 119 | | | 6,216 | |
Cash and cash equivalents at end of period | | $192,128 | | | $3,519 | | | $119 | |
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
Cash paid (received) during the period for: | | | | | | |
Interest - net of amount capitalized | | $140,735 | | | $131,134 | | | $118,731 | |
Income taxes | | ($21,971) | | | ($33,989) | | | $44,393 | |
See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | |
ENTERGY ARKANSAS, INC. AND SUBSIDIARIES |
CONSOLIDATED BALANCE SHEETS |
ASSETS |
| | |
| | December 31, |
| | 2017 | | 2016 |
| | (In Thousands) |
| | | | |
CURRENT ASSETS | | | | |
Cash and cash equivalents: | | | | |
Cash | |
| $6,184 |
| |
| $20,174 |
|
Temporary cash investments | | 32 |
| | 335 |
|
Total cash and cash equivalents | | 6,216 |
| | 20,509 |
|
Securitization recovery trust account | | 3,748 |
| | 4,140 |
|
Accounts receivable: | | |
| | |
|
Customer | | 110,016 |
| | 102,229 |
|
Allowance for doubtful accounts | | (1,063 | ) | | (1,211 | ) |
Associated companies | | 38,765 |
| | 35,286 |
|
Other | | 65,209 |
| | 58,153 |
|
Accrued unbilled revenues | | 105,120 |
| | 100,193 |
|
Total accounts receivable | | 318,047 |
| | 294,650 |
|
Deferred fuel costs | | 63,302 |
| | 96,690 |
|
Fuel inventory - at average cost | | 29,358 |
| | 32,760 |
|
Materials and supplies - at average cost | | 192,853 |
| | 182,600 |
|
Deferred nuclear refueling outage costs | | 56,485 |
| | 81,313 |
|
Prepayments and other | | 12,108 |
| | 14,293 |
|
TOTAL | | 682,117 |
| | 726,955 |
|
| | | | |
OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
Decommissioning trust funds | | 944,890 |
| | 834,735 |
|
Other | | 3,160 |
| | 7,912 |
|
TOTAL | | 948,050 |
| | 842,647 |
|
| | | | |
UTILITY PLANT | | |
| | |
|
Electric | | 11,059,538 |
| | 10,488,060 |
|
Property under capital lease | | — |
| | 716 |
|
Construction work in progress | | 280,888 |
| | 304,073 |
|
Nuclear fuel | | 277,345 |
| | 307,352 |
|
TOTAL UTILITY PLANT | | 11,617,771 |
| | 11,100,201 |
|
Less - accumulated depreciation and amortization | | 4,762,352 |
| | 4,635,885 |
|
UTILITY PLANT - NET | | 6,855,419 |
| | 6,464,316 |
|
| | | | |
DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
Regulatory assets: | | |
| | |
|
Regulatory asset for income taxes - net | | — |
| | 62,646 |
|
Other regulatory assets (includes securitization property of $28,583 as of December 31, 2017 and $41,164 as of December 31, 2016) | | 1,567,437 |
| | 1,428,029 |
|
Deferred fuel costs | | 67,096 |
| | 66,898 |
|
Other | | 13,910 |
| | 14,626 |
|
TOTAL | | 1,648,443 |
| | 1,572,199 |
|
| | | | |
TOTAL ASSETS | |
| $10,134,029 |
| |
| $9,606,117 |
|
| | | | |
See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | |
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
CONSOLIDATED BALANCE SHEETS |
ASSETS |
| | |
| | December 31, |
| | 2020 | | 2019 |
| | (In Thousands) |
| | | | |
CURRENT ASSETS | | | | |
Cash and cash equivalents: | | | | |
Cash | | $24,108 | | | $3,519 | |
Temporary cash investments | | 168,020 | | | 0 | |
Total cash and cash equivalents | | 192,128 | | | 3,519 | |
Securitization recovery trust account | | 0 | | | 4,036 | |
Accounts receivable: | | | | |
Customer | | 183,719 | | | 117,679 | |
Allowance for doubtful accounts | | (18,334) | | | (1,169) | |
Associated companies | | 34,216 | | | 29,178 | |
Other | | 35,845 | | | 117,653 | |
Accrued unbilled revenues | | 109,000 | | | 108,489 | |
Total accounts receivable | | 344,446 | | | 371,830 | |
| | | | |
| | | | |
Fuel inventory - at average cost | | 43,811 | | | 33,745 | |
Materials and supplies - at average cost | | 237,640 | | | 211,320 | |
Deferred nuclear refueling outage costs | | 32,692 | | | 48,875 | |
| | | | |
| | | | |
Prepayments and other | | 13,296 | | | 14,096 | |
| | | | |
TOTAL | | 864,013 | | | 687,421 | |
| | | | |
OTHER PROPERTY AND INVESTMENTS | | | | |
Decommissioning trust funds | | 1,273,921 | | | 1,101,283 | |
| | | | |
Other | | 341 | | | 345 | |
TOTAL | | 1,274,262 | | | 1,101,628 | |
| | | | |
UTILITY PLANT | | | | |
Electric | | 12,905,322 | | | 12,293,483 | |
| | | | |
Construction work in progress | | 234,213 | | | 197,775 | |
Nuclear fuel | | 163,044 | | | 195,547 | |
TOTAL UTILITY PLANT | | 13,302,579 | | | 12,686,805 | |
Less - accumulated depreciation and amortization | | 5,255,355 | | | 5,019,826 | |
UTILITY PLANT - NET | | 8,047,224 | | | 7,666,979 | |
| | | | |
DEFERRED DEBITS AND OTHER ASSETS | | | | |
Regulatory assets: | | | | |
| | | | |
Other regulatory assets (includes securitization property of $0 as of December 31, 2020 and $1,706 as of December 31, 2019) | | 1,832,384 | | | 1,666,850 | |
Deferred fuel costs | | 68,220 | | | 67,690 | |
Other | | 14,028 | | | 15,065 | |
TOTAL | | 1,914,632 | | | 1,749,605 | |
| | | | |
TOTAL ASSETS | | $12,100,131 | | | $11,205,633 | |
| | | | |
See Notes to Financial Statements. | | | | |
| | ENTERGY ARKANSAS, INC. AND SUBSIDIARIES | |
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES | | ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
CONSOLIDATED BALANCE SHEETS | CONSOLIDATED BALANCE SHEETS | CONSOLIDATED BALANCE SHEETS |
LIABILITIES AND EQUITY | LIABILITIES AND EQUITY | LIABILITIES AND EQUITY |
| | | | |
| | December 31, | | | December 31, |
| | 2017 | | 2016 | | | 2020 | | 2019 |
| | (In Thousands) | | | (In Thousands) |
| | | | | |
CURRENT LIABILITIES | | | | | CURRENT LIABILITIES | | | | |
Currently maturing long-term debt | |
| $— |
| |
| $114,700 |
| Currently maturing long-term debt | | $485,000 | | | $0 | |
Short-term borrowings | | 49,974 |
| | — |
| |
| Accounts payable: | | |
| | |
| Accounts payable: | | | | |
Associated companies | | 365,915 |
| | 239,711 |
| Associated companies | | 59,448 | | | 111,785 | |
Other | | 215,942 |
| | 185,153 |
| Other | | 208,591 | | | 202,201 | |
Customer deposits | | 97,687 |
| | 97,512 |
| Customer deposits | | 98,506 | | | 101,411 | |
Taxes accrued | | 47,321 |
| | 7,194 |
| Taxes accrued | | 81,837 | | | 81,831 | |
| Interest accrued | | 18,215 |
| | 16,580 |
| Interest accrued | | 22,745 | | | 22,788 | |
Deferred fuel costs | | Deferred fuel costs | | 53,065 | | | 53,721 | |
Current portion of unprotected excess accumulated deferred income taxes | | Current portion of unprotected excess accumulated deferred income taxes | | 0 | | | 9,296 | |
Other | | 29,922 |
| | 36,557 |
| Other | | 40,628 | | | 38,760 | |
TOTAL | | 824,976 |
| | 697,407 |
| TOTAL | | 1,049,820 | | | 621,793 | |
| | | | | | | | |
NON-CURRENT LIABILITIES | | |
| | |
| NON-CURRENT LIABILITIES | | | | |
Accumulated deferred income taxes and taxes accrued | | 1,190,669 |
| | 2,186,623 |
| Accumulated deferred income taxes and taxes accrued | | 1,286,123 | | | 1,183,126 | |
Accumulated deferred investment tax credits | | 34,104 |
| | 35,305 |
| Accumulated deferred investment tax credits | | 30,500 | | | 31,701 | |
Regulatory liability for income taxes - net | | 985,823 |
| | — |
| Regulatory liability for income taxes - net | | 467,031 | | | 478,174 | |
Other regulatory liabilities | | 363,591 |
| | 305,907 |
| Other regulatory liabilities | | 686,872 | | | 559,555 | |
Decommissioning | | 981,213 |
| | 924,353 |
| Decommissioning | | 1,314,160 | | | 1,242,616 | |
Accumulated provisions | | 34,729 |
| | 18,682 |
| Accumulated provisions | | 70,169 | | | 63,880 | |
Pension and other postretirement liabilities | | 353,274 |
| | 424,234 |
| Pension and other postretirement liabilities | | 361,682 | | | 319,075 | |
Long-term debt (includes securitization bonds of $34,662 as of December 31, 2017 and $48,139 as of December 31, 2016) | | 2,952,399 |
| | 2,715,085 |
| |
Long-term debt (includes securitization bonds of $0 as of December 31, 2020 and $6,772 as of December 31, 2019) | | Long-term debt (includes securitization bonds of $0 as of December 31, 2020 and $6,772 as of December 31, 2019) | | 3,482,507 | | | 3,517,208 | |
Other | | 5,147 |
| | 13,854 |
| Other | | 75,098 | | | 62,568 | |
TOTAL | | 6,900,949 |
| | 6,624,043 |
| TOTAL | | 7,774,142 | | | 7,457,903 | |
| | | | | | | | |
Commitments and Contingencies | |
|
| |
|
| Commitments and Contingencies | | 0 | | 0 |
| | | | | |
Preferred stock without sinking fund | | 31,350 |
| | 31,350 |
| |
| | | | | |
COMMON EQUITY | | |
| | |
| |
Common stock, $0.01 par value, authorized 325,000,000 shares; issued and outstanding 46,980,196 shares in 2017 and 2016 | | 470 |
| | 470 |
| |
Paid-in capital | | 790,264 |
| | 790,243 |
| |
Retained earnings | | 1,586,020 |
| | 1,462,604 |
| |
| EQUITY | | EQUITY | | | | |
Member's equity | | Member's equity | | 3,276,169 | | | 3,125,937 | |
TOTAL | | 2,376,754 |
| | 2,253,317 |
| TOTAL | | 3,276,169 | | | 3,125,937 | |
| | | | | | | | |
TOTAL LIABILITIES AND EQUITY | |
| $10,134,029 |
| |
| $9,606,117 |
| TOTAL LIABILITIES AND EQUITY | | $12,100,131 | | | $11,205,633 | |
| | | | | | | | |
See Notes to Financial Statements. | | |
| | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | | | | | | | | | |
ENTERGY ARKANSAS, INC. AND SUBSIDIARIES |
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY |
For the Years Ended December 31, 2017, 2016, and 2015 |
| | | | |
| | Common Equity | | |
| | Common Stock | | Paid-in Capital | | Retained Earnings | | Total |
| | (In Thousands) | | |
| | | | | | | | |
Balance at December 31, 2014 | |
| $470 |
| |
| $588,471 |
| |
| $1,235,296 |
| |
| $1,824,237 |
|
Net income | | — |
| | — |
| | 74,272 |
| | 74,272 |
|
Preferred stock dividends | | — |
| | — |
| | (6,873 | ) | | (6,873 | ) |
Other | | — |
| | 22 |
| | — |
| | 22 |
|
Balance at December 31, 2015 | |
| $470 |
| |
| $588,493 |
| |
| $1,302,695 |
| |
| $1,891,658 |
|
Net income | | — |
| | — |
| | 167,212 |
| | 167,212 |
|
Capital contributions from parent | | — |
| | 200,000 |
| | — |
| | 200,000 |
|
Capital stock redemption | | — |
| | 1,750 |
| | (2,033 | ) | | (283 | ) |
Preferred stock dividends | | — |
| | — |
| | (5,270 | ) | | (5,270 | ) |
Balance at December 31, 2016 | |
| $470 |
| |
| $790,243 |
| |
| $1,462,604 |
| |
| $2,253,317 |
|
Net income | | — |
| | — |
| | 139,844 |
| | 139,844 |
|
Common stock dividends | | — |
| | — |
| | (15,000 | ) | | (15,000 | ) |
Preferred stock dividends | | — |
| | — |
| | (1,428 | ) | | (1,428 | ) |
Other | | — |
| | 21 |
| | — |
| | 21 |
|
Balance at December 31, 2017 | |
| $470 |
| |
| $790,264 |
| |
| $1,586,020 |
| |
| $2,376,754 |
|
| | | | | | | | |
See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
| | | | | |
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY |
For the Years Ended December 31, 2020, 2019, and 2018 |
| |
| |
| Member's Equity |
| (In Thousands) |
| |
Balance at December 31, 2017 | $2,376,754 | |
Net income | 252,707 | |
Capital contributions from parent | 350,000 | |
| |
Common equity distributions | (91,751) | |
Non-cash contribution from parent | 94,335 | |
Preferred stock dividends | (1,249) | |
Other | 2,307 | |
Balance at December 31, 2018 | $2,983,103 | |
Net income | 262,964 | |
| |
| |
Common equity distributions | (115,000) | |
| |
| |
Other | (5,130) | |
Balance at December 31, 2019 | $3,125,937 | |
Net income | 245,232 | |
| |
| |
Common equity distributions | (95,000) | |
| |
| |
| |
Balance at December 31, 2020 | $3,276,169 | |
| |
See Notes to Financial Statements. | |
|
| | | | | | | | | | | | | | | | | | | | |
ENTERGY ARKANSAS, INC. AND SUBSIDIARIES |
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (In Thousands) |
| | | | | | | | | | |
Operating revenues | |
| $2,139,919 |
| |
| $2,086,608 |
| |
| $2,253,564 |
| |
| $2,172,391 |
| |
| $2,190,159 |
|
Net income | |
| $139,844 |
| |
| $167,212 |
| |
| $74,272 |
| |
| $121,392 |
| |
| $161,948 |
|
Total assets | |
| $10,134,029 |
| |
| $9,606,117 |
| |
| $8,747,774 |
| |
| $8,777,655 |
| |
| $8,007,707 |
|
Long-term obligations (a) | |
| $2,983,749 |
| |
| $2,746,435 |
| |
| $2,691,189 |
| |
| $2,757,423 |
| |
| $2,424,969 |
|
| | | | | | | | | | |
(a) Includes long-term debt (excluding currently maturing debt) and preferred stock without sinking fund. |
| | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (Dollars In Millions) |
| | | | | | | | | | |
Electric Operating Revenues: | | |
| | |
| | |
| | |
| | |
|
Residential | |
| $768 |
| |
| $789 |
| |
| $824 |
| |
| $755 |
| |
| $772 |
|
Commercial | | 495 |
| | 495 |
| | 515 |
| | 461 |
| | 469 |
|
Industrial | | 472 |
| | 446 |
| | 477 |
| | 424 |
| | 433 |
|
Governmental | | 19 |
| | 18 |
| | 20 |
| | 18 |
| | 19 |
|
Total retail | | 1,754 |
| | 1,748 |
| | 1,836 |
| | 1,658 |
| | 1,693 |
|
Sales for resale: | | |
| | |
| | |
| | |
| | |
|
Associated companies | | 128 |
| | 49 |
| | 128 |
| | 131 |
| | 346 |
|
Non-associated companies | | 121 |
| | 118 |
| | 195 |
| | 282 |
| | 83 |
|
Other | | 137 |
| | 172 |
| | 95 |
| | 101 |
| | 68 |
|
Total | |
| $2,140 |
| |
| $2,087 |
| |
| $2,254 |
| |
| $2,172 |
| |
| $2,190 |
|
| | | | | | | | | | |
Billed Electric Energy Sales (GWh): | | | | |
| | |
| | |
| | |
|
Residential | | 7,298 |
| | 7,618 |
| | 8,016 |
| | 8,070 |
| | 7,921 |
|
Commercial | | 5,825 |
| | 5,988 |
| | 6,020 |
| | 5,934 |
| | 5,929 |
|
Industrial | | 7,528 |
| | 6,795 |
| | 6,889 |
| | 6,808 |
| | 6,769 |
|
Governmental | | 237 |
| | 237 |
| | 235 |
| | 238 |
| | 241 |
|
Total retail | | 20,888 |
| | 20,638 |
| | 21,160 |
| | 21,050 |
| | 20,860 |
|
Sales for resale: | | |
| | |
| | |
| | |
| | |
|
Associated companies | | 1,782 |
| | 1,609 |
| | 2,239 |
| | 2,299 |
| | 7,918 |
|
Non-associated companies | | 6,549 |
| | 7,115 |
| | 7,980 |
| | 8,003 |
| | 1,011 |
|
Total | | 29,219 |
| | 29,362 |
| | 31,379 |
| | 31,352 |
| | 29,789 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | (In Thousands) |
| | | | | | | | | | |
Operating revenues | | $2,084,494 | | | $2,259,594 | | | $2,060,643 | | | $2,139,919 | | | $2,086,608 | |
Net income | | $245,232 | | | $262,964 | | | $252,707 | | | $139,844 | | | $167,212 | |
Total assets | | $12,100,131 | | | $11,205,633 | | | $10,401,596 | | | $10,134,029 | | | $9,606,117 | |
Long-term obligations (a) | | $3,482,507 | | | $3,517,208 | | | $3,225,759 | | | $2,983,749 | | | $2,746,435 | |
| | | | | | | | | | |
(a) Includes long-term debt (excluding currently maturing debt) and preferred stock without sinking fund. |
| | | | | | | | | | |
| | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | (Dollars In Millions) |
| | | | | | | | | | |
Electric Operating Revenues: | | | | | | | | | | |
Residential | | $841 | | | $795 | | | $807 | | | $768 | | | $789 | |
Commercial | | 466 | | | 539 | | | 426 | | | 495 | | | 495 | |
Industrial | | 462 | | | 521 | | | 434 | | | 472 | | | 446 | |
Governmental | | 18 | | | 21 | | | 17 | | | 19 | | | 18 | |
Total billed retail | | 1,787 | | | 1,876 | | | 1,684 | | | 1,754 | | | 1,748 | |
Sales for resale: | | | | | | | | | | |
Associated companies | | 105 | | | 118 | | | 104 | | | 128 | | | 49 | |
Non-associated companies | | 68 | | | 140 | | | 145 | | | 121 | | | 118 | |
Other | | 124 | | | 126 | | | 128 | | | 137 | | | 172 | |
Total | | $2,084 | | | $2,260 | | | $2,061 | | | $2,140 | | | $2,087 | |
| | | | | | | | | | |
Billed Electric Energy Sales (GWh): | | | | | | | | | | |
Residential | | 7,584 | | | 7,996 | | | 8,248 | | | 7,298 | | | 7,618 | |
Commercial | | 5,356 | | | 5,822 | | | 5,967 | | | 5,825 | | | 5,988 | |
Industrial | | 7,586 | | | 7,759 | | | 8,071 | | | 7,528 | | | 6,795 | |
Governmental | | 223 | | | 241 | | | 239 | | | 237 | | | 237 | |
Total retail | | 20,749 | | | 21,818 | | | 22,525 | | | 20,888 | | | 20,638 | |
Sales for resale: | | | | | | | | | | |
Associated companies | | 1,659 | | | 2,180 | | | 1,773 | | | 1,782 | | | 1,609 | |
Non-associated companies | | 4,198 | | | 7,206 | | | 6,447 | | | 6,549 | | | 7,115 | |
Total | | 26,606 | | | 31,204 | | | 30,745 | | | 29,219 | | | 29,362 | |
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
ResultsThe COVID-19 Pandemic
See “The COVID-19 Pandemic” section of Operations
Net Income
2017 Compared to 2016
Net income decreased $305.7 million primarily due to the effect of the enactment of the Tax CutsEntergy Corporation and Jobs Act, in December 2017, which resulted inSubsidiaries Management’s Financial Discussion and Analysis for a decrease of $182.6 million in net income in 2017, and the effect of a settlement with the IRS related to the 2010-2011 IRS audit, which resulted in a $136.1 million reduction of income tax expense in 2016. Also contributing to the decrease in net income were higher other operation and maintenance expenses. The decrease was partially offset by higher net revenue and higher other income. See Note 3 to the financial statements for discussion of the effectsCOVID-19 pandemic.
Hurricane Laura, Hurricane Delta, and Hurricane Zeta
In August 2020 and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of the Tax CutsEntergy Louisiana’s service area. The storms resulted in widespread outages, significant damage to distribution and Jobs Acttransmission infrastructure, and the IRS audit.
2016 Compared to 2015
Net income increased $175.4 million primarily due toloss of sales during the effect of a settlement with the IRS related to the 2010-2011 IRS audit, which resulted in a $136.1 million reduction of income tax expense in 2016. Also contributing to the increase were lower other operation and maintenance expenses, higher net revenue, and higher other income. The increase was partially offset by higher depreciation and amortization expenses, higher interest expense, and higher nuclear refueling outage expenses. See Note 3 to the financial statements for discussion of the IRS audit.
Net Revenue
2017 Compared to 2016
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2017 to 2016.
|
| | | |
| Amount |
| (In Millions) |
| |
2016 net revenue |
| $2,438.4 |
|
Regulatory credit resulting from reduction of the
federal corporate income tax rate
| 55.5 |
|
Retail electric price | 42.8 |
|
Louisiana Act 55 financing savings obligation | 17.2 |
|
Volume/weather | (12.4 | ) |
Other | 19.0 |
|
2017 net revenue |
| $2,560.5 |
|
The regulatory credit resulting from reduction of the federal corporate income tax rate variance is due to the reduction of the Vidalia purchased power agreement regulatory liability by $30.5 million and the reduction of the Louisiana Act 55 financing savings obligation regulatory liabilities by $25 millionoutages. Additionally, as a result of Hurricane Laura’s extensive damage to the enactmentgrid infrastructure serving the impacted area, large portions of the Tax Cutsunderlying transmission system required nearly a complete rebuild. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by Hurricane Laura, Hurricane Delta, and Jobs Act,Hurricane Zeta are currently estimated to be approximately $2.0 billion, including approximately $1.67 billion in capital costs and approximately $330 million in non-capital costs. This estimate includes all costs to restore power and repair or replace the damages from the hurricanes, except for the cost to repair or replace damage incurred to an Entergy Louisiana transmission line in southeast Louisiana, and the amount of that cost could be significant. The restoration plan for this transmission line and the related cost estimate is still being evaluated. Also, Entergy Louisiana’s revenues were adversely affected in 2020, primarily due to power outages resulting from the hurricanes. Entergy Louisiana is considering all reasonable avenues to recover storm-related costs from Hurricane Laura, Hurricane Delta, and Hurricane Zeta, including securitization. Storm cost recovery or financing will be subject to review by applicable regulatory authorities.
Entergy Louisiana recorded accounts payable and corresponding construction work in progress and regulatory assets for the estimated costs incurred that were necessary to return customers to service. Entergy Louisiana recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. There are well established mechanisms and precedent for addressing these catastrophic events and providing for recovery of prudently incurred storm costs in accordance with applicable regulatory and legal principles. Because Entergy Louisiana has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
In October 2020, Entergy Louisiana filed an application at the LPSC seeking approval of certain ratemaking adjustments to facilitate issuance of shorter-term bonds to provide interim financing for restoration costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta. Subsequently, Entergy Louisiana and the LPSC staff filed a joint motion seeking approval to exclude from the derivation of Entergy Louisiana’s capital structure and cost rate of debt for ratemaking purposes, including the allowance for funds used during construction, shorter-term debt up to $1.1 billion issued by Entergy Louisiana to fund costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta costs on an interim basis. In November 2020 the LPSC issued an order approving the joint motion, and Entergy Louisiana issued $1.1 billion of 0.62% Series mortgage bonds due November 2023. Also in November 2020, Entergy Louisiana drew $257 million from its funded storm reserves.
In December 2017,2020, Entergy Louisiana provided the LPSC with notification that it intends to initiate a storm cost recovery proceeding in the near future, which loweredwill permit the federal corporate income tax rate from 35%LPSC to 21%. The effectsretain any outside consultants and counsel needed to review the storm cost recovery application. In February 2021 the LPSC voted to retain outside counsel and consultants to assist in the review of the Tax Cuts and Jobs Act are discussed furtherEntergy Louisiana’s upcoming storm cost recovery application, which is expected to be filed in Note 3 to the financial statements.
March 2021.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
February 2021 Winter Storms
See the “February 2021 Winter Storms” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the February 2021 winter storms. Entergy Louisiana’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $50 million to $60 million. Natural gas purchases for Entergy Louisiana for February 1st through 25th, 2021 are approximately $190 million compared to natural gas purchases for February 2020 of $39 million.
Results of Operations
2020 Compared to 2019
Net Income
Net income increased $390.8 million primarily due to the $382.8 million reduction in deferred income tax expense related to the basis of assets contributed in the 2015 Entergy Louisiana and Entergy Gulf States Louisiana business combination as a result of the resolution of the 2014-2015 IRS audit in the fourth quarter 2020 and the $58 million reduction in income tax expense resulting from an IRS settlement in the first quarter 2020 related to the uncertain tax position regarding the Hurricane Isaac Louisiana Act 55 financing, which also resulted in a $29 million ($21 million net-of-tax) regulatory charge to reflect Entergy Louisiana’s agreement to share the savings with customers. Also contributing to the increase were higher retail electric price, lower other operation and maintenance expenses, and a lower effective income tax rate. The increase was partially offset by higher depreciation and amortization expenses, lower volume/weather, lower other income, higher interest expense, and higher taxes other than income taxes. See Note 3 to the financial statements for further discussion of the tax audit resolution and the tax settlement.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2020 to 2019:
| | | | | |
| Amount |
| (In Millions) |
2019 operating revenues | $4,285.2 | |
Fuel, rider, and other revenues that do not significantly affect net income | (330.3) | |
Volume/weather | (68.8) | |
Return of unprotected excess accumulated deferred income taxes to customers | 7.5 | |
Retail electric price | 176.3 | |
2020 operating revenues | $4,069.9 | |
Entergy Louisiana’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The volume/weather variance is primarily due to decreased commercial and industrial usage as a result of the COVID-19 pandemic, the effects of Hurricane Laura, Hurricane Delta, and Hurricane Zeta on sales, and the effect of less favorable weather on residential sales, partially offset by increased residential usage as a result of the COVID-19 pandemic. The decrease in industrial usage is partially offset by an increase in demand from expansion projects, primarily in the transportation and chemicals industries. See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
COVID-19 pandemic. See “Hurricane Laura, Hurricane Delta, and Hurricane Zeta” above for discussion of the storms.
The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through changes in the formula rate plan effective May 2018. In 2020, $31.1 million was returned to customers as compared to $38.6 million in 2019. There was no effect on net income as the reduction in operating revenues was offset by a reduction in income tax expense. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
The retail electric price variance is primarily due to an increase in formula rate plan revenues implemented witheffective June 2019 due to the first billing cycleinclusion of March 2016, to collect the estimated first-year revenue requirement relatedfor the J. Wayne Leonard Power Station (formerly St. Charles Power Station) and effective April 2020 due to the purchase of Power Blocks 3 and 4inclusion of the Unionfirst-year revenue requirement for the Lake Charles Power Station and increases in March 2016formula rate plan revenues effective September 2019 and a provision recorded in 2016 related to the settlement of the Waterford 3 replacement steam generator prudence review proceeding.September 2020. See Note 2 to the financial statements for further discussion of the formula rate plan revenues and the Waterford 3 replacement steam generator prudence review proceeding.proceedings.
The Louisiana Act 55 financing savings obligation variance results from a regulatory charge recorded in 2016 for tax savings to be shared with customers per an agreement approved by the LPSC. The tax savings resulted from the 2010-2011 IRS audit settlement on the treatment of the Louisiana Act 55 financing of storm costs for Hurricane Gustav and Hurricane Ike. See Note 3 to the financial statements for additional discussion of the settlement and benefit sharing.
The volume/weather variance is primarily due to the effect of less favorable weather on residential and commercial sales and decreased usage during the unbilled sales period. The decrease was partially offset by an increase of 1,237 GWh, or 4%, in industrial usage primarily due to an increase in demand from existing customers and expansion projects in the chemicals industry.
2016 Compared to 2015
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenue comparing 2016 to 2015.
|
| | | |
| Amount |
| (In Millions) |
| |
2015 net revenue |
| $2,408.8 |
|
Retail electric price | 62.5 |
|
Volume/weather | (6.7 | ) |
Louisiana Act 55 financing savings obligation | (17.2 | ) |
Other | (9.0 | ) |
2016 net revenue |
| $2,438.4 |
|
The retail electric price variance is primarily due to an increase in formula rate plan revenues, implemented with the first billing cycle of March 2016, to collect the estimated first-year revenue requirement related to the purchase of Power Blocks 3 and 4 of the Union Power Station. See Note 2 to the financial statements for further discussion.
The volume/weather variance is primarily due to the effect of less favorable weather on residential sales, partially offset by an increase in industrial usage and an increase in volume during the unbilled period. The increase in industrial usage is primarily due to increased demand from new customers and expansion projects, primarily in the chemicals industry.
The Louisiana Act 55 financing savings obligation variance results from a regulatory charge for tax savings to be shared with customers per an agreement approved by the LPSC. The tax savings resulted from the 2010-2011 IRS audit settlement on the treatment of the Louisiana Act 55 financing of storm costs for Hurricane Gustav and Hurricane Ike. See Note 3 to the financial statements for additional discussion of the settlement and benefit sharing.
Included in Other is a provision of $23 million recorded in 2016 related to the settlement of the Waterford 3 replacement steam generator prudence review proceeding, offset by a provision of $32 million recorded in 2015 related to the uncertainty at that time associated with the resolution of the Waterford 3 replacement steam generator prudence
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
review proceeding. See Note 2 to the financial statements for a discussion of the Waterford 3 replacement steam generator prudence review proceeding.
Other Income Statement Variances
2017 Compared to 2016
Other operation and maintenance expenses increaseddecreased primarily due to:
an increase•a decrease of $17.8$10.2 million in nuclear generation expenses primarily due to a lower scope of work performed in 2020 as compared to 2019, in part as a result of the COVID-19 pandemic;
•a decrease of $9.5 million primarily due to contract costs in 2019 related to initiatives to explore new customer products and services;
•a decrease of $6.8 million in loss provisions;
•higher nuclear laborinsurance refunds of $5.9 million;
•a decrease of $5.8 million in energy efficiency costs including contract labor,due to position the nuclear fleettiming of recovery from customers; and
•a decrease of $4.3 million in non-nuclear generation expenses primarily due to meet its operational goals, partially offset by a lower scope of work performed during plant outages in 2017;
an increase of $9.5 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 20172020 as compared to the prior year;
same period in 2019, partially offset by increases resulting from the J. Wayne Leonard Power Station (formerly St. Charles Power Station) and the Lake Charles Power Station being placed in service.
The decrease was partially offset by:
•an increase of $4.1 million as a result of the amount of transmission costs allocated by MISO. See Note 2 to the financial statements for further information on the recovery of these costs;
an increase of $3.6 million in transmission and distribution expenses due to higher vegetation maintenance costs; and
an increase of $3.2 million in write-offs of customer accounts.
Taxes other than income taxes increased primarily due to increases in ad valorem taxes, state franchise taxes, and payroll taxes. Ad valorem taxes increased primarily due to higher assessments, including the assessment of Arkansas ad valorem taxes on the Union Power Station beginning in 2017. State franchise taxes increased primarily due to a change in the Louisiana franchise tax law which became effective for 2017.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including Power Blocks 3 and 4 of the Union Power Station purchased in March 2016, and the effects of recording in third quarter 2016 final court decisions in the River Bend and Waterford 3 lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $6 million of spent nuclear fuel storage costs previously recorded as depreciation expense. See Note 14 to the financial statements for discussion of the Union Power Station purchase. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.
Other income increased primarily due to an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2017, which includes the St. Charles Power Station project, and higher realized gains in 2017 on the River Bend decommissioning trust fund investments, including portfolio rebalancing to the 30% interest in River Bend formerly owned by Cajun.
Interest expense decreased primarily due to an increase in the allowance for borrowed funds used during construction due to higher construction work in progress in 2017, which includes the St. Charles Power Station project.
2016 Compared to 2015
Nuclear refueling outage expenses increased primarily due to the amortization of higher expenses associated with the refueling outages at Waterford 3.
Other operation and maintenance expenses decreased primarily due to:
the $45 million write-off recorded in 2015 to recognize the portion of the assets associated with the Waterford 3 replacement steam generator project no longer probable of recovery. See Note 2 to the financial statements for further discussion of the prudence review proceeding; and
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
a decrease of $35 million in compensation and benefits costs primarily due to a decreasean increase in net periodic pension and other postretirement benefits costs as a result of highera decrease in the discount ratesrate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs.liabilities. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.
costs; and
•several individually insignificant items.
The decrease was partially offset by an increase of $19.9 million in nuclear generation expenses
Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher nuclear labor costs, including contract labor.property assessments.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the J. Wayne Leonard Power BlocksStation (formerly St. Charles Power Station), which was placed into service in May 2019 and the Lake Charles Power Station, which was placed in service in March 2020.
Other regulatory charges (credits) include regulatory charges of $32.6 million recorded in the fourth quarter 2020 due to a settlement with the IRS related to the uncertain tax position regarding Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing because the savings will be shared with customers and $29 million recorded in the first quarter 2020 due to a settlement with the IRS related to the uncertain tax position regarding Hurricane Isaac Louisiana Act 55 financing because the savings will be shared with customers. See Note 3 and 4to the financial statements for further discussion of the Union Power Station purchased in March 2016.settlements and savings obligations.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other income increaseddecreased primarily due to an increaseto:
•a decrease in the allowance for equity funds used during construction due to higher construction work in progress in 2016, which included2019, including the J. Wayne Leonard Power Station (formerly St. Charles Power Station) and the Lake Charles Power Station project,projects; and increased distribution and transmission spending. The increase was also due to higher income
•changes in 2016 on the River Bend and Waterford 3 decommissioning trust fund investments.activity.
Interest expense increased primarily due to:
•the issuances of $300 million of 4.20% Series mortgage bonds and $350 million of 2.90% Series mortgage bonds, each in March 2020;
•the issuance of $525 million of 4.20% Series mortgage bonds in March 2016 of $425 million of 3.25% Series collateral trust mortgage bonds;2019; and
•a decrease in the issuanceallowance for borrowed funds used during construction due to higher construction work in March 2016 of $200 million of 4.95% Series first mortgage bonds;progress in 2019, including the J. Wayne Leonard Power Station (formerly St. Charles Power Station) and Lake Charles Power Station projects.
the issuance in October 2016 of $400 million of 2.40% Series collateral trust mortgage bonds.
The increase was partially offset by the refinancing at lower interest rates of certain first mortgage bonds. See Note 5 to the financial statements for details of long-term debt.
Income Taxes
The effective income tax rates were (54.6%) for 2017, 2016,2020 and 2015 were 60.5%, 12.6%, and 28.6%, respectively.15% for 2019. The difference in the effective income tax rate of 60.5% for 2017 versus the federal statutory rate of 35%21% for 20172020 was primarily due to the enactmentcompletion of the Tax Cuts and Jobs Act, signed by President Trump in December 2017, which changed2014-2015 IRS audit effectively settling the federal corporate income tax rate from 35% to 21% effective in 2018. See Note 3 to the financial statementspositions for further discussion of the effects of the Tax Cuts and Jobs Act.those years. The difference in the effective income tax rate of 12.6% for 2016 versus the federal statutory rate of 35%21% for 20162019 was primarily due to the reversalamortization of excess accumulated deferred income taxes. See Notes 2 and 3 to the financial statements for a portiondiscussion of the provision for uncertain tax positions as a result ofeffects and regulatory activity regarding the settlement of the 2010-2011 IRS audit in the second quarter 2016Tax Cuts and book and tax differences related to the non-taxable income distributions earned on preferred membership interests, partially offset by state income taxes.Jobs Act. See Note 3 to the financial statements for a reconciliation of the federal statutory raterates of 35%21% to the effective income tax rates.
Income Tax Legislation2019 Compared to 2018
See the “Income Tax LegislationMANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” sectionin Item 7 of Entergy Corporation and Subsidiaries Management’s Financial Discussion and AnalysisLouisiana’s Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 21, 2020, for discussion of the Tax Cuts and Jobs Act, the federal income tax legislation enacted in December 2017. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 results of operations for 2019 compared to 2018.
Liquidity and financial position, the provisions of the Act, and the uncertainties associated with accountingCapital Resources
Cash Flow
Cash flows for the Act,years ended December 31, 2020, 2019, and Note 2 to the financial statements discusses proceedings commenced or other responses by Entergy’s regulators to the Act.2018 were as follows:
| | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 |
| (In Thousands) |
Cash and cash equivalents at beginning of period | $2,006 | | | $43,364 | | | $35,907 | |
| | | | | |
Net cash provided by (used in): | | | | | |
Operating activities | 1,072,986 | | | 1,236,002 | | | 1,395,204 | |
Investing activities | (1,944,671) | | | (1,653,634) | | | (1,878,208) | |
Financing activities | 1,597,699 | | | 376,274 | | | 490,461 | |
Net increase (decrease) in cash and cash equivalents | 726,014 | | | (41,358) | | | 7,457 | |
| | | | | |
Cash and cash equivalents at end of period | $728,020 | | | $2,006 | | | $43,364 | |
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2020 Compared to 2019
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2017, 2016, and 2015 were as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (In Thousands) |
Cash and cash equivalents at beginning of period |
| $213,850 |
| |
| $35,102 |
| |
| $320,516 |
|
| | | | | |
Net cash provided by (used in): | | | |
| | |
|
Operating activities | 1,337,545 |
| | 1,037,912 |
| | 1,155,516 |
|
Investing activities | (1,787,409 | ) | | (1,474,065 | ) | | (994,208 | ) |
Financing activities | 271,921 |
| | 614,901 |
| | (446,722 | ) |
Net increase (decrease) in cash and cash equivalents | (177,943 | ) | | 178,748 |
| | (285,414 | ) |
| | | | | |
Cash and cash equivalents at end of period |
| $35,907 |
| |
| $213,850 |
| |
| $35,102 |
|
Operating Activities
Net cash flow provided by operating activities increased $299.6decreased $163 million in 20172020 primarily due to:
income tax refunds•an increase of $234.2$186.1 million in 2017 comparedstorm spending in 2020, primarily due to income tax paymentsHurricane Laura, Hurricane Delta, and Hurricane Zeta restoration efforts. See “Hurricane Laura, Hurricane Delta, and Hurricane Zeta” above for discussion of $156.6 millionstorm restoration efforts;
•lower collections of receivables from customers, in 2016. Entergy Louisiana received income tax refunds in 2017 and made income tax payments in 2016 in accordance with an intercompany income tax allocation agreement. The income tax refunds in 2017 resulted from the utilization of Entergy Louisiana’s net operating losses. The income tax payments in 2016 resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit, payments for state taxes resulting from the effect of the final settlement of the 2006-2007 IRS audit, and the effect of net operating loss limitations. See Note 3part due to the financial statements for a discussion of the audits;COVID-19 pandemic;
an increase due to •the timing of recovery of fuel and purchased power costs; and
•an increase of $21.5 million in interest payment of $60 million made in March 2016 related to the purchase of a beneficial interest in the Waterford 3 leased assets.paid.
The increasedecrease was partially offset by:
•a refund to customersdecrease in January 2017 of approximately $71 million as a result of the settlement approved by the LPSC related to the Waterford 3 replacement steam generator project. See Note 2 to the financial statements for discussion of the settlement and refund;
an increase of $62.8$43.7 million in spending on nuclear refueling outages;
•the timing of payments to vendors; and
proceeds•income tax refunds of $37.8 million received in August 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for a discussion of the spent nuclear fuel litigation.
Net cash flow provided by operating activities decreased $117.6$14.7 million in 2016 primarily due to:
an increase of $67.52020 compared to $15.3 million in income tax payments in 2016.2019. Entergy Louisiana had income tax paymentsrefunds in 20162020 and 2015 in accordance with intercompany income tax allocation agreements. The income tax payments in 2016 resulted primarily from adjustments associated2019 in accordance with the settlement of the 2010-2011 IRS audit, payments for state taxes resulting from the effect of the final settlement of the 2006-2007 IRS audit, and the effect of net operating loss limitations. The 2015an intercompany tax allocation agreement. Entergy Louisiana had income tax payments resulted primarily from adjustments
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
associated with the settlementa refund of the 2008-2009 IRS audit. See Note 3 to the financial statements foran overpayment on a discussion of theprior year state income tax audits;return.
an increase of $80.7 million in interest paid resulting from an increase in interest expense, including a payment of $60 million made in March 2016 related to the purchase of a beneficial interest in the Waterford 3 leased assets. See Note 10 to the financial statements for a discussion of the purchase of a beneficial interest in the Waterford 3 leased assets;
the timing of collections from customers and payments to vendors; and
a decrease due to the timing of recovery of fuel and purchased power costs in 2016.
The decrease was partially offset by proceeds of $37.8 million received in 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed and a decrease of $30.5 million in spending on nuclear refueling outages in 2016. See Note 8 to the financial statements for a discussion of the spent nuclear fuel litigation.
Investing Activities
Net cash flow used in investing activities increased $313.3$291 million in 20172020 primarily due to:
•an increase of $364.3$709.7 million in fossil-fueled generationstorm spending 2020, primarily due to Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration efforts, See “Hurricane Laura, Hurricane Delta, and Hurricane Zeta” above for discussion of storm restoration efforts;
•the purchase of Washington Parish Energy Center in November 2020 for approximately $222 million. See Note 14 to the financial statements for further discussion of the Washington Parish Energy Center purchase;
•an increase of $16.7 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of Entergy Louisiana’s distribution system, including increased spending on advanced metering infrastructure; and
•money pool activity.
The increase was partially offset by:
•an increase of $302.2 million in net receipts from storm reserve escrow accounts;
•a decrease of $207.8 million in non-nuclear generation construction expenditures due to higher spending in 2019 on the St.Lake Charles Power Station and LakeJ. Wayne Leonard Power Station (formerly St. Charles Power Station projects in 2017;Station) projects;
an increase•a decrease of $148.9$133.1 million in transmission construction expenditures primarily due to a higherlower scope of work performed on various projects in 2017;2020 as compared to 2019;
an increase•a decrease of $144.9$89.5 million in nuclear construction expenditures primarily due to a lower scope of work performed on various nuclear projects in 2020 as compared to 2019; and
•a decrease of $26.1 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material, and service deliveries, and the timing of cash payments during the nuclear fuel cycle;cycle.
proceeds of $57.9 million received in 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation;
an increase of $53.6 million in nuclear construction expenditures primarily due to increased spending on various nuclear projects in 2017;
an increase of $30.4 million in distribution construction expenditures due to increased spending on digital technology improvements within the customer contact centers;
an increase of $19.9 million due to increased spending on advanced metering infrastructure; and
an increase of $12.3 million due to various information technology projects and upgrades in 2017.
The increase was partially offset by:
the purchase of Power Blocks 3 and 4 of the Union Power Station for an aggregate purchase price of approximately $475 million in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase;
money pool activity; and
an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2017.
DecreasesIncreases in Entergy Louisiana’s receivable from the money pool are a sourceuse of cash flow, and Entergy Louisiana’s receivable from the money pool decreasedincreased by $11.3$13.4 million in 20172020 compared to increasingdecreasing by $16.3 $46.8
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
million in 2016.2019. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Net cash flow used in investing activities increased $479.9 million in 2016 primarily due to:
the purchase of Power Blocks 3 and 4 of the Union Power Station for an aggregate purchase price of approximately $475 million in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase;
an increase of $130.7 million in fossil-fueled generation construction expenditures primarily due to spending on the St. Charles Power Station project in 2016;
cash proceeds of $59.6 million received in 2015 from the transfer of Algiers assets to Entergy New Orleans in September 2015. See “State and Local Rate Regulation and Fuel-Cost Recovery- Retail Rates - Electric - Filings with the City Council” below for further discussion of the transfer;
an increase of $52 million in transmission construction expenditures due to a higher scope of work performed in 2016; and
an increase of $20.5 million due to various information technology projects and upgrades in 2016.
The increase was partially offset by:
fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and service deliveries, and the timing of cash payments during the nuclear fuel cycle;
proceeds of $57.9 million received in 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
a decrease of $16.9 million in nuclear construction expenditures primarily due to decreased spending on compliance with NRC post-Fukushima requirements.
Financing Activities
Net cash flow provided by financing activities decreased $343increased $1,221.4 million in 20172020 primarily due to:
•the issuance of $1.1 billion of 0.62% Series mortgage bonds in November 2020;
•the issuance of $350 million of 2.90% Series mortgage bonds and $300 million of 4.20% Series mortgage bonds, each in March 2020;
•the issuance of $300 million of 2.90% Series mortgage bonds and $300 million of 1.60% Series mortgage bonds, each in November 2020; and
•a decrease of $186.5 million in common equity distributions in 2020 primarily due to the net issuance of $325.6 million of long-term debt in 2017 compared to the net issuance of $961.2 million in 2016. upcoming capital expenditures.
The decreaseincrease was partially offset by:
a decrease•the issuance of $194.3$525 million of common equity distributions primarily as a result4.20% Series mortgage bonds in March 2019;
•the repayment in August 2020 of higher construction expenditures$250 million of 3.95% Series mortgage bonds due October 2020;
•the repayment in December 2020 of $200 million of 5.25% Series mortgage bonds due July 2052;
•money pool activity;
•the repayment in December 2020 of $100 million of 4.70% Series mortgage bonds due June 2063; and higher nuclear fuel purchases in 2017; and
•net repayments of long-term borrowings of $39.7$62 million in 2020 on the nuclear fuel company variable interest entities’ credit facilitiesfacilities.
Decreases in 2017Entergy Louisiana’s payable to the money pool are a use of cash flow, and Entergy Louisiana’s payable to the money pool decreased by $82.8 million in 2020 compared to net repayments of $56.6increasing by $82.8 million in 2016.2019.
Entergy Louisiana’s financing activities provided $614.9 million of cash in 2016 compared to using $446.7 million in 2015 primarily due to the following activity:
the net issuance of $961.2 million of long-term debt in 2016 compared to the net retirement of $103.4 million of long-term debt in 2015;
the redemption in September 2015 of $100 million of 6.95% Series and $10 million of 8.25% Series preferred membership interests in connection with the Entergy Louisiana and Entergy Gulf States Louisiana business combination;
net repayments of borrowings of $56.6 million on the nuclear fuel company variable interest entity’s credit facility in 2016 compared to net borrowings of $14.3 million in 2015; and
an increase of $59.5 million in common equity distributions in 2016. Equity distributions were lower in 2015 in anticipation of the purchase of Power Blocks 3 and 4 of the Union Power Station.
See Note 5 to the financial statements for details of long-term debt.
2019 Compared to 2018
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Louisiana’s Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 21, 2020, for discussion of operating, investing, and financing cash flow activities for 2019 compared to 2018.
Capital Structure
Entergy Louisiana’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio for Entergy Louisiana is primarily due to the net issuances of long-term debt in 2020.
| | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
Debt to capital | 54.8 | % | | 53.4 | % |
Effect of excluding securitization bonds | 0.0 | % | | (0.1 | %) |
Debt to capital, excluding securitization bonds (a) | 54.8 | % | | 53.3 | % |
Effect of subtracting cash | (2.1 | %) | | (0.1 | %) |
Net debt to net capital, excluding securitization bonds (a) | 52.7 | % | | 53.2 | % |
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
(a)Calculation excludes the securitization bonds, which are non-recourse to Entergy Louisiana.
Capital Structure
Entergy Louisiana’s capitalization is balanced between equity and debt, as shown in the following table.
|
| | | | | |
| December 31, 2017 | | December 31, 2016 |
Debt to capital | 53.8 | % | | 53.4 | % |
Effect of excluding securitization bonds | (0.3 | %) | | (0.5 | %) |
Debt to capital, excluding securitization bonds (a) | 53.5 | % | | 52.9 | % |
Effect of subtracting cash | (0.1 | %) | | (0.9 | %) |
Net debt to net capital, excluding securitization bonds (a) | 53.4 | % | | 52.0 | % |
| |
(a) | Calculation excludes the securitization bonds, which are non-recourse to Entergy Louisiana. |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Louisiana uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition because the securitization bonds are non-recourse to Entergy Louisiana, as more fully described in Note 5 to the financial statements. Entergy Louisiana also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition because net debt indicates Entergy Louisiana’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Louisiana seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend,distribution, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Louisiana may issue incremental debt or reduce dividends,distributions, or both, to maintain its targeted capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing dividends,distributions, Entergy Louisiana may receive equity contributions to maintain the targetedits capital structure.
Uses of Capital
Entergy Louisiana requires capital resources for:
•construction and other capital investments;
•debt maturities or retirements;
•working capital purposes, including the financing of fuel and purchased power costs; and
•distribution and interest payments.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Louisiana’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| 2021 | | 2022 | | 2023 |
| (In Millions) |
Planned construction and capital investment: | | | | | |
Generation | $365 | | | $460 | | | $785 | |
Transmission | 425 | | | 340 | | | 230 | |
Distribution | 540 | | | 485 | | | 500 | |
Utility Support | 160 | | | 130 | | | 115 | |
Total | $1,490 | | | $1,415 | | | $1,630 | |
In addition to the planned spending in the table above, Entergy Louisiana also expects to pay for $845 million of capital investments in 2021 related to Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration work that have been accrued as of December 31, 2020.
|
| | | | | | | | | | | |
| 2018 | | 2019 | | 2020 |
| (In Millions) |
Planned construction and capital investment: | | | | | |
Generation |
| $875 |
| |
| $530 |
| |
| $330 |
|
Transmission | 465 |
| | 350 |
| | 285 |
|
Distribution | 325 |
| | 395 |
| | 365 |
|
Utility Support | 165 |
| | 110 |
| | 135 |
|
Total |
| $1,830 |
| |
| $1,385 |
| |
| $1,115 |
|
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Louisiana’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2022-2023 | | 2024-2025 | | After 2025 | | Total |
| (In Millions) |
Long-term debt (a) | $557 | | | $2,294 | | | $1,495 | | | $9,506 | | | $13,852 | |
Operating leases (b) | $13 | | | $19 | | | $10 | | | $4 | | | $46 | |
Finance leases (b) | $4 | | | $7 | | | $4 | | | $2 | | | $17 | |
Purchase obligations (c) | $687 | | | $1,463 | | | $1,472 | | | $4,838 | | | $8,460 | |
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2019-2020 | | 2021-2022 | | After 2022 | | Total |
| (In Millions) |
Long-term debt (a) |
| $940 |
| |
| $903 |
| |
| $843 |
| |
| $6,785 |
| |
| $9,471 |
|
Operating leases |
| $22 |
| |
| $41 |
| |
| $24 |
| |
| $19 |
| |
| $106 |
|
Purchase obligations (b) |
| $633 |
| |
| $1,420 |
| |
| $1,366 |
| |
| $7,125 |
| |
| $10,544 |
|
| |
(a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
(b) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Louisiana, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Vidalia purchased power agreement and the Unit Power Sales Agreement, both of which are discussed in Note 8 to the financial statements. |
(a)Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.
(b)Lease obligations are discussed in Note 10 to the financial statements.
(c)Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Louisiana, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Vidalia purchased power agreement and the Unit Power Sales Agreement, both of which are discussed in Note 8 to the financial statements.
In addition to the contractual obligations given above, Entergy Louisiana currently expects to contribute approximately $71.9$59.9 million to its qualified pension plans and approximately $19$15.6 million to its other postretirement health care and life insurance plans in 2018,2021, although the 20182021 required pension contributions will be known with more certainty when the January 1, 20182021 valuations are completed, which is expected by April 1, 2018.2021. See “Critical Accounting Estimates- Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also, in addition to the contractual obligations, Entergy Louisiana has $926.6 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Louisiana includes specific investments such as the St. Charles Power Station and Lake Charles Power Station, each discussed below; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhancemaintain reliability and improve service to customers, including investment to support advanced metering;meters and related investments; resource planning, including potential generation and renewables projects; system improvements; investments in River Bend and Waterford 3; software and security; and other investments. Entergy’s Utility supply plan initiative will continue to seek to transform its generation portfolio with new or repowered generation resources. Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above. The estimatedEstimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements,
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Louisiana pays distributions from its earnings at a percentage determined monthly.
St. Charles Power Station
In August 2015, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by the construction of the St. Charles Power Station, a nominal 980 megawatt combined-cycle generating unit, on land adjacent to the existing Little Gypsy plant in St. Charles Parish, Louisiana. It is currently estimated to cost $869 million to construct, including transmission interconnection and other related costs. The LPSC issued an order approving certification of St. Charles Power Station in December 2016. Construction is in progress and commercial operation is estimated to occur by mid-2019.
Lake Charles Power Station
In November 2016, Entergy Louisiana filed an application with the LPSC seeking certification that the public convenience and necessity would be served by the construction of the Lake Charles Power Station, a nominal 994 megawatt combined-cycle generating unit in Westlake, Louisiana, on land adjacent to the existing Nelson plant in Calcasieu Parish. The current estimated cost of the Lake Charles Power Station is $872 million, including estimated costs of transmission interconnection and other related costs. In May 2017 the parties to the proceeding agreed to an uncontested stipulation finding that construction of the Lake Charles Power Station is in the public interest and authorizing an in-service rate recovery plan. In July 2017 the LPSC issued an order unanimously approving the stipulation and approved certification of the unit. Construction is in progress and commercial operation is expected to occur by mid-2020.
Washington Parish Energy Center
In April 2017, Entergy Louisiana signed a purchase and sale agreement with a subsidiary of Calpine Corporation for the acquisition of a peaking plant. Calpine will construct the plant, which will consist of two natural gas-fired combustion turbine units with a total nominal capacity of approximately 361 MW. The plant, named the Washington Parish Energy Center, will be located in Bogalusa, Louisiana and, subject to permits and approvals, is expected to be completed in 2021. Subject to regulatory approvals, Entergy Louisiana will purchase the plant once it is complete for an estimated total investment of approximately $261 million, including transmission and other related costs. In May 2017, Entergy Louisiana filed an application with the LPSC seeking certification of the plant. A procedural schedule has been established, with the deadlines recently extended and the hearing continued from March 2018 until June 2018 in order to allow the parties an opportunity to reach settlement.
Advanced Metering Infrastructure (AMI)
In November 2016, Entergy Louisiana filed an application seeking a finding from the LPSC that Entergy Louisiana’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy Louisiana proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Louisiana’s modernized power grid. The filing included an estimate of implementation costs for AMI of $330 million. The filing identified a number of quantified and unquantified benefits, and Entergy Louisiana provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $607 million. Entergy Louisiana also sought to continue to include in rate base the remaining book value, approximately $92 million at December 31, 2015, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy Louisiana proposed a 15-year useful life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. The communications network deployment
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
is expected to begin by late-2018, after the necessary information technology infrastructure is in place. Entergy Louisiana proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022. The parties reached an uncontested stipulation permitting implementation of Entergy Louisiana’s proposed AMI system, with modifications to the proposed customer charge. In July 2017 the LPSC approved the stipulation. Entergy Louisiana expects to recover the undepreciated balance of its existing meters through a regulatory asset at current depreciation rates.
Sources of Capital
Entergy Louisiana’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•storm reserve escrow accounts;
•debt or preferred membership interest issuances;issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Entergy Louisiana may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest rates are favorable.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
All debt and common and preferred membership interest issuances by Entergy Louisiana require prior regulatory approval. Preferred membership interest and debtDebt issuances are also subject to issuance tests set forth in its bond indentures and other agreements. Entergy Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Louisiana’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| | | | | | | | | | | | | | | | | | | | |
2020 | | 2019 | | 2018 | | 2017 |
(In Thousands) |
$13,426 | | ($82,826) | | $46,843 | | $11,173 |
|
| | | | | | |
2017 | | 2016 | | 2015 | | 2014 |
(In Thousands) |
$11,173 | | $22,503 | | $6,154 | | $2,815 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Louisiana has a credit facility in the amount of $350 million scheduled to expire in August 2022.September 2024. The credit facility allows Entergy Louisiana to issueincludes fronting commitments for the issuance of letters of credit against $15 million of the borrowing capacity of the facility. As of December 31, 2017,2020, there were no cash borrowings and a $9.1 million letterno letters of credit outstanding under the credit facility. In addition, Entergy Louisiana is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2017, a $29.72020, $2.2 million letterin letters of credit waswere outstanding under Entergy Louisiana’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
The Entergy Louisiana nuclear fuel company variable interest entities have two separate credit facilities, oneeach in the amount of $105 million and one in the amount of $85 million, both scheduled to expire in May 2019.September 2022. As of December 31, 2017, $65.72020, $18.9 million of loans were outstanding under the credit facility for the Entergy Louisiana River Bend nuclear fuel company variable interest entity. As of December 31, 2017, $43.5 million in letters of credit to support a like amount of commercial paper issued and $36.42020, $39.3 million in loans were outstanding under the Entergy Louisiana Waterford nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for additional discussion of the nuclear fuel company variable interest entity credit facilities.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Louisiana obtained authorizations from the FERC through October 2019July 2022 for the following:
•short-term borrowings not to exceed an aggregate amount of $450 million at any time outstanding;
•long-term borrowings and security issuances; and
long-term •borrowings by its nuclear fuel company variable interest entities.
See Note 4 to the financial statements for further discussion of Entergy Louisiana’s short-term borrowing limits.
Hurricane Isaac
In June 2014 the LPSC voted to approve a series of orders which (i) quantified $290.8 million of Hurricane Isaac system restoration costs as prudently incurred; (ii) determined $290 million as the level of storm reserves to be re-established; (iii) authorized Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs; and (iv) granted other requested relief associated with storm reserves and Act 55 financing of Hurricane Isaac system restoration costs. Entergy Louisiana committed to pass on to customers a minimum of $30.8 million of customer benefits through annual customer credits of approximately $6.2 million for five years. Approvals for the Act 55 financings were obtained from the Louisiana Utilities Restoration Corporation and the Louisiana State Bond Commission. See Note 2 to the financial statements for a discussion of the August 2014 issuance of bonds under Act 55 of the Louisiana Legislature.
Little Gypsy Repowering ProjectRetail Rates - Gas
In accordance with the settlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of the upper end of the earnings band as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2007, 2015.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.
Other
In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and the second is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the LPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax obligation at the parent level of a consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020.
Entergy Mississippi
Fuel Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.
To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
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Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.
Formula Rate Plan
In August 2012 the MPSC opened inquiries to review whether the current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan was still appropriate or could be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan proceeding. In March 2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans. The docket remains open.
Entergy New Orleans
Fuel Recovery
Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.
Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of its natural gas hedging program consistent with the City Council’s stated policy objectives. The program uses financial instruments to hedge exposure to volatility in the wholesale price of natural gas purchased to serve Entergy New Orleans gas customers. Entergy New Orleans hedges up to 25% of actual gas sales made during the winter months.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy New Orleans’s efforts to recover storm-related costs.
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Energy Efficiency Programs
A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. The rate settlement provided an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provided a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. In January 2015 the City Council approved funding for the Energy Smart program from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In April 2017 the City Council approved an implementation plan for the Energy Smart program from April 2017 through December 2019. The City Council directed that the $11.8 million balance reported for Energy Smart funds be used to continue funding the program for Entergy New Orleans’s legacy customers and that the Energy Smart Algiers program continue to be funded through the Algiers fuel adjustment clause, until additional customer funding is required for the legacy customers. In September 2017, Entergy New Orleans filed a supplemental plan and proposed several options for an interim cost recovery mechanism necessary to recover program costs during the period between when existing funds directed to Energy Smart programs are depleted and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect. In December 2017 the City Council approved an energy efficiency cost recovery rider as an interim funding mechanism for Energy Smart, subject to verification that no additional funding sources exist. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. See Note 2 to the financial statements for discussion of Entergy New Orleans’s application with the City Council seeking approval of an implementation plan for the Energy Smart program from April 2020 through December 2022.
Entergy Texas
Fuel Recovery
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included in base rates. Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. The PUCT fuel cost proceedings are discussed in Note 2 to the financial statements.
At the PUCT’s April 2013 open meeting, the PUCT Commissioners discussed their view that a purchased power capacity rider was good public policy. The PUCT issued an order in May 2013 adopting the rule allowing for a purchased power capacity rider, subject to an offsetting adjustment for load growth. The rule, as adopted, also includes a process for obtaining pre-approval by the PUCT of purchased power agreements. Entergy Texas has not exercised the option to recover its capacity costs under the new rider mechanism, but will continue to evaluate the benefits of utilizing the new rider to recover future capacity costs.
Electric Industry Restructuring
In June 2009, a law was enacted in Texas that required Entergy Texas to cease all activities relating to Entergy Texas’s transition to competition. The law allows Entergy Texas to remain a part of the SERC Reliability Corporation (SERC) Region, although it does not prevent Entergy Texas from joining another power region. The law provides that proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding
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exist. Under the law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT’s certification of Entergy Texas’s power region.
The law also contains provisions that allow Entergy Texas to take advantage of a cost recovery mechanism that permits annual filings for the recovery of reasonable and necessary expenditures for transmission infrastructure improvement and changes in wholesale transmission charges. This mechanism was previously available to other non-ERCOT Texas utility companies, but not to Entergy Texas.
The law further amended already existing law that had required Entergy Texas to propose for PUCT approval a tariff to allow eligible customers the ability to contract for competitive generation. The amending language in the law provides, among other things, that: 1) the tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers who choose not to participate in the tariff; 2) Entergy Texas shall “purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer;” and 3) Entergy Texas shall provide and price transmission service and ancillary services under that tariff at a rate that is unbundled from its cost of service. The law directs that the PUCT may not issue an order on the tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction.
The PUCT determined that unrecovered costs that may be recovered through the rider consist only of those costs necessary to implement and administer the competitive generation program and do not include lost revenues or embedded generation costs. The amount of customer load that may be included in the competitive generation service program is limited to 115 MW.
In September 2011 the PUCT adopted a proposed rule implementing a distribution cost recovery factor to recover capital and capital-related costs related to distribution infrastructure. The distribution cost recovery factor permits utilities once per year to implement an increase or decrease in rates above or below amounts reflected in base rates to reflect depreciation expense, federal income tax and other taxes, and return on investment. The distribution cost recovery factor rider may be changed a maximum of four times between base rate cases.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery factor rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas franchises are considered to be contracts and, therefore, are terminable pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Louisiana announced that it intendedholds non-exclusive franchises to pursueprovide electric service in approximately 175 incorporated municipalities and in the solid fuel repoweringunincorporated areas of a 538 MW unit at its Little Gypsy plant. In March 2009 the LPSC voted in favorapproximately 59 parishes of a motion directingLouisiana. Entergy Louisiana holds non-exclusive franchises to temporarily suspendprovide natural gas service to customers in the repowering projectCity of Baton Rouge and based upon an analysisin East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.
Entergy Mississippi has received from the MPSC certificates of the project’s economic viability,public convenience and necessity to make a recommendation regarding whetherprovide electric service to proceed with the project. This action was based uponareas within 45 counties, including a number of factors includingmunicipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
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Entergy New Orleans provides electric and gas service in the recent declineCity of New Orleans pursuant to indeterminate permits set forth in naturalcity ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas prices,utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas, and holds non-exclusive franchises to provide electric service in approximately 68 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire over the period 2020-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
Property and Other Generation Resources
Owned Generating Stations
The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2020, is indicated below:
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| | Owned and Leased Capability MW(a) |
Company | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
Entergy Arkansas | | 5,175 | | | 2,091 | | | 1,817 | | | 1,194 | | | 73 | | | — | |
Entergy Louisiana | | 11,317 | | | 8,827 | | | 2,144 | | | 346 | | | — | | | — | |
Entergy Mississippi | | 3,347 | | | 2,929 | | | — | | | 416 | | | — | | | 2 | |
Entergy New Orleans | | 665 | | | 638 | | | — | | | — | | | — | | | 27 | |
Entergy Texas | | 2,260 | | | 2,005 | | | — | | | 255 | | | — | | | — | |
System Energy | | 1,256 | | | — | | | 1,256 | | | — | | | — | | | — | |
Total | | 24,020 | | | 16,490 | | | 5,217 | | | 2,211 | | | 73 | | | 29 | |
(a)“Owned and Leased Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.
Summer peak load for the Utility has averaged 21,591 MW over the previous decade.
The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 8,801 MW of new long-term resources and the deactivation of about 4,664 MW of legacy generation. As MISO market participants, the Utility operating companies also participate in MISO’s Day Ahead and Real Time Energy and Ancillary Services markets to economically dispatch generation and purchase energy to serve customers reliably and at the lowest reasonable cost.
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Other Generation Resources
RFP Procurements
The Utility operating companies from time to time issue requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies. The RFPs issued by the Utility operating companies have sought resources needed to meet near-term MISO reliability requirements as well as environmental concerns,long-term requirements through a broad range of wholesale power products, including limited-term (1 to 3 years) and long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
•Entergy Louisiana’s construction of the unknown costs980 MW, combined-cycle, gas turbine J. Wayne Leonard Power Station (previously referred to as the St. Charles generating facility) at its existing Little Gypsy electric generating station. The facility began commercial operation in May 2019;
•Entergy Texas’s construction of carbon legislationthe 993 MW, combined-cycle, gas turbine Montgomery County Power Station at its existing Lewis Creek electric generating station. The facility began commercial operation in January 2021;
•Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station site. The facility began commercial operation in March 2020;
•In October 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and changesthe facility is scheduled to be in service by early 2022;
•In March 2019, Entergy Arkansas signed an agreement for the capital/financial markets. purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020 and the facility is scheduled to be in service by the end of 2021;
•Entergy New Orleans received regulatory approval in August 2019 to construct the New Orleans Solar Station (a 20 MW self-build solar project) located at the NASA Michoud Facility.The facility was placed in service in December 2020;
•In April 2009,June 2020, Entergy Louisiana compliedArkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Lee County, Arkansas. In October 2020, Entergy Arkansas filed a petition with the LPSC’s directive and recommendedAPSC seeking a finding that the project be suspended for an extended period of time of three years or more. In May 2009 the LPSC issued an order declaring that Entergy Louisiana’s decision to place the Little Gypsy project into a longer-term suspension of three years or moretransaction is in the public interest and prudent.requesting all necessary approvals. Closing is expected to occur by the end of 2022;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2023; and
•In June 2020, Entergy Texas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 1,200 acres in Liberty County near Dayton, Texas.In September 2020, Entergy Texas filed a petition with the PUCT seeking a finding that the transaction is in the public interest and requesting all necessary approvals.Closing is expected to occur by the end of 2023.
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The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:
•River Bend’s 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
•Entergy Arkansas’s wholesale base load capacity life-of-unit PPAs executed in 2003 totaling approximately 220 MW between Entergy Arkansas and Entergy Louisiana (110 MW) and between Entergy Arkansas and Entergy New Orleans (110 MW) related to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which had not been included in Entergy Arkansas’s retail rates);
•In May 2011, Entergy Texas and Calpine Energy Services, L.P. executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. Entergy Louisiana purchases 50% of the facility’s capacity and energy from Entergy Texas. In July 2014, LS Power purchased the Carville Energy Center and replaced Calpine Energy Services as the counterparty to the agreement;
•In September 2012, Entergy Gulf States Louisiana executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 MW when available, from Rain CII Carbon LLC’s petroleum coke calcining facility in Sulphur, Louisiana. The facility began commercial operation in May 2013. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with the facility;
•In March 2013, Entergy Gulf States Louisiana executed a 20-year agreement for 8.5 MW from Agrilectric Power Partners, LP’s refurbished rice hull-fueled electric generation facility located in Lake Charles, Louisiana. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with Agrilectric;
•In September 2013, Entergy Louisiana executed a 10-year agreement with TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, to purchase approximately 3 MW from its landfill gas-fueled power generation facility located in Cleveland, Texas;
•Entergy Mississippi’s cost-based purchase, beginning in January 2013, of 90 MW from Entergy Arkansas’s share of Grand Gulf (only 60 MW of this PPA came through the RFP process). Cost recovery for the 90 MW was approved by the MPSC in January 2013;
•In April 2015, Entergy Arkansas and Stuttgart Solar, LLC executed a 20-year agreement for 81 MW from a solar photovoltaic electric generation facility located near Stuttgart, Arkansas. The APSC approved the project and deliveries pursuant to that agreement commenced in June 2018;
•In November 2016, Entergy Louisiana and LS Power executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. The transaction received regulatory approval and will begin in June 2022;
•In November 2016, Entergy Louisiana and Occidental Chemical Corporation executed a 10-year agreement for 500 MW from the Taft Cogeneration facility located in Hahnville, Louisiana. The transaction received regulatory approval and began in June 2018;
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
•In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021;
•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a five-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
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•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021; and
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a solar photovoltaic electric generating facility located in Polk County, Texas.The PPA is expected to start when the facility reaches commercial operation in 2023.
In April 2020, Entergy Services, on behalf of Entergy Texas, issued an RFP for combined-cycle gas turbine capacity and energy resources. The RFP was seeking up to 1,000 MW - 1,200 MW of capacity, capacity-related benefits, energy, other electric products, and environmental attributes, if any, from a single generation resource located in the “Eastern Region” of Entergy Texas’s service area. In December 2020, Entergy Texas posted notice that it has elected to proceed with the self-build alternative, Orange County Power Station. The self-build alternative will be conditioned on receipt of required internal and regulatory approvals.
In June 2020, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic resources. The RFP was seeking 300 MW of energy, capacity, capacity-related benefits, other electric products, and environmental attributes from eligible new-build solar photovoltaic generation resources. In December 2020, Entergy Louisiana concluded evaluations of the RFP. Three proposals have been placed on the primary selection list and two proposals have been placed on the secondary selection list. Negotiations are currently in progress.
In January 2021, Entergy Texas provided notice that it intends to issue an RFP for solar generation resources. The RFP is seeking a minimum of 200 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Texas customers.
Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process, including Entergy Mississippi’s January 2006 acquisition of the 480 MW, combined-cycle, gas-fired Attala power plant; Entergy Gulf States Louisiana’s March 2008 acquisition of the 322 MW, simple-cycle, gas-fired Calcasieu Generating Facility; Entergy Louisiana’s April 2011 acquisition of the 580 MW, combined-cycle, gas-fired Acadia Energy Center Unit 2; Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) March 2016 acquisitions of the 1,980 MW (summer rating), natural gas-fired, combined-cycle gas turbine Union Power Station power blocks, each rated at 495 MW (summer rating); and Entergy Mississippi’s October 2009,2019 acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The Utility operating companies have also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.
The Washington Parish Energy Center is a 361 MW natural gas-fired peaking power plant approximately 60 miles north of New Orleans on a site Entergy Louisiana purchased from Calpine in 2019. In May 2018, Entergy Louisiana received LPSC approval of its certification application for this simple-cycle power plant to be developed pursuant to an agreement between Calpine and Entergy Louisiana. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020.
The Hardin County Peaking Facility is an existing 147 MW simple-cycle gas-fired peaking power plant in Kountze, Texas, owned by East Texas Electric Cooperative. Entergy Texas is currently seeking regulatory certification to move forward with the purchase of the facility. The facility has been in operation since January 2010.
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Power Through Program
In December 2020, Entergy Texas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation that is to be installed at commercial and industrial customer premises. If approved, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.”
Interconnections
The Utility operating companies’ generating units are interconnected to a transmission system operating at various voltages up to 500 kV. These generating units consist of steam-electric production facilities, combustion-turbine generators, pressurized and boiling water nuclear reactors, and inverter-based technologies operating in the MISO energy and ancillary services market. Entergy’s Utility operating companies are MISO market participants and are interconnected with many neighboring utilities. MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. As a Regional Transmission Organization, MISO assures consumers of unbiased regional grid management and open access to the transmission facilities under MISO’s functional supervision. In addition, the Utility operating companies are members of SERC Reliability Corporation (SERC). SERC is a nonprofit corporation responsible for promoting and improving the reliability, adequacy, and critical infrastructure of the bulk power supply systems in all or portions of 16 central and southeastern states.SERC serves as a regional entity with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing Bulk Electric System reliability standards within the SERC Region.
Gas Property
As of December 31, 2020, Entergy New Orleans distributed and transported natural gas for distribution within New Orleans, Louisiana, through approximately 2,600 miles of gas pipeline. As of December 31, 2020, the gas properties of Entergy Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Louisiana’s financial position.
Title
The Utility operating companies’ generating stations are generally located on properties owned in fee simple. Most of the substations and transmission and distribution lines are constructed on private property or public rights-of-way pursuant to easements, servitudes, or appropriate franchises. Some substation properties are owned in fee simple. The Utility operating companies generally have the right of eminent domain, whereby they may perfect title to, or secure easements or servitudes on, private property for their utility operations.
Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are subject to the liens of mortgages securing bonds issued by those companies. The Lewis Creek generating station of Entergy Texas was acquired by merger with a subsidiary of Entergy Texas and is currently not subject to the lien of the Entergy Texas indenture.
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Fuel Supply
The sources of generation and average fuel cost per kWh for the Utility operating companies and System Energy for the years 2018-2020 were:
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| | Natural Gas | | Nuclear | | Coal | | Purchased Power | | MISO Purchases |
Year | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh |
2020 | | 47 | | | 1.92 | | | 29 | | | 0.57 | | | 3 | | | 2.54 | | | 8 | | | 4.36 | | | 13 | | | 2.48 | |
2019 | | 40 | | | 2.33 | | | 28 | | | 0.73 | | | 6 | | | 2.31 | | | 8 | | | 4.86 | | | 18 | | | 2.71 | |
2018 | | 39 | | | 2.84 | | | 27 | | | 0.84 | | | 9 | | | 2.24 | | | 8 | | | 5.23 | | | 17 | | | 3.71 | |
Actual 2020 and projected 2021 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:
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| Natural Gas | | Nuclear | | Coal | | Purchased Power (d) | | MISO Purchases (e) |
| 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 |
Entergy Arkansas (a) | 24 | % | | 35 | % | | 60 | % | | 51 | % | | 10 | % | | 13 | % | | 1 | % | | 1 | % | | 5 | % | | — | |
Entergy Louisiana | 51 | % | | 59 | % | | 26 | % | | 27 | % | | 1 | % | | 2 | % | | 9 | % | | 12 | % | | 13 | % | | — | |
Entergy Mississippi (b) | 73 | % | | 69 | % | | 14 | % | | 22 | % | | 4 | % | | 9 | % | | — | | | — | | | 9 | % | | — | |
Entergy New Orleans (b) | 55 | % | | 56 | % | | 33 | % | | 40 | % | | 1 | % | | 2 | % | | 2 | % | | 2 | % | | 9 | % | | — | |
Entergy Texas | 39 | % | | 60 | % | | 11 | % | | 13 | % | | 2 | % | | 6 | % | | 23 | % | | 21 | % | | 25 | % | | — | |
System Energy (c) | — | | | — | | | 100 | % | | 100 | % | | — | | | — | | | — | | | — | | | — | | | — | |
Utility (a) (b) | 47 | % | | 55 | % | | 29 | % | | 31 | % | | 3 | % | | 6 | % | | 8 | % | | 8 | % | | 13 | % | | — | |
(a)Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2020 and is expected to provide less than 1% of its generation in 2021.
(b)Solar power provided less than 1% of Entergy Mississippi’s and Entergy New Orleans's generation in 2020 and is expected to provide less than 1% of each of Entergy Mississippi’s and Entergy New Orleans's generation in 2021.
(c)Capacity and energy from System Energy’s interest in Grand Gulf is allocated as follows under the Unit Power Sales Agreement: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%. Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.
(d)Excludes MISO purchases.
(e)In December 2013, Entergy integrated its transmission system into the MISO RTO. Entergy offers all of its generation into the MISO energy market on a day-ahead and real-time basis and bids for power in the MISO energy market to serve the demand of its customers, with MISO making dispatch decisions. The MISO purchases metric provided for 2020 is not projected for 2021.
Some of the Utility’s gas-fired plants are also capable of using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in 2021, it is possible that various operational events including weather or pipeline maintenance may require the use of fuel oil.
Natural Gas
The Utility operating companies have long-term firm and short-term interruptible gas contracts for both supply and transportation. Over 50% of the Utility operating companies’ power plants maintain some level of long-
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term firm transportation. Short-term contracts and spot-market purchases satisfy additional gas requirements. Entergy Texas owns a gas storage facility that provides reliable and flexible natural gas service to certain generating stations.
Many factors, including wellhead deliverability, storage, pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
Coal
Entergy Arkansas has committed to seven one- to three-year contracts that will supply approximately 85% of the total coal supply needs in 2021. These contracts are staggered in term so that not all contracts have to be renewed the same year. The remaining 15% of total coal requirements will be satisfied by contracts with a term of less than one year. Based on continued improved Powder River Basin (PRB) coal deliveries by rail and the high cost of alternate sources and modes of transportation, no alternative coal consumption is expected at Entergy Arkansas during 2021. Coal will be transported to Arkansas via an existing transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2021.
Entergy Louisiana has committed to five one- to three-year contracts that will supply approximately 90% of Nelson Unit 6 coal needs in 2021. If needed, additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as for Entergy Arkansas’s plants, no alternative coal consumption is expected at Nelson Unit 6 during 2021. Coal will be transported to Nelson primarily via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2021.
For the year 2020, coal transportation delivery rates to Entergy Arkansas-and Entergy Louisiana-operated coal-fired units were adequate to meet supply needs and obligations, and it is expected that delivery times in 2021 will continue to be consistent. Both Entergy Arkansas and Entergy Louisiana control a sufficient number of railcars to satisfy the rail transportation requirement.
The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2021. Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.
Nuclear Fuel
The nuclear fuel cycle consists of the following:
•mining and milling of uranium ore to produce a concentrate;
•conversion of the concentrate to uranium hexafluoride gas;
•enrichment of the uranium hexafluoride gas;
•fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and
•disposal of spent fuel.
The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated
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uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the owner of a nuclear power plant.
Based upon currently planned fuel cycles, the Utility nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through most of 2023. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. There are a number of possible supply alternatives that may be accessed to mitigate any supplier performance failure, including potentially drawing upon Entergy’s inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.
The effects of market price changes may be reduced and deferred by risk management strategies, such as negotiation of floor and ceiling amounts for long-term contracts, buying for inventory or entering into forward physical contracts at fixed prices when Entergy believes it is appropriate and useful. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance reliability of conversion, enrichment, and fabrication services providers. There are fewer of these providers than for uranium. For conversion and enrichment services, like uranium, Entergy diversifies its supply by supplier and country and may take special measures as needed to ensure supply of enriched uranium for the reliable fabrication of nuclear fuel. For fabrication services, each plant is dependent upon the effective performance of the fabricator of that plant’s nuclear fuel, therefore, Entergy provides additional monitoring, inspection, and oversight for the fabrication process to assure reliability and quality.
Entergy Arkansas, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the financial statements of Entergy and the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These credit facilities are subject to periodic renewal, and the notes are issued periodically, typically for terms between three and seven years.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with one interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with CenterPoint Energy Services which guarantees Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The CenterPoint Energy Service gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans also makes interruptible spot market purchases.
Entergy Louisiana purchased natural gas for resale in 2020 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.
Federal Regulation of the Utility
State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.
System Agreement (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Prior to each operating company’s termination of participation in the System Agreement (Entergy Arkansas in December 2013, Entergy Mississippi in November 2015, and Entergy Louisiana, Entergy New Orleans, and Entergy Texas each in August 2016), the Utility operating companies engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which was a rate schedule approved by the FERC. Under the terms of the System Agreement, generating capacity and other power resources were jointly operated by the Utility operating companies that were participating in the System Agreement. The System Agreement provided, among other things, that parties having generating reserves greater than their allocated share of reserves (long companies) would receive payments from those parties having generating reserves that were less than their allocated share of reserves (short companies). Such payments were at amounts sufficient to cover certain of the long companies’ costs for intermediate and peaking oil/gas-fired generation, including operating expenses, fixed charges on debt, dividend requirements on preferred equity, and a fair rate of return on common equity investment. Under the System Agreement, the rates used to compensate long companies were based on costs associated with the long companies’ steam electric generating units fueled by oil or gas and having an annual average heat rate above 10,000 Btu/kWh. In addition, for all energy exchanged among the Utility operating companies under the System Agreement, the companies purchasing exchange energy were required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs.
Although the System Agreement has terminated, certain of the Utility operating companies’ and their retail regulators are pursuing litigation involving the System Agreement at the FERC and in federal courts. The proceedings include challenges to the allocation of costs as defined by the System Agreement and other matters. See Note 2 to the financial statements for discussion of legal proceedings at the FERC and in federal courts involving the System Agreement.
Transmission and MISO Markets
In December 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO did not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities, MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and congestion management and provides schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the markets. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. Each Utility operating company has its own transmission pricing zone and a formula rate template (included as Attachment O to the MISO tariff) used to
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establish transmission rates within MISO. The terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets and the allocation of transmission upgrade costs, are subject to regulation by the FERC.
System Energy and Related Agreements
System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In July 2001 a rate proceeding commenced by System Energy at the FERC in 1995 became final, with the FERC approving a prospective 10.94% return on equity. In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas’s and Entergy Mississippi’s acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC. See Note 2 to the financial statements for discussion of complaints filed with the FERC regarding System Energy’s return on equity.
Unit Power Sales Agreement
The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.
In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf-related costs and recovers the remaining 78% of its share in rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas’s cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans that sell a portion of the output of Entergy Arkansas’s retained share of Grand Gulf to those companies, with the remainder of the retained share being sold to Entergy Mississippi through a separate life-of-resources purchased power agreement. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted rate relief with respect to costs associated with Entergy Louisiana’s share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Entergy Louisiana retains and does not recover from retail ratepayers 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause at 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC’s approval. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of the output of Entergy Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted rate relief for those purchases by the MPSC through its annual unit power cost rate mechanism.
Availability Agreement
The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the financing by System Energy
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of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges.
The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.
System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for its two outstanding series of first mortgage bonds. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.
Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be made directly to the holders of indebtedness that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.
The obligations of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans to make payments under the Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to the FERC for approval with respect to the terms of such sale. No such filing with the FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability Agreement, the jurisdictional portions of the Availability Agreement would be submitted to the FERC for approval.
Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement and, therefore, no payments under the Availability Agreement have ever been required. If Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their Availability Agreement obligations exceed their Unit Power Sales Agreement obligations.
The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors.
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Service Companies
Entergy Services, a limited liability company wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the Utility operating companies, but also provides services to Entergy Wholesale Commodities. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas
Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson Unit 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.
Entergy Texas purchases from Entergy Louisiana pursuant to a life-of-unit purchased power agreement a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend’s nuclear and environmental liabilities that is identical to the share of the plant’s output purchased by Entergy Texas under the purchased power agreement. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements.
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
On October 1, 2015, the businesses formerly conducted by Entergy Louisiana (Old Entergy Louisiana) and Entergy Gulf States Louisiana (Old Entergy Gulf States Louisiana) were combined into a single public utility. In order to effect the business combination, under the Texas Business Organizations Code (TXBOC), Old Entergy Louisiana allocated substantially all of its assets to a new subsidiary, Entergy Louisiana Power, LLC, a Texas limited liability company (New Entergy Louisiana), and New Entergy Louisiana assumed the liabilities of Old Entergy Louisiana, in a transaction regarded as a merger under the TXBOC. Under the TXBOC, Old Entergy Gulf States Louisiana allocated substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States Louisiana assumed the liabilities of Old Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. New Entergy Gulf States Louisiana then merged into New Entergy Louisiana with New Entergy Louisiana surviving the merger. Thereupon, Old Entergy Louisiana changed its name from “Entergy Louisiana, LLC” to “EL Investment Company, LLC” and New Entergy Louisiana changed its name from “Entergy Louisiana Power, LLC” to “Entergy Louisiana, LLC” (Entergy Louisiana). With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Old Entergy Louisiana and Old Entergy Gulf States Louisiana.
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Entergy New Orleans Internal Restructuring
In November 2017, pursuant to the agreement in principle, Entergy New Orleans, Inc. undertook a multi-step restructuring, including the following:
•Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.
•Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans, Inc. allocated substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power assumed substantially all of the liabilities of Entergy New Orleans, Inc. in a transaction regarded as a merger under the TXBOC. Entergy New Orleans, Inc. remained in existence and held the membership interests in Entergy New Orleans Power.
•Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The restructuring was accounted for as a transaction between entities under common control.
Entergy Arkansas Internal Restructuring
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Mississippi Internal Restructuring
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
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•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
Entergy Wholesale Commodities
Entergy Wholesale Commodities includes the ownership, operation, and decommissioning of nuclear power plants, located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities revenues are primarily derived from sales of energy and generation capacity from these plants. Entergy Wholesale Commodities also provides operations and management services, including decommissioning-related services, to nuclear power plants owned by non-affiliated entities in the United States. Entergy Wholesale Commodities also includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers.
See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
Property
Nuclear Generating Stations
Entergy Wholesale Commodities includes the ownership of the following nuclear power plants:
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Power Plant | | Market | | In Service Year | | Acquired | | Location | | Capacity - Reactor Type | | License Expiration Date |
Indian Point 3 (a) | | NYISO | | 1976 | | Nov. 2000 | | Buchanan, NY | | 1,041 MW - Pressurized Water | | 2025 (a) |
Indian Point 2 (a) | | NYISO | | 1974 | | Sept. 2001 | | Buchanan, NY | | 1,028 MW - Pressurized Water | | 2024 (a) |
Palisades (b) | | MISO | | 1971 | | Apr. 2007 | | Covert, MI | | 811 MW - Pressurized Water | | 2031 (b) |
(a)Power operations ceased at the Indian Point 2 plant in April 2020. The fuel was permanently removed from the reactor vessel and placed in the spent fuel pool in May 2020. The Indian Point 3 plant is expected to cease operations on April 30, 2021. Entergy and Holtec jointly filed a license transfer application with the NRC in November 2019, requesting approval for the transfer of the Indian Point plants, along with their nuclear decommissioning trusts and decommissioning liabilities, from Entergy to Holtec. The NRC approved the license transfer application on November 23, 2020.
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(b)The Palisades plant is expected to cease operations on May 31, 2022. There is a contract to sell the plant to Holtec subject to NRC and other regulatory approvals.
See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
Entergy Wholesale Commodities also includes the ownership of two non-operating nuclear facilities, Big Rock Point in Michigan and Indian Point 1 in New York that were acquired when Entergy purchased the Palisades and Indian Point 2 nuclear plants, respectively. These facilities are in various stages of the decommissioning process. Both Big Rock Point and Indian Point 1 are under contract to be sold with their respective plants.
Non-nuclear Generating Stations
Entergy Wholesale Commodities includes the ownership, or interests in joint ventures that own, the following non-nuclear power plants:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Plant | | Location | | Ownership | | Net Owned Capacity (a) | | Type |
Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
RS Cogen; 425 MW (c) | | Lake Charles, LA | | 50% | | 213 MW | | Gas/Steam |
Nelson Unit 6; 550 MW | | Westlake, LA | | 11% | | 60 MW(b) | | Coal |
(a)“Net Owned Capacity” refers to the nameplate rating on the generating unit.
(b)The owned MW capacity is the portion of the plant capacity owned by Entergy Wholesale Commodities. For a complete listing of Entergy’s jointly-owned generating stations, refer to “Jointly-Owned Generating Stations” in Note 1 to the financial statements.
(c)Indirectly owned through an interest in an unconsolidated joint venture. In December 2020, Entergy’s wholly-owned subsidiary with a direct interest in RS Cogen, LLC entered into a membership interest purchase agreement with a subsidiary of the other 50% equity partner to sell its 50% membership interest in the joint venture to the equity partner. The targeted closing date for the transaction is October 2022.
Independent System Operators
The Indian Point plants fall under the authority of the New York Independent System Operator (NYISO). The Palisades plant falls under the authority of the MISO. The primary purpose of NYISO and MISO is to direct the operations of the major generation and transmission facilities in their respective regions; ensure grid reliability; administer and monitor wholesale electricity markets; and plan for their respective region’s energy needs.
Energy and Capacity Sales
As a wholesale generator, Entergy Wholesale Commodities’ core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and also sells energy in the day ahead or spot markets. Entergy Wholesale Commodities also sells unforced capacity, which allows load-serving entities to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Entergy Wholesale Commodities’ forward physical power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Entergy Wholesale Commodities to deliver MWh of energy, make capacity available, or both.See “Market and Credit Risk Sensitive Instruments” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for additional information regarding these contracts.
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As part of the purchase of the Palisades plant in 2007, Entergy executed a 15-year PPA with the seller, Consumers Energy, for 100% of the plant’s output, excluding any future uprates. Under the purchased power agreement, Consumers Energy receives the value of any new environmental credits for the first ten years of the agreement. Palisades and Consumers Energy will share on a 50/50 basis the value of any new environmental credits for years 11 through 15 of the agreement. The environmental credits are defined as benefits from a change in law that causes capability of the plant as of the purchase date to become a tradable attribute (e.g., emission credit, renewable energy credit, environmental credit, “green” credit, etc.) or otherwise to have a market value. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022 and transfer to Holtec thereafter.
Customers
Entergy Wholesale Commodities’ customers for the sale of both energy and capacity from its nuclear plants include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. These customers include Consumers Energy, the company from which Entergy purchased the Palisades plant, and NYISO and MISO. Substantially all the credit exposure associated with the planned energy output under contract for Entergy Wholesale Commodities nuclear plants is with counterparties or their guarantors that have public investment grade credit ratings.
Competition
The NYISO market is highly competitive. Entergy Wholesale Commodities has numerous competitors in New York including generation companies affiliated with regulated utilities, other independent power producers, municipal and co-operative generators, owners of co-generation plants and wholesale power marketers. Entergy Wholesale Commodities is an independent power producer, which means it generates power for sale to third parties at day ahead or spot market prices to the extent that the power is not sold under a fixed price contract. Municipal and co-operative generators also generate power but use most of it to deliver power to their municipal or co-operative power customers. Owners of co-generation plants produce power primarily for their own consumption. Wholesale power marketers do not own generation; rather they buy power from generators or other market participants and resell it to retail providers or other market participants. Competition in the New York power market is affected by, among other factors, the amount of generation and transmission capacity in these markets. MISO does not have a centralized clearing capacity market, but load serving entities do meet most of their capacity needs through bilateral contracts and self-supply with a smaller portion coming through voluntary MISO auctions. Almost all of Palisades’ current output is contracted to Consumers Energy through May 2022. Entergy Wholesale Commodities does not expect to be materially affected by competition in the MISO market in the near term.
Seasonality
Entergy Wholesale Commodities’ revenues and operating income are subject to fluctuations during the year due to seasonal factors, weather conditions, and contract pricing. When outdoor and cooling water temperatures are low, generally during colder months, Entergy Wholesale Commodities nuclear power plants operate more efficiently, and consequently, generate more electricity. Many of Entergy Wholesale Commodities’ contracts provide for shaped pricing over the course of the year. As a result of these factors, Entergy Wholesale Commodities’ revenues are typically higher in the first and third quarters than in the second and fourth quarters.
Fuel Supply
Nuclear Fuel
See “Fuel Supply - Nuclear Fuel” in the Utility portion of Part I, Item 1 for a discussion of the nuclear fuel cycle and markets. Entergy Nuclear Fuels Company, a wholly-owned subsidiary, is responsible for contracts to acquire nuclear materials, except for fuel fabrication, for Entergy Wholesale Commodities nuclear power plants,
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while Entergy Nuclear Operations, Inc. acts as the agent for the purchase of nuclear fuel assembly fabrication services. All contracts for the disposal of spent nuclear fuel are between the DOE and each of the nuclear power plant owners. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment has been adjusted to reflect reduced overall requirements related to the planned permanent shutdowns of the Indian Point 3 and Palisades plants. Fuel procurement for the Entergy Wholesale Commodities segment was primarily limited to the requirements of the Palisades plant’s final refueling in 2020.
Other Business Activities
Entergy Nuclear Power Marketing, LLC (ENPM) was formed in 2005 to centralize the power marketing function for Entergy Wholesale Commodities nuclear plants. Upon its formation, ENPM entered into long-term power purchase agreements with the Entergy Wholesale Commodities subsidiaries that own nuclear power plants (generating subsidiaries). As part of a series of agreements, ENPM agreed to assume and/or otherwise service the existing power purchase agreements that were in effect between the generating subsidiaries and their customers. ENPM’s functions include origination of new energy and capacity transactions and generation scheduling.
Services provided by either Entergy Nuclear, Inc. or other Entergy Wholesale Commodities subsidiaries include engineering, operations and maintenance, fuel procurement, management and supervision, technical support and training, administrative support, and other managerial or technical services required to operate, maintain, and decommission nuclear electric power facilities.
TLG Services, a subsidiary in the Entergy Wholesale Commodities segment, offers decommissioning, engineering, and related services to nuclear power plant owners.
Entergy provides plant operation support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. In 2010 an Entergy subsidiary signed an agreement to extend the management support services to Cooper Nuclear Station by 15 years, through January 2029.
Regulation of Entergy’s Business
Federal Power Act
The Federal Power Act provides the FERC the authority to regulate:
•the transmission and wholesale sale of electric energy in interstate commerce;
•the reliability of the high voltage interstate transmission system through reliability standards;
•sale or acquisition of certain assets;
•securities issuances;
•the licensing of certain hydroelectric projects;
•certain other activities, including accounting policies and practices of electric and gas utilities; and
•changes in control of FERC jurisdictional entities or rate schedules.
The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over the rates charged by Entergy Arkansas and Entergy Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the Utility operating companies. In addition, the FERC regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC regulation of the MISO RTO includes regulation of the design and implementation of the wholesale markets administered by the MISO RTO, as well as the rates, terms, and conditions of open access transmission service over the member systems and the allocation of costs associated with transmission upgrades.
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Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 70 MW of capacity.
State Regulation
Utility
Entergy Arkansas is subject to regulation by the APSC as to the following:
•utility service;
•utility service areas;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery rider;
•terms and conditions of service;
•service standards;
•the acquisition, sale, or lease of any public utility plant or property constituting an operating unit or system;
•certificates of convenience and necessity and certificates of environmental compatibility and public need, as applicable, for generating and transmission facilities;
•avoided cost payments to Qualifying Facilities;
•net energy metering;
•integrated resource planning;
•utility mergers and acquisitions and other changes of control; and
•the issuance and sale of certain securities.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory Authority only if it fails to treat its retail customers in Tennessee in the same manner as its retail customers in Arkansas. Additionally, Entergy Arkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to retail ratemaking or other regulatory jurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment clause and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•certification of certain transmission projects;
•certification of capacity acquisitions, both for owned capacity and purchase power contracts;
•procurement process to acquire over 50 MW;
•audits of the environmental adjustment charge, avoided cost payment to Qualifying Facilities, and energy efficiency rider;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control.
Entergy Mississippi is subject to regulation by the MPSC as to the following:
•utility service;
•utility service areas;
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•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery mechanism;
•terms and conditions of service;
•service standards;
•certification of generating facilities and certain transmission projects;
•avoided cost payments to Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers, acquisitions, and other changes of control.
Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.
Entergy New Orleans is subject to regulation by the City Council as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment charge and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•audit of the environmental adjustment charge;
•certification of the construction or extension of any new plant, equipment, property, or facility that comprises more than 2% of the utility’s rate base;
•integrated resource planning;
•net energy metering;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other changes of control.
To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to the following:
•retail rates and charges, including depreciation rates, and terms and conditions of service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;
•fuel recovery, including reconciliations (audits) of the fuel adjustment charges;
•service standards;
•certification of certain transmission and generation projects;
•utility service areas, including extensions into new areas;
•avoided cost payments to Qualifying Facilities;
•net energy metering; and
•utility mergers, sales/acquisitions/leases of plants over $10 million, sales of greater than 50% voting stock of utilities, and transfers of controlling interest in or operation of utilities.
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Regulation of the Nuclear Power Industry
Atomic Energy Act of 1954 and Energy Reorganization Act of 1974
Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC. Entergy subsidiaries in the Entergy Wholesale Commodities segment are subject to the NRC’s jurisdiction as the owners and operators of Indian Point Energy Center, Palisades, and Big Rock Point.
Nuclear Waste Policy Act of 1982
Spent Nuclear Fuel
Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Entergy’s nuclear owner/licensee subsidiaries have been charged fees for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2020 of $192.0 million for the one-time fee. Entergy accepted assignment of the Pilgrim, FitzPatrick, Indian Point 3, Indian Point 1 and Indian Point 2, Vermont Yankee, Palisades, and Big Rock Point spent fuel disposal contracts with the DOE held by their previous owners. The FitzPatrick spent fuel disposal contract was assigned to Exelon as part of the sale of the plant, completed in March 2017. The Vermont Yankee spent fuel disposal contract was assigned to NorthStar as part of the sale of the plant in January 2019. The Pilgrim spent fuel disposal contract was transferred to Holtec as part of the sale of Entergy Nuclear Generation Company in August 2019. The owners of these plants previous to Entergy have paid or retained liability for the fees for all generation prior to the purchase dates of those plants. The fees payable to the DOE may be adjusted in the future to assure full recovery. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.6 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).
The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing (the DOE filed the license application in June 2008) and, after the license is granted by the NRC, proceed with the repository construction and commencement of receipt of spent fuel. Because the DOE has not begun accepting spent fuel, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts. The DOE continues to delay meeting its obligation. Specific steps were taken to discontinue the Yucca Mountain project, including a motion to the NRC to withdraw the license application with prejudice and the establishment of a commission to develop recommendations for alternative spent fuel storage solutions. In August 2013 the U.S. Court of Appeals for the D.C. Circuit ordered the NRC to continue with the Yucca Mountain license review, but only to the extent of funds previously appropriated by Congress for that purpose and not yet used. Although the NRC completed the safety evaluation report for the license review in 2015, the previously appropriated funds are not sufficient to complete the review, including required hearings. The government has taken no effective action to date related to the recommendations of the appointed spent fuel study commission. Accordingly, large uncertainty remains regarding the time frame under
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which the DOE will begin to accept spent fuel from Entergy’s facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at Entergy’s nuclear sites.
Following the defunding of the Yucca Mountain spent fuel repository program, the National Association of Regulatory Utility Commissioners and others sued the government seeking cessation of collection of the one mill per net kWh generated and sold after April 7, 1983 fee. In November 2013 the D.C. Circuit Court of Appeals ordered the DOE to submit a proposal to Congress to reset the fee to zero until the DOE complies with the Nuclear Waste Policy Act or Congress enacts an alternative waste disposal plan. In January 2014 the DOE submitted the proposal to Congress under protest, and also filed a petition for rehearing with the D.C. Circuit. The petition for rehearing was denied. The zero spent fuel fee went into effect prospectively in May 2014.
As a result of the DOE’s failure to begin disposal of spent nuclear fuel in 1998 pursuant to the Nuclear Waste Policy Act of 1982 and the spent fuel disposal contracts, Entergy’s nuclear owner/licensee subsidiaries have incurred and will continue to incur damages. These subsidiaries have been, and continue to be, involved in litigation to recover the damages caused by the DOE’s delay in performance. See Note 8 to the financial statements for discussion of final judgments recorded by Entergy in 2018, 2019, and 2020 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE. Through 2020, Entergy’s subsidiaries won and collected on judgments against the government totaling approximately $800 million.
Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at Palisades in 1993, at ANO in 1996, at River Bend in 2005, at Grand Gulf in 2006, at Indian Point in 2008, and at Waterford 3 in 2011. These facilities will be expanded as needed.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Louisiana, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, Waterford 3, and Grand Gulf, respectively. In addition, Entergy Louisiana and Entergy Texas are entitled to recover from customers through electric rates the estimated decommissioning costs for the portion of River Bend subject to retail rate regulation. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.
In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In October 2020, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and ANO 2 decommissioning trusts were adequately funded without further collections, and in December 2020, the APSC ordered zero collections for ANO 1 and ANO 2 decommissioning.
In July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend to address previously identified funding shortfalls. This LPSC decision contemplated that the level of decommissioning collections could be revisited should the NRC grant license extensions for both Waterford 3 and River Bend. In July 2019, following the NRC approval of license extensions for Waterford 3 and River Bend, Entergy Louisiana made a filing with the LPSC seeking permission to canceladjust decommissioning and depreciation rates for those plants, including one proposed scenario that would adjust Louisiana-jurisdictional decommissioning collections to zero for both plants (including an offsetting increase in depreciation rates). Because of the Little Gypsy repowering projectongoing public health emergency arising from the COVID-19 pandemic and accompanying economic uncertainty, Entergy Louisiana determined that the relief sought in the filing was no longer appropriate, and in November 2020, filed an unopposed motion to dismiss the proceeding. Following that filing, in a December 2020 order, the LPSC dismissed the proceeding without prejudice.
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In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2018 the PUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning fund was adequate following license renewal.
In September 2016 the NRC issued a 20-year operating license renewal for Grand Gulf. In a 2017 filing at the FERC, System Energy stated that with the renewed operating license, Grand Gulf’s decommissioning trust was sufficiently funded, and proposed, among other things, to cease decommissioning collections for Grand Gulf effective October 1, 2017. The FERC accepted a settlement including the proposed decommissioning revenue requirement by letter order in August 2018.
Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.
In January 2019, Entergy sold 100% of the membership interest in Entergy Nuclear Vermont Yankee to a subsidiary of NorthStar. As a result of the sale, NorthStar assumed ownership of Vermont Yankee and its decommissioning and site restoration trusts, together with complete responsibility for the facility’s decommissioning and site restoration. See Note 9 to the financial statements for further discussion of Vermont Yankee decommissioning costs and see “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the NorthStar transaction.
In August 2019, Entergy sold 100% of the equity interests in Entergy Nuclear Generation Company, LLC to a subsidiary of Holtec International. As a result of the sale, Holtec assumed ownership of Pilgrim and its decommissioning trust, together with complete responsibility for the facility’s decommissioning and site restoration. See Note 14 to the financial statements for further discussion of the sale.
For the Indian Point 3 and FitzPatrick plants purchased in 2000 from NYPA, NYPA retained the decommissioning trust funds and the decommissioning liabilities with the right to require the Entergy subsidiaries to assume each of the decommissioning liabilities provided that it assigns the corresponding decommissioning trust, up to a specified level, to the Entergy subsidiaries. In August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy, which was completed in January 2017. In March 2017, Entergy sold the FitzPatrick plant to Exelon, and as part of the transaction, the FitzPatrick decommissioning trust fund, along with the decommissioning obligation for that plant, was transferred to Exelon. The FitzPatrick spent fuel disposal contract was assigned to Exelon as part of the transaction. See Note 14 to the financial statements for discussion of the FitzPatrick sale.
In March 2020 filings with the NRC were made reporting on decommissioning funding for all of Entergy subsidiaries’ nuclear plants. Those reports showed that decommissioning funding for each of the nuclear plants met the NRC’s financial assurance requirements.
Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 16 to the financial statements.
Price-Anderson Act
The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect the public in the event of a nuclear power plant accident. The costs of this insurance
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are borne by the nuclear power industry. Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025. The Price-Anderson Act limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $137.6 million per reactor (with 97 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, System Energy, or an Entergy Wholesale Commodities company is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units is also purchased. The Price-Anderson Act and insurance applicable to the nuclear programs of Entergy are discussed in more detail in Note 8 to the financial statements.
NRC Reactor Oversight Process
The NRC’s Reactor Oversight Process is a program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response. The NRC evaluates plant performance by analyzing two distinct inputs: inspection findings resulting from the NRC’s inspection program and performance indicators reported by the licensee. The evaluations result in the placement of each plant in one of the NRC’s Reactor Oversight Process Action Matrix columns: “licensee response column,” or Column 1, “regulatory response column,” or Column 2, “degraded cornerstone column,” or Column 3, and “multiple/repetitive degraded cornerstone column,” or Column 4. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject to progressively increasing levels of inspection by the NRC with, in general, progressively increasing levels of associated costs. The nuclear generating plants owned and operated by Entergy’s Utility and Entergy Wholesale Commodities businesses are currently in Column 1, except for Grand Gulf, which is currently in Column 2.
In November 2020 the NRC placed Grand Gulf in Column 2 based on the incidence of three unplanned plant scrams during the second and third quarters of 2020.Two of the scram events related to new turbine control system components that failed, and a third related to a feedwater valve positioner that failed, all of which had been replaced in a refueling outage that ended in May 2020. The NRC plans to conduct a supplemental inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 2. As a consequence of two additional Grand Gulf scrams during the fourth quarter 2020, System Energy expects Grand Gulf to be placed into NRC Column 3 based on plant performance indicators for the four quarters ended December 31, 2020. This will involve an additional supplemental NRC inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 3.
Environmental Regulation
Entergy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy’s businesses are in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted below. Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely estimated. Except to the extent discussed below, at this time compliance with federal, state, and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Entergy’s businesses and is not expected to have a material effect on their competitive position, results of operations, cash flows, or financial position.
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Clean Air Act and Subsequent Amendments
The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a lesser extent, certain operations at nuclear and other facilities. Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements. These programs include:
•New source review and preconstruction permits for new sources of criteria air pollutants, greenhouse gases, and significant modifications to existing facilities;
•Acid rain program for control of sulfur dioxide (SO2) and nitrogen oxides (NOx);
•Nonattainment area programs for control of criteria air pollutants, which could include fee assessments for air pollutant emission sources under Section 185 of the Clean Air Act if attainment is not reached in a timely manner;
•Hazardous air pollutant emissions reduction programs;
•Interstate Air Transport;
•Operating permit programs and enforcement of these and other Clean Air Act programs;
•Regional Haze programs; and
•New and existing source standards for greenhouse gas and other air emissions.
New Source Review (NSR)
Preconstruction permits are required for new facilities and for existing facilities that undergo a modification that results in a significant net emissions increase and is not classified as routine repair, maintenance, or replacement. Units that undergo certain non-routine modifications must obtain a permit modification and may be required to install additional air pollution control technologies. In December 2020 the EPA amended the NSR regulations to clarify when a physical change or change in the method of operation will constitute such a modification. Entergy has an established process for identifying modifications requiring additional permitting approval and is monitoring the regulations and associated guidance provided by the states and the federal government with regard to the determination of routine repair, maintenance, and replacement. Several years ago, however, the EPA implemented an enforcement initiative, aimed primarily at coal plants, to identify modifications that it does not consider routine for which the unit did not obtain a modified permit. Various courts and the EPA have been inconsistent in their judgments regarding modifications that are considered routine and on other legal issues that affect this program.
In February 2011, Entergy received a request from the EPA for several categories of information concerning capital and maintenance projects at the White Bluff and Independence facilities, both located in Arkansas, in order to determine compliance with the Clean Air Act, including NSR requirements and air permits issued by the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ). In August 2011, Entergy’s Nelson facility, located in Louisiana, received a similar request for information from the EPA. In September 2015 an additional request for similar information was received for the White Bluff facility. Entergy responded to all requests. None of these EPA requests for information alleged that the facilities were in violation of law.
In January and February 2018, Entergy Arkansas, Entergy Mississippi, Entergy Power, and other co-owners received 60-day notice of intent to sue letters from the Sierra Club and the National Parks Conservation Association concerning allegations of violations of new source review and permitting provisions of the Clean Air Act at the Independence and White Bluff coal-burning units, respectively. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims as well as other issues facing Entergy Arkansas’s fossil generation plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, is subject to approval by the U.S. District Court for the Eastern District of Arkansas. In October 2019 the District Court requested supplemental briefing on several issues to be resolved prior to addressing the motion to approve the
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settlement; that briefing was completed in May 2020. For further information about the settlement, see “Regional Haze” discussed below.
National Ambient Air Quality Standards
The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide, and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is classified as “marginal,” “moderate,” “serious,” or “severe.” When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.
Ozone Nonattainment
Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area that is not in attainment with the applicable NAAQS for ozone. The ozone nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Both Lewis Creek and the Montgomery County Power Station hold all necessary permits for construction and operation and comply with applicable air quality program regulations. Measures enacted to return the area to ozone attainment could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the ozone NAAQS.
Potential SO2Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. In Entergy’s utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana are designated as nonattainment. In August 2017 the EPA issued a letter indicating that East Baton Rouge and St. Charles parishes would be designated by December 31, 2020, as monitors were installed to determine compliance. In December 2020 the EPA designated East Baton Rouge, St. Charles, St. James, and West Baton Rouge parishes in Louisiana as attainment/unclassifiable, and, in Texas, Jefferson County as attainment/unclassifiable and Orange County as unclassifiable. Challenges to these final designations must be filed within 60 days of publication in the Federal Register. Entergy continues to monitor this situation.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2020 the EPA finalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. The final appropriate and necessary finding does not revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. Entergy will continue to monitor this situation.
Cross-State Air Pollution
In March 2005 the EPA finalized the Clean Air Interstate Rule (CAIR), which was intended to reduce SO2 and NOx emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule required a combination of capital investment to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy.
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Based on several court challenges, CAIR and its subsequent versions, now known as the Cross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions. In September 2016 the EPA finalized the CSAPR Update Rule to address interstate transport for the 2008 ozone NAAQS. Starting in 2017 the final rule requires reductions in summer nitrogen oxides (NOx) emissions. Several states, including Arkansas and Texas, filed a challenge to the Update Rule. In September 2019 the D.C. Circuit upheld the EPA’s underlying approach to the Update Rule, but determined that it was inconsistent with the Clean Air Act because it failed to include deadlines consistent with downwind states’ deadlines for attainment. The court remanded the rule to the EPA for further consideration, but did not vacate so the rule remains in effect pending the EPA’s further review. In October 2020 the EPA issued its proposal intended to address the D.C. Circuit’s remand. The draft rule proposes to finalize interstate transport obligations for 21 states. For nine states, including Arkansas, Mississippi, and Texas, the EPA proposes that additional emission reductions are not necessary. For 12 states, however, including Louisiana, the EPA proposes additional emission reductions through proposed reductions in the number of NOx emission allowances allocated to each state. Entergy, through its various trade associations, filed comments on the proposal and will continue to monitor the rulemaking and its potential impact on its facilities in Louisiana. If the October 2020 proposal is finalized, ozone season NOx emissions may become more expensive in Louisiana.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could result in a requirement to install SO2 and NOx pollution control technology as Best Available Retrofit Control Technology (BART) to continue operating certain of Entergy’s fossil generation units. The rule leaves certain CAVR determinations to the states.
In Arkansas, the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ) prepared a state implementation plan (SIP) for Arkansas facilities to implement its obligations under the CAVR. In April 2012 the EPA finalized a decision addressing the Arkansas Regional Haze SIP, in which it disapproved a large portion of the Arkansas plan, including the emission limits for NOx and SO2 at White Bluff. In April 2015 the EPA published a proposed federal implementation plan (FIP) for Arkansas, taking comment on requiring installation of scrubbers and low NOx burners to continue operating both units at the White Bluff plant and both units at the Independence plant and NOx controls to continue operating the Lake Catherine plant. Entergy filed comments by the deadline in August 2015. Among other comments, including opposition to the EPA’s proposed controls on the Independence units, Entergy proposed to meet more stringent SO2 and NOx limits at both White Bluff and Independence within three years of the effective date of the final FIP and to cease the use of coal at the White Bluff units at a later date.
In September 2016 the EPA published the final Arkansas Regional Haze FIP. In most respects, the EPA finalized its original proposal but shortened the time for compliance for installation of the NOx controls. The FIP required an emission limitation consistent with SO2 scrubbers at both White Bluff and Independence by October 2021 and NOx controls by April 2018. The EPA declined to adopt Entergy’s proposals related to ceasing coal use as an alternative to SO2 scrubbers for White Bluff SO2 BART. In November 2016, Entergy and other interested parties, including the State of Arkansas, filed petitions for administrative reconsideration and stay at the EPA as well as petitions for judicial review in the U.S. Court of Appeals for the Eighth Circuit. The Eighth Circuit granted the stay pending settlement discussions and pending the State’s development of a SIP that, if approved by the EPA, would replace the FIP. The state had proposed its replacement SIP in two parts: Part I considers NOx requirements, and Part II considers SO2 requirements. The EPA approved the Part I NOx SIP in January 2018. The Part I SIP requires that Entergy address NOx impacts on visibility via compliance with the Cross-State Air Pollution Rule ozone-season emission trading program. Arkansas has finalized a Part II SIP which has been approved by the EPA but is currently pending a state court appeal. That appeal has been stayed pending the outcome of a federal court case, which may resolve many of the issues on appeal. The final Part II SIP requires that Entergy achieve SO2 emission reductions via the use of low-sulfur coal at both White Bluff and Independence within three years. The
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Part II SIP also requires that Entergy cease to use coal at White Bluff by December 31, 2028 and notes the current planning assumption that Entergy’s Independence units will cease to use coal by December 31, 2030.
In January and February 2018, Entergy Arkansas, Entergy Mississippi, Entergy Power, and other co-owners received 60-day notice of intent to sue letters from the Sierra Club and the National Parks Conservation Association concerning allegations of violations of new source review and permitting provisions of the Clean Air Act at the Independence and White Bluff coal-burning units, respectively. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims and reducing the risk that Entergy Arkansas, as operator of Independence and White Bluff, might be compelled under the Clean Air Act’s regional haze program to install costly emissions control technologies. Consistent with the terms of the settlement and in many cases also the Part II SIP, Entergy Arkansas, along with co-owners, will begin using only low-sulfur coal at Independence and White Bluff by mid-2021; cease to use coal at White Bluff and Independence by the end of 2028 and 2030, respectively; cease operation of the remaining gas unit at Lake Catherine by the end of 2027; reserve the option to develop new generating sources at each plant site; and commit to install or propose to regulators at least 800 MWs of renewable generation by the end of 2027, with at least half installed or proposed by the end of 2022 (which includes two existing Entergy Arkansas projects) and with all qualifying co-owner projects counting toward satisfaction of the obligation. Under the settlement, the Sierra Club and the National Parks Conservation Association also waive certain potential existing claims under federal and state environmental law with respect to specified generating plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, is subject to approval by the U.S. District Court for the Eastern District of Arkansas. The EPA, which is allowed to comment on such a settlement agreement, has stated that it has no objections to the settlement. In November 2020 the court denied motions by the Arkansas Attorney General and the Arkansas Affordable Energy Coalition to intervene and to stay the proceedings. The proposed intervenors did not appeal the ruling. Still pending before the court is a motion by the plaintiffs to approve the settlement, in support of which Entergy made a filing. The Arkansas Attorney General also filed an application before the APSC in December 2018 seeking projectan investigation into the effects of the settlement. The Arkansas Affordable Energy Coalition filed to support the Arkansas Attorney General’s application, and Entergy Arkansas filed a motion to dismiss it. The application remains pending before the APSC. In October 2019 the District Court requested supplemental briefing on several issues prior to addressing the motion to approve the settlement; that briefing concluded in May 2020.
In Louisiana, Entergy has worked with the Louisiana Department of Environmental Quality (LDEQ) and the EPA to revise the Louisiana SIP for regional haze, which had been disapproved in part in 2012. The LDEQ submitted a revised SIP in February 2017. In May 2017 the EPA proposed to approve a majority of the revisions. In September 2017 the EPA issued a proposed SIP approval for the Nelson plant, requiring an emission limitation consistent with the use of low-sulfur coal, with a compliance date of January 22, 2021. The EPA issued final approval in December 2017. The EPA approval was appealed to the U.S. Court of Appeals for the Fifth Circuit. In October 2019 the Fifth Circuit affirmed the EPA’s SIP approval. A petition for rehearing filed by plaintiffs was denied by the Fifth Circuit. Plaintiffs did not petition for further review by the Supreme Court.
The second planning period (2018-2028) for the regional haze program requires states to examine sources for impacts on visibility and to prepare SIPs by 2021. Entergy received information collection requests from Arkansas and Louisiana requesting an evaluation of technical and economic feasibility of various NOx and SO2 control technologies for Independence, Nelson 6, and Ninemile. Responses to the information requests have been submitted to the respective state agencies.
New and Existing Source Performance Standards for Greenhouse Gas Emissions
In July 2019 the EPA released the Affordable Clean Energy Rule (ACE), which applies only to existing coal-fired electric generating units. The ACE determines that heat rate improvements are the best system of emission reductions and lists six candidate technologies for consideration by states at each coal unit. The rule and associated rulemakings by the EPA replace the Obama administration’s Clean Power Plan, which established
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national emissions performance rates for existing fossil-fuel fired steam electric generating units and combustion turbines. The ACE rule provides states discretion in determining how the best system for emission reductions applies to individual units, including through the consideration of technical feasibility and the remaining useful life of the facility. The ADEQ and the LDEQ have issued information collection requests to Entergy facilities to help the states collect the information needed to determine the best system of emission reductions for each facility. Entergy responded to the requests and will continue to monitor litigation challenging the rule. In January 2021 the U.S. Court of Appeals for the D.C. Circuit vacated ACE. The court held that ACE relied on an incorrect interpretation of the Clean Air Act that the statute expressly forecloses emission reduction approaches, such as emissions trading and generating shifting, that cannot be applied at and to the individual source. The court remanded ACE to the EPA for further consideration and also vacated the repeal of the Clean Power Plan. The vacatur will not be effective until the court issues its mandate which is being held until after disposition of any petitions for rehearing. Entergy is currently reviewing the court’s opinion.
In 2018 the EPA proposed a revision to the new source performance standard on greenhouse gas emissions that primarily impacts new coal units and, therefore, should not impact Entergy. In January 2021 the EPA finalized a pollutant-specific contribution finding for greenhouse gas emissions from new, modified, and reconstructed electric generating units. The rule establishes a three percent threshold for determining when a pollutant significantly contributes to air pollution and reaffirms the EPA’s position that the Clean Air Act Section 111(b) requires the EPA to make pollutant-specific significant contribution findings before promulgation of a new source performance standard. The EPA did not, however, finalize the new source performance standard on greenhouse gas emissions and intends to address the 2018 proposal in a future action.
Potential Legislative, Regulatory, and Judicial Developments
In addition to the specific instances described above, there are a number of legislative and regulatory initiatives concerning air emissions, as well as other media, that are under consideration at the federal, state, and local level. Because of the nature of Entergy’s business, the imposition of any of these initiatives could affect Entergy’s operations. Entergy continues to monitor these initiatives and activities in order to analyze their potential operational and cost recoveryimplications. These initiatives include:
•designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;
•introduction of bills in Congress and development of regulations by the EPA proposing further limits on NOx, SO2, mercury, and carbon dioxide and other air emissions. New legislation or regulations applicable to stationary sources could take the form of market-based cap-and-trade programs, direct requirements for the installation of air emission controls onto air emission sources, or other or combined regulatory programs;
•efforts in Congress or at the EPA to establish a federal carbon dioxide emission tax, control structure, or unit performance standards;
•revisions to the estimates of the Social Cost of Carbon and its use for regulatory impact analysis of federal laws and regulations;
•implementation of the Regional Greenhouse Gas Initiative by several states in the northeastern United States and similar actions in other regions of the United States;
•efforts on the local, state, and federal level to codify renewable portfolio standards, clean energy standards, or a similar mechanism requiring utilities to produce or purchase a certain percentage of their power from defined renewable energy sources or energy sources with lower emissions;
•efforts to develop more stringent state water quality standards, effluent limitations for Entergy’s industry sector, stormwater runoff control regulations, and cooling water intake structure requirements;
•efforts to restrict the previously-approved continued use of oil-filled equipment containing certain levels of polychlorinated biphenyls (PCBs);
•efforts by certain external groups to encourage reporting and disclosure of environmental, social, and governance risk;
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•the listing of additional species as threatened or endangered, the protection of critical habitat for these species, and developments in the legal protection of eagles and migratory birds;
•the regulation of the management, disposal, and beneficial reuse of coal combustion residuals; and
•the regulation of the management and disposal and recycling of equipment associated with renewable and clean energy sources such as used solar panels, wind turbine blades, hydrogen usage, or battery storage.
Entergy continues to support national legislation that would increase planning certainty for electric utilities while addressing carbon dioxide emissions in an economy-wide, responsible, and flexible manner. By virtue of its proportionally large investment in low-emitting generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020. In 2020, Entergy succeeded in achieving its initial climate commitment to reduce carbon dioxide cumulative emissions by 20% from 2000 levels. Total carbon dioxide emissions representing Entergy’s ownership share of power plants and controllable power purchases in the United States were approximately 39.1 million tons in 2020 and 40.7 million tons in 2019. Since its original commitment in 2001, Entergy’s cumulative emissions are approximately 7.6% below its 2020 goal.
Entergy voluntarily conducted a five-year period. climate scenario analysis and published a comprehensive report in March 2019. The report follows the framework and recommendations of the Task Force on Climate-related Disclosures, describing climate-related governance, strategy, risk management, and metrics and targets. Scenario analyses resulted in Entergy developing and publishing a new goal of reducing the Utility’s emission rate by 50 percent from 2000 levels by 2030. In September 2020, Entergy committed to achieving net-zero carbon emissions by 2050, while continuing its commitment to grid reliability and affordability for customers. In December 2020, Entergy published a report regarding this long-term commitment that describes its approach and technology point-of-view. Technology research and development, innovation, and advancement are critical to Entergy’s ability to meet this climate commitment.
Entergy participates in the M.J. Bradley & Associates’ Annual Benchmarking Air Emissions Report, an annual analysis of the 100 largest U.S. electric power producers. The report is available on the M.J. Bradley website. Entergy’s annual greenhouse gas emissions inventory is also third-party verified, and that certification is made available on the American Carbon Registry website. Entergy participates annually in the Dow Jones Sustainability Index and in 2020 was listed on the North American Index. Entergy has been listed on the World or North American Index, or both, for nineteen consecutive years. Entergy also participated in the 2020 CDP and CDP Water evaluations, receiving a ‘B’ for both responses.
Clean Water Act
The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act) provide the statutory basis for the National Pollutant Discharge Elimination System permit program, section 402, and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The Clean Water Act requires virtually all discharges of pollutants to waters of the United States to be permitted. Section 316(b) of the Clean Water Act regulates cooling water intake structures, section 401 of the Clean Water Act requires a water quality certification from the state in support of certain federal actions and approvals, and section 404 regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.
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Steam Electric Effluent Guidelines
The 2015 Steam Electric Effluent Limitations Guidelines (ELG) rule required, among other things, that there be no discharge of bottom ash transport water. In October 2020 the EPA issued its final rule revision on bottom ash transport water allowing the discharge of up to 10% system volume for certain purge waters, including storm events and non-routine operations. The final rule requires compliance as soon as possible beginning October 31, 2021, but no later than December 31, 2025. Several challenges to the final rule have been filed. Additionally, the Fifth Circuit Court of Appeals previously vacated and remanded the provisions of the rule related to legacy wastewater and leachate, which the EPA plans to address in a separate rulemaking. Despite the final rule and pending challenges, Entergy is implementing projects at its White Bluff and Independence plants to convert to zero-discharge systems to comply with the ELG rule and the coal combustion residuals restrictions on impoundments. Additionally, the Nelson Unit 6 facility is implementing operational and maintenance measures to minimize the potential for discharge of bottom ash transport water from the existing bottom ash handling system at the site, and is reviewing the effectiveness of these changes for compliance with the requirements of the October 2020 final rule.
Federal Jurisdiction of Waters of the United States
In February 2019 the EPA published its proposed revised definition of Waters of the United States, which proposes to narrow the scope of Clean Water Act jurisdiction, as compared to a 2015 definition which had been stayed by several federal courts. The final rule was released in January 2020 and effective in June 2020. In October 2019 the EPA repealed the 2015 rule and re-codified the pre-existing regulations. That rule was effective late December 2019. Numerous challenges have been filed against both rules.
Groundwater at Certain Nuclear Sites
The NRC requires nuclear power plants to monitor and report regularly the presence of radioactive material in the environment. Entergy joined other nuclear utilities and the Nuclear Energy Institute in 2006 to develop a voluntary groundwater monitoring and protection program. This initiative began after detection of very low levels of radioactive material, primarily tritium, in groundwater at several plants in the United States. Tritium is a radioactive form of hydrogen that occurs naturally and is also a byproduct of nuclear plant operations. In addition to tritium, other radionuclides have been found in site groundwater at nuclear plants.
As part of the groundwater monitoring and protection program, Entergy has: (1) performed reviews of plant groundwater characteristics (hydrology) and historical records of past events on site that may have potentially impacted groundwater; (2) implemented fleet procedures on how to handle events that could impact groundwater; and (3) installed groundwater monitoring wells and began periodic sampling. The program also includes protocols for notifying local officials if contamination is found. To date, radionuclides such as tritium have been detected at Arkansas Nuclear One, Indian Point, Palisades, Grand Gulf, and River Bend. Each of these sites has installed groundwater monitoring wells and implemented a program for testing groundwater at the sites for the presence of tritium and other radionuclides. Based on current information, the concentrations and locations of radionuclides detected at these plants pose no threat to public health or safety, but each site continues to evaluate the results from its groundwater monitoring program.
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint, and several liability on responsible parties. Many states have adopted programs similar to CERCLA. Entergy subsidiaries in the Utility and Entergy Wholesale Commodities businesses have sent waste materials to various
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disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been or will be sold to decommissioning companies. In addition, environmental laws now regulate certain of Entergy’s operating procedures and maintenance practices that historically were not subject to regulation. Some disposal sites used by Entergy subsidiaries have been the subject of governmental action under CERCLA or similar state programs, resulting in site clean-up activities. Entergy subsidiaries have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs. The affected Entergy subsidiaries have established provisions for the liabilities for such environmental clean-up and restoration activities. Details of potentially material CERCLA and similar state program liabilities are discussed in the “Other Environmental Matters” section below.
Coal Combustion Residuals
In June 2010 the EPA issued a proposed rule on coal combustion residuals (CCRs) that contained two primary regulatory options: (1) regulating CCRs destined for disposal in landfills or received (including stored) in surface impoundments as so-called “special wastes” under the hazardous waste program of Resource Conservation and Recovery Act (RCRA) Subtitle C; or (2) regulating CCRs destined for disposal in landfills or surface impoundments as non-hazardous wastes under Subtitle D of RCRA. Under both options, CCRs that are beneficially reused in certain processes would remain excluded from hazardous waste regulation. In April 2015 the EPA published the final CCR rule with the material being regulated under the second scenario presented above - as non-hazardous wastes regulated under RCRA Subtitle D.
The final regulations create new compliance requirements including modified storage, new notification and reporting practices, product disposal considerations, and CCR unit closure criteria. Entergy believes that on-site disposal options will be available at its facilities, to the extent needed for CCR that cannot be transferred for beneficial reuse. As of December 31, 2020, Entergy has recorded asset retirement obligations related to CCR management of $20.1 million.
In December 2016 the Water Infrastructure Improvements for the Nation Act (WIIN Act) was signed into law, which authorizes states to regulate coal ash rather than leaving primary enforcement to citizen suit actions. States may submit to the EPA proposals for a permit program.
Pursuant to the EPA Rule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area, but has not indicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and detection monitoring will continue as the rule requires. In late-2017, Entergy determined that certain in-ground wastewater treatment system recycle ponds at its White Bluff and Independence facilities require management under the new EPA regulations. Consequently, in order to move away from using the recycle ponds, White Bluff and Independence each have installed a new permanent bottom ash handling system that does not fall under the CCR rule. As of November 2020, both sites are operating the new system and no longer are sending waste to the recycle ponds. Each site has commenced closure of one of its two recycle ponds, with the remaining pond being held in reserve during initial operation of the new bottom ash handling system. Closure of the remaining recycle pond at each site will commence as soon as possible, but no later than April 11, 2021, which is the deadline under the finalized CCR rule to commence closure of any unlined recycle ponds. Any potential requirements for corrective action or operational changes under the new CCR rule continue to be assessed. Notably, ongoing litigation has resulted in the EPA’s continuing review of the rule. Consequently, the nature and cost of additional corrective action requirements may depend, in part, on the outcome of the EPA’s review.
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Other Environmental Matters
Entergy Louisiana and Entergy Texas
Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, currently is involved in the second phase of the remedial investigation of the Lake Charles Service Center site, located in Lake Charles, Louisiana. A manufactured gas plant (MGP) is believed to have operated at this site from approximately 1916 to 1931. Coal tar, a by-product of the distillation process employed at MGPs, apparently was routed to a portion of the property for disposal. The same area also has been used as a landfill. In 1999, Entergy Gulf States, Inc. signed a second administrative consent order with the EPA to perform a removal action at the site. Removal actions addressed contaminated source material, soil, and sediment and included capping certain soil on and off-site. In 2002 approximately 7,400 tons of contaminated soil and debris were excavated and disposed of from an area within the service center. In 2003 a cap was constructed over the remedial area to prevent the migration of contamination to the surface. In August 2010,2005 an administrative order was issued by the EPA requiring that a 10-year groundwater study be conducted at this site. The groundwater monitoring study commenced in January 2006. The EPA released the second Five Year Review in 2015. In that review, the EPA indicated that the remediation technique was insufficient and that Entergy would need to utilize other remediation technologies on the site. In July 2015, Entergy submitted a Focused Feasibility Study to the EPA outlining the potential remedies and suggesting installation of the new remedial method, a waterloo barrier. The estimated cost for this remedy is approximately $2 million, to be allocated between Entergy Louisiana and Entergy Texas. In early 2017 the EPA indicated that the waterloo barrier may not be necessary and requested revisions to the Focused Feasibility Study. The EPA released the third Five Year Review in late-2019 confirming that a new remedial method is not necessary but requiring continuation of the current groundwater monitoring. The site’s remedy includes monitored natural attenuation of groundwater, and institutional controls to restrict groundwater and land use. The EPA has determined that no additional actions are needed for the remedy to be protective over the long-term, and the remedy is protective of human health and the environment.
Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas
The Texas Commission on Environmental Quality (TCEQ) notified Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas that the TCEQ believes those entities are potentially responsible parties (PRPs) concerning contamination existing at the San Angelo Electric Service Company (SESCO) facility in San Angelo, Texas. The facility operated as a transformer repair and scrapping facility from the 1930s until 2003. Both soil and groundwater contamination existed at the site. Entergy subsidiaries sent transformers to this facility. Entergy Arkansas, Entergy Louisiana, and Entergy Texas responded to an information request from the TCEQ. Entergy Louisiana and Entergy Texas joined a group of PRPs responding to site conditions in cooperation with the State of Texas, creating cost allocation models based on review of SESCO documents and employee interviews, and investigating contribution actions against other PRPs. Entergy Louisiana and Entergy Texas have agreed to contribute to the remediation of contaminated soil and groundwater at the site in a measure proportionate to those companies’ involvement at the site. Current estimates, although variable depending on ultimate remediation design and performance, indicate that Entergy’s total share of remediation costs likely will be approximately $1.5 million to $2 million. Groundwater monitoring wells at the site were plugged and abandoned in December 2019 following receipt of a certificate of completion issued by the TCEQ. Site decommissioning activities are complete and final disposition of the property will be determined at a later time.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas
The EPA notified Entergy that the EPA believes Entergy is a PRP concerning PCB contamination at the F.J. Doyle Salvage facility in Leonard, Texas. The facility operated as a scrap salvage business during the 1970s to the 1990s. In May 2018 the EPA investigated the site surface and sub-surface soils and, in November 2018 the EPA conducted a removal action, including disposal of PCB contaminated soils. Entergy responded to the EPA’s information requests in May and July 2019. In November 2020 the EPA sent Entergy and other PRPs a demand
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letter seeking reimbursement for response costs totaling $4 million expended at the site. The demand letter is being evaluated and liability and PRP allocation of response costs are yet to be determined.
Entergy Texas
In December 2016 a transformer inside the Hartburg, Texas Substation had an internal fault resulting in a release of approximately 15,000 gallons of non-PCB mineral oil. Cleanup ensued immediately; however, rain caused much of the oil to spread across the substation yard and into a nearby wetland. The TCEQ and the National Response Center were immediately notified, and the TCEQ responded to the site approximately two hours after the cleanup was initiated. The remediation liability is estimated at $2.2 million; however, this number could fluctuate depending on the remediation extent and wetland mitigation requirements. In July 2017, Entergy entered into the Voluntary Cleanup Program with the TCEQ. In November 2017, additional soil sampling was completed in the wetland area and, in February 2018, a site summary report of findings was submitted to the TCEQ. The TCEQ responded in June 2018 and requested an ecological exclusion criteria checklist/Tier II screening-level ecological risk assessment, and additional site assessment, additional soil samples, groundwater samples, and some additional diagrams and maps. In October 2018, Entergy submitted the requested information to the TCEQ. In January 2019 the TCEQ responded with another request for information. In March 2019, Entergy submitted the requested information to the TCEQ. In August 2019 the TCEQ responded with a request for additional information including an Affected Property Assessment Report (APAR) and water well survey. The TCEQ has agreed that the necessity of the water well survey is dependent on the results of the groundwater resampling that will occur. Groundwater sampling was completed in December 2019 and results were submitted to the TCEQ for review. Based on the groundwater sampling results, the TCEQ confirmed in February 2020 that a water well survey is not necessary and requested the APAR and an Ecological Risk Assessment by August 2020. Due to COVID-19 delays, the TCEQ extended the APAR and Ecological Risk Assessment submittal dates to December 2020, which Entergy timely met.
Litigation
Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but certain states in which Entergy operates have proven to be unusually litigious environments. Judges and juries in Louisiana, Mississippi, and Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. The litigation environment in these states poses a significant business risk to Entergy.
Asbestos Litigation(Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)
See Note 8 to the financial statements for a discussion of this litigation.
Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
See Note 8 to the financial statements for a discussion of these proceedings.
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Human Capital
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2020, Entergy subsidiaries employed 13,400 people.
| | | | | |
Utility: | |
Entergy Arkansas | 1,244 | |
Entergy Louisiana | 1,654 | |
Entergy Mississippi | 750 | |
Entergy New Orleans | 303 | |
Entergy Texas | 658 | |
System Energy | — | |
Entergy Operations | 3,529 | |
Entergy Services | 3,859 | |
Entergy Nuclear Operations | 1,356 | |
Other subsidiaries | 47 | |
Total Entergy | 13,400 | |
Approximately 3,900 employees are represented by the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the International Brotherhood of Teamsters, the United Government Security Officers of America, and the International Union, Security, Police, and Fire Professionals of America.
Below is the breakdown of Entergy’s employees by gender and race/ethnicity:
| | | | | | | | | | | |
Gender (%) | 2020 | | 2019 |
Female | 21 | | 20 |
Male | 79 | | 80 |
| 100 | | 100 |
| | | | | | | | | | | |
Race/Ethnicity (%) | 2020 | | 2019 |
White | 78 | | 79 |
Black/African American | 15 | | 15 |
Hispanic/Latino | 3 | | 2 |
Asian | 2 | | 2 |
Other | 2 | | 2 |
| 100 | | 100 |
Entergy’s Approach to Human Resources
Entergy’s people and culture enable its success; that is why acquiring, retaining, and developing talent are important components of Entergy’s human resources strategy. Entergy focuses on an approach that includes, among other things, governance and oversight; safety; organizational health, including diversity, inclusion and belonging; and talent management.
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Governance and Oversight
Ensuring that workplace processes support the desired culture and strategy begins with the Board of Directors and the Office of the Chief Executive. The Personnel Committee establishes priorities and reviews performance on a range of topics. It oversees Entergy’s incentive plan design and administers its executive compensation plans to incentivize the behaviors and outcomes that support achievement of Entergy’s corporate objectives. Annually, it reviews executive performance, development and succession plans to align a high performing executive team with Entergy’s priorities. The Personnel Committee also oversees Entergy’s performance through regular briefings on a wide variety of human resources topics including Entergy’s safety culture and performance; organizational health; and diversity, inclusion, and belonging initiatives and performance.
Other committees of the Board oversee other key aspects of Entergy’s culture. For example, the Audit Committee reviews reports on ethics and compliance training and performance, as well as regular reports on calls made to Entergy’s ethics line and related investigations. To maximize the sharing of information and facilitate the participation of all Board members in these discussions, the Board schedules its regular committee meetings in a manner such that all directors can attend.
The Office of the Chief Executive, which includes the Senior Vice President and Chief Human Resources Officer, ensures annual business plans are designed to support Entergy’s talent objectives, reviews workforce-related metrics, and regularly discusses the development, succession planning, and performance of their direct reports and other company officers.
Safety
Entergy’s safety objective is: Everyone Safe. All Day. Every Day. While the COVID-19 pandemic and historical hurricane season presented significant challenges, Entergy’s safety strategy and commitment to excellence showed results in 2020. Entergy employees achieved a total recordable incident rate of 0.40 in 2020 compared to 0.56 in 2019 and 0.48 in 2018. The recordable incident rate equals the number of recordable incidents per 100 full-time equivalents. Recordable incidents include fatalities, lost-time accidents, restricted-duty accidents, and medical attentions and is not inclusive of potential work-related COVID-19 cases. This marked improvement in total recordable incident rate placed Entergy in top-decile in safety performance when benchmarked amongst peers within the Edison Electric Institute.
Organizational Health, including Diversity, Inclusion and Belonging
Entergy believes that organizational health fosters an engaged and productive culture that positions Entergy to deliver sustainable value to its stakeholders. Entergy measures its progress through an organizational health survey coordinated by an external third party. Since initially administering the survey in 2014, Entergy improved from an initial score of 49 (fourth quartile) to a score in 2020 of 72 (near top quartile). In addition to significantly improved scores, initial employee participation of 66 percent in 2014 rose to and remains at 90 percent in 2018-2020.
Entergy believes that a culture focused on diversity, inclusion, and belonging drives foundational engagement. Entergy is committed to developing and retaining a workforce that reflects the rich diversity of the communities it serves. In 2019, Entergy embarked on a three-year phased approach to enhance inclusion for individuals and teams. Among other actions, the primary focus of its 2020 actions was taking a stand against social injustice, reinforcing expectations, training and leading by example, starting at the top of the organization and cascading through management ranks.
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Talent Management
Entergy’s focus on talent management is organized in three areas: developing and attracting a diverse pool of talent, equipping its leaders to develop the organization, and building premier utility capability through employee performance management and succession programs. Entergy believes that developing a diverse pool of local talent equipped with the skills needed, today and in the future, and reflecting the communities Entergy serves will give it a long-term competitive advantage. The focus of Entergy’s leadership development programs is to equip managers with the skills needed to effectively develop their teams and improve the leader-employee relationship. Entergy’s talent development infrastructure, which includes a combination of business function-specific and enterprise-wide learning and development programs, is designed to ensure Entergy has qualified staff with the skills, experiences, and behaviors needed to perform today and prepare for the future. Entergy strives to achieve its strategic priorities by aligning and enhancing team and individual performance with business objectives, effectively deploying talent through succession planning, and managing workforce transitions.
Availability of SEC filings and other information on Entergy’s website
Entergy electronically files reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies, and amendments to such reports. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. Copies of the reports that Entergy files with the SEC can be obtained at the SEC’s website.
Entergy uses its website, http://www.entergy.com, as a routine channel for distribution of important information, including news releases, analyst presentations and financial information. Filings made with the SEC are posted and available without charge on Entergy’s website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These filings include annual and quarterly reports on Forms 10-K and 10-Q (including related filings in Inline XBRL format) and current reports on Form 8-K; proxy statements; and any amendments to those reports or statements. All such postings and filings are available on Entergy’s Investor Relations website free of charge. Entergy is providing the address to its internet site solely for the information of investors and does not intend the address to be an active link. The contents of the website are not incorporated into this report.
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RISK FACTORS
See “RISK FACTOR SUMMARY” in Part I Item 1 for a summary of Entergy’s and the Registrant Subsidiaries’ risk factors.
Investors should review carefully the following risk factors and the other information in this Form 10-K. The risks that Entergy faces are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect Entergy’s financial condition, results of operations, and liquidity. See “FORWARD-LOOKING INFORMATION.”
Utility Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The impacts of the COVID-19 pandemic and responsive measures taken on Entergy’s and its Utility operating companies’ business, results of operations, and financial condition are highly uncertain and cannot be predicted.
In December 2019 a novel strain of coronavirus was reported to have surfaced in Wuhan, China. Since then, COVID-19 has spread throughout most countries in the world, including the United States. Public health officials in the United States have both recommended and mandated wearing of masks, precautions to mitigate the spread of COVID-19, including prohibitions on congregating in heavily-populated areas, mandated closure or limitations on the functions of non-essential business, and shelter-in-place orders or similar measures, including throughout Entergy’s service areas. While some of these mitigation measures have been lifted, it is unclear how long certain forms of mitigation measures will remain in place, whether they will be reinstated in the future, and how they will ultimately impact the general economy, Entergy’s customers, and its operations.
Entergy and its Utility operating companies have experienced a decline in commercial and industrial sales and an increase in arrearages and bad debt expense due to non-payment by customers, and expect such reduced levels of sales and increased arrearages and bad debt expense to continue, the extent and duration of which management cannot predict. The Utility operating companies temporarily suspended disconnecting customers for non-payment of bills, and the suspension remains in place at Entergy Arkansas, has been re-instituted at Entergy New Orleans, and could be re-instituted at the other Utility operating companies should their regulators mandate. While they are working with regulators to ensure ultimate recovery for those and other COVID-19 related costs, the amount, method, and timing of such recovery is unknown. Entergy and its Registrant Subsidiaries also could experience, and in some cases have experienced, among other challenges, supply chain, vendor, and contractor disruptions; delays in completion of capital or other construction projects, maintenance, and other operations activities, including prolonged or delayed outages; delays in regulatory proceedings; workforce availability, health or safety issues; increased storm recovery costs; increased cybersecurity risks as a result of many employees telecommuting; increased late or uncollectible customer payments; volatility in the credit or capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available credit facilities); or other adverse impacts on their ability to execute on business strategies and initiatives.
A sustained or further economic decline could adversely impact Entergy’s and the Utility operating companies’ liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, or increased bad debt expense. The Utility operating companies also may experience regulatory outcomes that require them to postpone planned investment and otherwise reduce costs due to the impact of the COVID-19 pandemic on their customers. In addition, if the COVID-19 pandemic continues to create disruptions or turmoil in the credit or financial markets, or adversely impacts Entergy’s credit metrics or ratings, such developments could adversely affect its ability to access capital on favorable terms and continue to meet its
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liquidity needs, or cause a decrease in the value of its defined benefit pension trust funds, as well as its nuclear decommissioning trust funds, all of which are highly uncertain and cannot be predicted.
Entergy cannot predict the extent or duration of the outbreak, the impact of new variants of COVID-19, the timing, availability, distribution or effectiveness of a vaccine, anti-viral or other treatments for COVID-19, governmental responsive measures, or the extent of the effects or ultimate impacts on the global, national or local economy, the capital markets, or its customers, suppliers, operations, financial condition, results of operations, or cash flows.
The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that can be lengthy and subject to appeal, potentially resulting in delays in effecting rate changes, lengthy litigation and uncertainty as to ultimate results.
The Utility operating companies are regulated on a cost-of-service and rate of return basis and are subject to statutes and regulatory commission rules and procedures. The rates that the Utility operating companies and System Energy charge reflect their capital expenditures, operations and maintenance costs, allowed rates of return, financing costs, and related costs of service. These rates significantly influence the financial condition, results of operations, and liquidity of Entergy and each of the Utility operating companies and System Energy. These rates are determined in regulatory proceedings and are subject to periodic regulatory review and adjustment, including adjustment upon the initiative of a regulator or affected stakeholders.
In addition, regulators may initiate proceedings to investigate the prudence of costs in the Utility operating companies’ and System Energy’s base rates and examine, among other things, the reasonableness or prudence of the companies’ operation and maintenance practices, level of expenditures (including storm costs and costs associated with capital projects), allowed rates of return and rate base, proposed resource acquisitions, and previously incurred capital expenditures that the operating companies seek to place in rates. The regulators may disallow costs subject to their jurisdiction found not to have been prudently incurred or found not to have been incurred in compliance with applicable tariffs, creating some risk to the ultimate recovery of those costs. Regulatory proceedings relating to rates and other matters typically involve multiple parties seeking to limit or reduce rates. Traditional base rate proceedings, as opposed to formula rate plans, generally have long timelines, are primarily based on historical costs, and may or may not be limited in scope or duration by statute. The length of these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates, such that the Utility operating companies may not fully recover all costs during the rate effective period and the Utility operating companies may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings.
The Utility operating companies have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including the operation of their assets and infrastructure or the quality of their service. Criticism or adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view the applicable operating company in a favorable light and could potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements.
The base rates of Entergy Texas are established largely in traditional base rate case proceedings.Between base rate proceedings, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs.These riders include a distribution cost recovery factor rider mechanism for the recovery of distribution-related capital investment and certain non-fuel MISO charges, a transmission cost recovery factor rider mechanism for the recovery of transmission-related capital investments, a generation cost recovery rider mechanism for the recovery of generation-related capital investments, and a fixed fuel factor mechanism for the recovery of MISO fuel and energy-related costs.Entergy Texas also is required to make a filing every three years,
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at a minimum, reconciling its fuel and purchased power costs and fuel factor revenues.In the course of this reconciliation, the PUCT determines whether eligible fuel and fuel-related expenses and revenues are necessary and reasonable, and makes a prudence finding for each of the fuel-related contracts for the reconciliation period.Entergy Texas also is required to file full base rate case proceedings every four years and within eighteen months of utilizing its generation cost recovery rider for investments above $200 million.
Between base rate cases, Entergy Arkansas and Entergy Mississippi are able to adjust base rates annually through formula rate plans that utilize a forward test year (Entergy Arkansas) or forward-looking features (Entergy Mississippi).In response to Entergy Arkansas’s application for a general change in rates in 2015, the APSC approved the formula rate plan tariff proposed by Entergy Arkansas including its use of a projected year test period and an initial five-year term.The initial five-year term expires in 2021. Entergy Arkansas has requested APSC approval of the extension of the formula rate plan tariff for an additional five years through 2026.If Entergy Arkansas’s formula rate plan were terminated or not extended beyond the initial term, Entergy Arkansas could file an application for a general change in rates that may include a request for continued regulation under a formula rate review mechanism.If Entergy Mississippi’s formula rate plan is terminated, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan.Entergy Arkansas and Entergy Mississippi recover fuel and purchased energy and certain non-fuel costs through other APSC-approved and MPSC-approved tariffs, respectively.
Entergy Louisiana historically sets electric base rates annually through a formula rate plan using an historic test year.The form of the formula rate plan, on a combined basis, was approved in connection with the business combination of Entergy Louisiana and Entergy Gulf States Louisiana and largely followed the formula rate plans that were approved by the LPSC staffin connection with the full electric base rate cases filed by those companies in February 2013.The formula rate plan was most recently extended through the test year 2019; certain modifications were made in that extension, including a decrease to the allowed return on equity and intervenorsthe addition of a transmission cost recovery mechanism.The formula rate plan continues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities and purchase power agreements approved by the LPSC and as noted, for certain transmission investment, among other items.MISO fuel and energy-related costs are recoverable in Entergy Louisiana’s fuel adjustment clause.Entergy Louisiana has a pending request to extend its formula rate plan with certain modifications, including implementation of a distribution investment recovery mechanism and use of end of period rate base.In the event that the electric formula rate plan is not renewed or extended, Entergy Louisiana would revert to the more traditional rate case environment.
Entergy New Orleans previously operated under a formula rate plan that ended with the 2011 test year.Based on a settlement agreement approved by the City Council, with limited exceptions, the base rates of Entergy New Orleans were frozen until rates were implemented in connection with the base rate case filed testimony. by Entergy New Orleans in 2018.In November 2019 the City Council issued a resolution resolving the rate case, with rates to become effective retroactive to August 2019.The LPSC staff (1)resolution allows Entergy New Orleans to implement a three-year formula rate plan, beginning with the 2019 test year as adjusted for forward-looking known and measurable changes.In November 2020 the City Council issued a resolution approving a settlement of the 2018 rate case.As part of this settlement, Entergy New Orleans agreed to postpone the filing of its first test year formula rate plan to 2021 and, in return, to be provided an additional test year for the three-year cycle.See Note 2 to the financial statements for further discussion.
The rates of System Energy are established by the FERC, and the costs allowed to be charged pursuant to these rates are, in turn, passed through to the participating Utility operating companies through the Unit Power Sales Agreement, which has monthly billings that reflect the current operating costs of, and investment in, Grand Gulf. Retail regulators and other parties may seek to initiate proceedings at FERC to investigate the prudence of costs included in the rates charged under the Unit Power Sales Agreement and examine, among other things, the
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reasonableness or prudence of the operation and maintenance practices, level of expenditures, allowed rates of return and rate base, and previously incurred capital expenditures. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a separate request for FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings nor can it predict whether any outcome could have a material effect on Entergy’s or System Energy’s results of operations, financial condition or liquidity. See Note 2 to the financial statements for further discussion of the proceedings. System Energy has received FERC acceptance for billing protocols to provide retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
The Utility operating companies and System Energy, and the energy industry as a whole, have experienced a period of rising costs and investments, and an upward trend in spending, especially with respect to infrastructure investments, which is likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms. For information regarding rate case proceedings and formula rate plans applicable to the Utility operating companies, see Note 2 to the financial statements.
Changes to state or federal legislation or regulation affecting electric generation, electric and natural gas transmission, distribution, and related activities could adversely affect Entergy and the Utility operating companies’ financial position, results of operations, or cash flows and their utility businesses.
If legislative and regulatory structures evolve in a manner that erodes the Utility operating companies’ exclusive rights to serve their regulated customers, they could lose customers and sales and their results of operations, financial position, or cash flows could be materially affected. Additionally, technological advances in energy efficiency and distributed energy resources are reducing the costs of these technologies and together with ongoing state and federal subsidies, the increasing penetration of these technologies could result in reduced sales by the Utility operating companies. Such loss of sales could put upward pressure on rates, resulting in adverse regulatory actions to mitigate such effects on rates. Entergy and the Utility operating companies cannot predict if or when they may be subject to changes in legislation or regulation, or the extent and timing of reductions of the cost of distributed energy resources, nor can they predict the impact of these changes on their results of operations, financial position, or cash flows.
The Utility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings.
The Utility operating companies recover their fuel, purchased power, and associated costs from their customers through rate mechanisms subject to periodic regulatory review and adjustment. Because regulatory review can result in the disallowance of incurred costs found not to have been prudently incurred, including the cost of replacement power purchased when generators experience outages or when planned outages are extended, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs, particularly when there are substantial or sudden increases in such costs. Regulators also may initiate proceedings to investigate the continued usage or the adequacy and operation of the fuel and purchased power recovery clauses of the Utility operating companies and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.
The Utility operating companies’ cash flows can be negatively affected by the time delays between when gas, power, or other commodities are purchased and the ultimate recovery from customers of the costs in rates. On occasion, when the level of incurred costs for fuel and purchased power rises very dramatically, some of the Utility operating companies may agree to defer recovery of a portion of that period’s fuel and purchased power costs for recovery at a later date, which could increase the near-term working capital and borrowing requirements of those companies. For a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power costs recovery, see Note 2 to the financial statements.
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There remains uncertainty regarding the effect of the termination of the System Agreement on the Utility operating companies.
The Utility operating companies historically engaged in the coordinated planning, construction, and operation of generating resources and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that had been approved by the FERC. The System Agreement terminated in its entirety on August 31, 2016.
There remains uncertainty regarding the long-term effect of the termination of the System Agreement on the Utility operating companies because of the significant effect of the agreement on the generation and transmission functions of the Utility operating companies and the significant period of time (over 30 years) that it was prudenthad been in existence. In the absence of the System Agreement, there remains uncertainty around the effectiveness of governance processes and the potential absence of federal authority to moveresolve certain issues among the projectUtility operating companies and their retail regulators.
In addition, although the System Agreement terminated in its entirety in August 2016, there are a few outstanding System Agreement proceedings at the FERC and at the D.C. Circuit that may require future adjustments, including challenges to the level and timing of payments made by Entergy Arkansas under the System Agreement. The outcome and timing of these FERC proceedings and resulting recovery and impact on rates cannot be predicted at this time.
For further information regarding the regulatory proceedings relating to the System Agreement, see Note 2 to the financial statements.
The Utility operating companies are subject to economic risks associated with participation in the MISO markets and the allocation of transmission upgrade costs. The operation of the Utility operating companies’ transmission system pursuant to the MISO RTO tariff and their participation in the MISO RTO’s wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
On December 19, 2013, the Utility operating companies integrated into the MISO RTO. MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. The Utility operating companies are subject to economic risks associated with participation in the MISO markets. MISO tariff rules and system conditions, including transmission congestion, could affect the Utility operating companies’ ability to sell capacity, energy, and/or ancillary services in certain regions and/or the economic value of such sales, or the cost of serving the Utility operating companies’ respective loads, and MISO market rules may change in ways that cause additional risk.
The Utility operating companies participate in the MISO regional transmission planning process and are subject to risks associated with planning decisions that MISO makes in the exercise of control over the planning of the Utility operating companies’ transmission assets that are under MISO’s functional control. The Utility operating companies pay transmission rates that reflect the cost of transmission projects that the Utility operating companies do not own, which could increase cash or financing needs. In addition to the cash and financing-related risks arising from long-term suspensionthe potential additional cost allocation to cancellationthe Utility operating companies from transmission projects of others, there is a risk that the Utility operating companies’ business and financial position could be harmed as a result of lost investment opportunities and other effects that flow from an increased number of competitive projects being approved and constructed that are interconnected with their transmission systems. Further, the terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets, the
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allocation of transmission upgrade costs, the MISO-wide allowed base rate of return on equity, and any required MISO-related charges and credits are subject to regulation by the FERC. The operation of the Utility operating companies’ transmission system pursuant to the MISO tariff and their participation in the MISO wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements. In addition, orders from each of the Utility operating companies’ respective retail regulators generally require that the Utility operating companies make periodic filings, or generally allow the retail regulator to direct the making of such filings, setting forth the results of analysis of the costs and benefits realized from MISO membership as well as the projected costs and benefits of continued membership in MISO and/or requesting approval of their continued membership in MISO. These filings have been submitted periodically by each of the Utility operating companies as required by their respective retail regulators, and the outcome of the resulting proceedings may affect the Utility operating companies’ continued membership in MISO.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather (including from Hurricane Laura, Hurricane Delta, and Hurricane Zeta), or the impact on customer bills of permitted storm cost recovery, could have material effects on Entergy and its Utility operating companies.
Entergy’s and its Utility operating companies’ results of operations, liquidity, and financial condition can be materially affected by the destructive effects of severe weather. Severe weather can also result in significant outages for the customers of the Utility operating companies and, therefore, reduced revenues for the Utility operating companies during the period of the outages. A delay or failure in recovering amounts for storm restoration costs incurred or revenues lost as a result of severe weather could have a material effect on Entergy and those Utility operating companies affected by severe weather. In addition, the recovery of major storm restoration costs from customers could effectively limit our ability to make planned capital or other investments due to the impact of such storm cost recovery on customer bills.
In August and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of the Utility’s service territories in Louisiana, including New Orleans, Texas, and to a lesser extent, in Arkansas and Mississippi. The storms resulted in widespread power outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild. Total restoration costs for the repair and/or replacement of the electrical system damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta are currently estimated to be approximately $2.4 billion. Because Entergy has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Nuclear Operating, Shutdown, and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)
Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities must consistently operate their nuclear power plants at high capacity factors in order to be successful, and lower capacity factors could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Nuclear capacity factors significantly affect the results of operations of certain Utility operating companies, System Energy, and Entergy Wholesale Commodities. Nuclear plant operations involve substantial fixed operating
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costs. Consequently, to be successful, a plant owner must consistently operate its nuclear power plants at high capacity factors, consistent with safety requirements. For the Utility operating companies that own nuclear plants, lower capacity factors can increase production costs by requiring the affected companies to generate additional energy, sometimes at higher costs, from their owned or contractually controlled facilities or purchase additional energy in the spot or forward markets in order to satisfy their supply needs. For the Entergy Wholesale Commodities nuclear plants, lower capacity factors directly affect revenues and cash flow from operations. Entergy Wholesale Commodities’ forward sales are comprised of various hedge products, many of which have some degree of operational-contingent price risk. Certain unit-contingent contracts guarantee specified minimum capacity factors. In the event plants with these contracts were operating below the guaranteed capacity factors, Entergy would be subject to price risk for the undelivered power. Further, Entergy Wholesale Commodities’ nuclear forward sales contracts can also be on a firm LD basis, which subjects Entergy to increasing price risk as capacity factors decrease. Many of these firm hedge products have damages risk.
Certain of the Utility operating companies and System Energy periodically shut down their nuclear power plants to replenish fuel. Plant maintenance and upgrades are often scheduled during such refueling outages. If refueling outages last longer than anticipated or if unplanned outages arise, Entergy’s and their results of operations, financial condition, and liquidity could be materially affected.
Outages at nuclear power plants to replenish fuel require the plant to be “turned off.” Refueling outages generally are planned to occur once every 18 to 24 months. Plant maintenance and upgrades are often scheduled during such planned outages, which typically extends the planned outage duration. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease, and maintenance costs may increase.
Certain of the Utility operating companies and System Energy face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication). These risks could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Based upon currently planned fuel cycles, Entergy’s nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable prices through 2020 and beyond. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. While there are a number of possible alternate suppliers that may be accessed to mitigate any supplier performance failure, the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S. Market prices for nuclear fuel have been extremely volatile from time to time in the past and may be subject to increased volatility due to the imposition of tariffs, domestic purchase requirements or limitations on importation of uranium or uranium products from foreign countries, or shifting trade arrangements between countries. Although Entergy’s nuclear fuel contract portfolio provides a degree of hedging against market risks for several years, costs for nuclear fuel in the future cannot be predicted with certainty due to normal inherent market uncertainties, and price changes could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance and reliability of conversion, enrichment, and fabrication services providers. These service providers are fewer in number than uranium suppliers. For conversion and enrichment services, Entergy diversifies its supply by supplier and country and may take special measures to ensure a reliable supply of enriched uranium for fabrication into nuclear fuel. For fabrication services, each plant is dependent upon the performance of the fabricator of that plant’s nuclear fuel; therefore, Entergy relies upon additional monitoring, inspection, and oversight of the fabrication process to assure reliability and quality of its nuclear fuel. Certain of the suppliers and service providers are located in or dependent upon countries, such as Russia, in which international sanctions or tariffs could further restrict the ability of such
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suppliers to continue to supply fuel or provide such services at acceptable prices or at all. The inability of such suppliers or service providers to perform such obligations could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business face the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants, which could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Under the Atomic Energy Act and Energy Reorganization Act, the NRC regulates the operation of nuclear power plants. The NRC may modify, suspend, or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations, or the terms of the licenses for nuclear facilities. Interested parties may also intervene which could result in prolonged proceedings. A change in the Atomic Energy Act, other applicable statutes, or the applicable regulations or licenses, or the NRC’s interpretation thereof, may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially affect the results of operations, liquidity, or financial condition of Entergy (through Entergy Wholesale Commodities), its Utility operating companies, or System Energy. A change in the classification of a plant owned by one of these companies under the NRC’s Reactor Oversight Process, which is the NRC’s program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response, also could cause the owner of the plant to incur material additional costs as a result of the increased oversight activity and potential response costs associated with the change in classification.For additional information concerning the current classification of the plants owned by Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business, see “Regulation of Entergy’s Business- Regulation of the Nuclear Power Industry - NRC Reactor Oversight Process” in Part I, Item 1.
Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate actions to modify, suspend, or revoke licenses, shut down a nuclear facility, or impose civil penalties. As a result, if an incident were to occur at any nuclear generating unit, whether an Entergy nuclear generating unit or not, it could materially affect the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, System Energy, or Entergy Wholesale Commodities.
Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities are exposed to risks and costs related to operating and maintaining their nuclear power plants, and their failure to maintain operational efficiency at their nuclear power plants could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
The nuclear generating units owned by certain of the Utility operating companies, System Energy,and the Entergy Wholesale Commodities business began commercial operations in the 1970s-1980s. Older equipment may require more capital expenditures to keep each of these nuclear power plants operating safely and efficiently. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages, or any unanticipated capital expenditures, could result in increased costs, some of which costs may not be fully recoverable by the Utility operating companies and System Energy in regulatory proceedings should there be a determination of imprudence. Operations at any of the nuclear generating units owned and operated by Entergy’s subsidiaries could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. A decision may be made to close a unit rather than incur the expense of restarting it or returning the unit to full capacity. For the Utility operating companies and System Energy, this could result in certain costs being stranded and potentially not fully recoverable in regulatory proceedings. For Entergy Wholesale Commodities, this could result in lost revenue and increased fuel and purchased power expense to meet
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supply commitments and penalties for failure to perform under their contracts with customers. In addition, the operation and maintenance of Entergy’s nuclear facilities require the commitment of substantial human resources that can result in increased costs.
The nuclear industry continues to address susceptibility to the effects of stress corrosion cracking and other corrosion mechanisms on certain materials within plant systems. The issue is applicable at all nuclear units to varying degrees and is managed in accordance with industry standard practices and guidelines that include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.
Moreover, Entergy is becoming more dependent on fewer suppliers for key parts of Entergy’s nuclear power plants that may need to be replaced or refurbished, and in some cases, parts are no longer available and have to be reverse-engineered for replacement. In addition, certain major parts have long lead-times to manufacture if an unplanned replacement is needed. This dependence on a reduced number of suppliers and long lead-times on certain major parts for unplanned replacements could result in delays in obtaining qualified replacement parts and, therefore, greater expense for Entergy.
The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities nuclear power plants, as well as the costs of and their ability to fully decommission their nuclear power plants, could be significantly affected by the timing of the opening of a spent nuclear fuel disposal facility, as well as interim storage and transportation requirements.
Certain of the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities nuclear plants incur costs for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the disposal of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, or any interim storage facility, and the timing of such facility opening, will significantly affect the costs associated with on-site storage of spent nuclear fuel. For example, while the DOE is required by law to proceed with the licensing of Yucca Mountain and, after the license is granted by the NRC, to construct the repository and commence the receipt of spent fuel, the NRC licensing of the Yucca Mountain repository is effectively at a standstill. These actions are prolonging the time before spent fuel is removed from Entergy’s plant sites. Because the DOE has not accomplished its objectives, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts, and Entergy has sued the DOE for such breach. Furthermore, Entergy is uncertain as to when the DOE will commence acceptance of spent fuel from its facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at the companies’ nuclear sites and maintenance costs on existing storage facilities, including aging management of fuel storage casks, may increase. The costs of on-site storage are also affected by regulatory requirements for such storage. In addition, the availability of a repository or other off-site storage facility for spent nuclear fuel may affect the ability to fully decommission the nuclear units and the costs relating to decommissioning. For further information regarding spent fuel storage, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs – Spent Fuel Disposal” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 8 to the financial statements.
Certain of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities nuclear plant owners may be required to pay substantial retrospective premiums imposed under the Price-Anderson Act in the event of a nuclear incident, and losses not covered by insurance could have a material effect on Entergy’s and their results of operations, financial condition, or liquidity.
Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere. The Price-Anderson Act limits each reactor owner’s public liability (off-site) for a single nuclear incident to the payment of retrospective premiums into a secondary insurance pool, which is referred to as Secondary Financial Protection, up to approximately $137.6 million per reactor. With 97 reactors currently
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
participating, this translates to a total public liability cap of approximately $14 billion per incident. The limit is subject to change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As required by the Price-Anderson Act, the Utility operating companies, System Energy, and Entergy Wholesale Commodities carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers, which is $450 million for each operating site. Claims for any nuclear incident exceeding that amount are covered under Secondary Financial Protection. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the primary insurance coverage, each owner of a nuclear plant reactor, including Entergy’s Utility operating companies, System Energy, and the Entergy Wholesale Commodities plant owners, regardless of fault or proximity to the incident, will be required to pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary insurance level, up to a maximum of approximately $137.6 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.101 billion). The retrospective premium payment is currently limited to approximately $21 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $137.6 million cap.
NEIL is a utility industry mutual insurance company, owned by its members, including the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities plants. All member plants could be subject to an annual assessment (retrospective premium of up to 10 times current annual premium for all policies) should the NEIL surplus (reserve) be significantly depleted due toinsured losses. As of December 31, 2020, the maximum annual assessment amounts total $104 million for the Utility plants. Retrospective premium insurance available through NEIL’s reinsurance treaty can cover the potential assessments and the Entergy Wholesale Commodities plants currently maintain the retrospective premium insurance to cover those potential assessments.
As an owner of nuclear power plants, Entergy participates in industry self-insurance programs and could be liable to fund claims should a plant owned by a different company experience a major event. Any resulting liability from a nuclear accident may exceed the applicable primary insurance coverage and require contribution of additional funds through the industry-wide program that could significantly affect the results of operations, financial condition, or liquidity of Entergy, certain of the Utility operating companies, System Energy, or the Entergy Wholesale Commodities subsidiaries.
The decommissioning trust fund assets for the nuclear power plants owned by the Utility operating companies, System Energy, and the Entergy Wholesale Commodities nuclear plant owners may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts, if one or more of Entergy’s nuclear power plants is retired earlier than the anticipated shutdown date, if the plants cost more to decommission than estimated, or if current regulatory requirements change, which then could require significant additional funding.
Owners of nuclear generating plants have an obligation to decommission those plants. Certain of the Utility operating companies, System Energy, and owners of the Entergy Wholesale Commodities nuclear power plants maintain decommissioning trust funds for this purpose. Certain of the Utility operating companies collect funds from their customers, which are deposited into the trusts covering the units operated for or on behalf of those companies. Those rate collections, as adjusted from time to time by rate regulators, are generally based upon operating license lives and trust fund balances as well as estimated trust fund earnings and decommissioning costs. Assets in these trust funds are subject to market fluctuations, will yield uncertain returns that may fall below projected return rates, and may result in losses resulting from the recognition of impairments of the value of certain securities held in these trust funds.
Under NRC regulations, nuclear plant owners are permitted to project the NRC-required decommissioning amount, based on an NRC formula or a site-specific estimate, and the amount that will be available in each nuclear power plant’s decommissioning trusts combined with any other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used. If the projected amount of each individual plant’s decommissioning trusts exceeds the NRC-required decommissioning amount, then its NRC license termination decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs required to decommission these nuclear power plants, or funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources or commitments would be required. Furthermore, depending upon the level of funding available in the trust funds, the NRC may not permit the trust funds to be used to pay for related costs such as the management of spent nuclear fuel that are not included in the NRC’s formula. The NRC may also require a plan for the provision of separate funding for spent fuel management costs. In addition to NRC requirements, there are other decommissioning-related obligations for certain of the Entergy Wholesale Commodities nuclear power plants, which management believes it will be able to satisfy.
Further, federal or state regulatory changes, including mandated increases in decommissioning funding or changes in the methods or standards for decommissioning operations, may also increase the funding requirements of, or accelerate the timing for funding of, the obligations related to the decommissioning of the Utility operating companies, System Energy, or Entergy Wholesale Commodities nuclear power plants or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. Such changes also could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. As a result, under any of these circumstances, Entergy’s results of operations, liquidity, and financial condition could be materially affected.
An early plant shutdown (either generally or relative to current expectations), poor investment results, or higher than anticipated decommissioning costs (including as a result of changing regulatory requirements) could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that the Utility operating companies, System Energy, or the Entergy Wholesale Commodities nuclear plant owners may be required to provide significant additional funds or credit support to satisfy regulatory requirements for decommissioning, which, with respect to the Utility operating companies, may not be recoverable from customers in a timely fashion or at all.
For further information regarding nuclear decommissioning costs, management’s decision to suspendexit the merchant power business, the impairment charges that resulted from such decision, and the planned sales of Palisades and Indian Point Energy Center (which, in each case, will include the transfer of the associated decommissioning trusts), see the “Critical Accounting Estimates- Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy, the “Entergy Wholesale Commodities Exit from the Merchant Power Business” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries, and Notes 9 and 14 to the financial statements.
New or existing safety concerns regarding operating nuclear power plants and nuclear fuel could lead to restrictions upon the operation and decommissioning of Entergy’s nuclear power plants.
New and existing concerns are being expressed in public forums about the safety of nuclear generating units and nuclear fuel. These concerns have led to, and may continue to lead to, various proposals to Federal regulators and governing bodies in some localities where Entergy’s subsidiaries own nuclear generating units for legislative and regulatory changes that might lead to the shutdown of nuclear units, additional requirements or restrictions related to spent nuclear fuel on-site storage and eventual disposal, or other adverse effects on owning, operating, and decommissioning nuclear generating units. Entergy vigorously responds to these concerns and proposals. If any of the existing proposals, or any proposals that may arise in the future with respect to legislative and regulatory changes, become effective, they could have a material effect on Entergy’s results of operations and financial condition.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
(Entergy Corporation)
Entergy Wholesale Commodities nuclear power plants are exposed to price risk.
Entergy and its subsidiaries do not have a regulator-authorized rate of return on their capital investments in non-utility businesses. As a result, the sale of capacity and energy from the Entergy Wholesale Commodities nuclear power plants, unless otherwise contracted, is subject to the fluctuation of market power prices. In order to reduce future price risk to desired levels, Entergy Wholesale Commodities utilizes contracts that are unit-contingent and Firm LD and various products such as forward sales, options, and collars. As of December 31, 2020, Entergy Wholesale Commodities’ nuclear power generation plants had sold forward 98% in 2021 and 99% in 2022 of its generation portfolio’s planned energy output, reflecting the planned shutdown and sale of the remaining Entergy Wholesale Commodities nuclear power plants by mid-2022.
Market conditions such as product cost, market liquidity, and other portfolio considerations influence the product and contractual mix. The obligations under unit-contingent agreements depend on a longer-termgenerating asset that is operating; if the generation asset is not operating, the seller generally is not liable for damages. For some unit-contingent obligations, however, there is also a guarantee of availability that provides for the payment to the power purchaser of contract damages, if incurred, in the event the unit owner fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. Firm LD sales transactions may be exposed to substantial operational price risk, a portion of which may be capped through the use of risk management products, to the extent that the plants do not run as expected and market prices exceed contract prices.
Market prices may fluctuate substantially, sometimes over relatively short periods of time, and at other times experience sustained increases or decreases. Demand for electricity and its fuel stock can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply, prices might be depressed. Also, from time to time there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, credit requirements, bidding rules, and other mechanisms to address volatility and other issues in these markets.
The effects of sustained low natural gas prices and power market structure challenges have resulted in lower market prices for electricity in the power regions where the Entergy Wholesale Commodities nuclear power plants are located. In addition, currently the market design under which the plants operate does not adequately compensate merchant nuclear plants for their environmental and fuel diversity benefits in the region. These conditions were primary factors leading to Entergy’s decision to shut down (or sell) Entergy Wholesale Commodities’ nuclear power plants before the end of their operating licenses.
The price that different counterparties offer for various products including forward sales is influenced both by market conditions as well as the contract terms such as damage provisions, credit support requirements, and the number of available counterparties interested in contracting for the desired forward period. Depending on differences between market factors at the time of contracting versus current conditions, Entergy Wholesale Commodities’ contract portfolio may have average contract prices above or below current market prices, including at the expiration of the contracts, which may significantly affect Entergy Wholesale Commodities’ results of operations, financial condition, or liquidity. New hedges are generally layered into on a rolling forward basis, waswhich tends to drive hedge over-performance to market in a falling price environment, and hedge underperformance to market in a rising price environment; however, hedge timing, product choice, and hedging costs will also affect these results. See the “Market and Credit Risk Sensitive Instruments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries. Since Entergy Wholesale Commodities has announced the closure (or sale) of its nuclear plants, Entergy Wholesale Commodities may enter into fewer forward sales contracts for output from such plants.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The Entergy Wholesale Commodities business is subject to substantial governmental regulation and may be adversely affected by legislative, regulatory, or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
The Entergy Wholesale Commodities business is subject to extensive regulation under federal, state, and local laws. Compliance with the requirements under these various regulatory regimes may cause the Entergy Wholesale Commodities business to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines, and/or civil or criminal liability.
Public utilities under the Federal Power Act are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Each of the owners of the Entergy Wholesale Commodities nuclear power plants that generates electricity, as well as Entergy Nuclear Power Marketing, LLC, is a “public utility” under the Federal Power Act by virtue of making wholesale sales of electric energy and/or owning wholesale electric transmission facilities. The FERC has granted these generating and power marketing companies the authority to sell electricity at market-based rates. The FERC’s orders that grant the Entergy Wholesale Commodities’ generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that the Entergy Wholesale Commodities business can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, the Entergy Wholesale Commodities’ market-based sales are subject to certain market behavior rules, and if any of its generating and power marketing companies were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority and potential penalties of up to $1.29 million per day per violation. If the Entergy Wholesale Commodities’ generating or power marketing companies were to lose their market-based rate authority, such companies would be required to obtain the FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates the Entergy Wholesale Commodities business charges for power from its facilities.
The Entergy Wholesale Commodities business is also affected by legislative and regulatory changes, as well as changes to market design, market rules, tariffs, cost allocations, and bidding rules imposed by the existing Independent System Operators. The Independent System Operators that oversee most of the wholesale power markets may impose, and in the future may continue to impose, mitigation, including price limitations, offer caps and other mechanisms, to address some of the volatility and the potential exercise of market power in these markets. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of the Entergy Wholesale Commodities business’ generation facilities that sell energy and capacity into the wholesale power markets. For further information regarding federal, state, and local laws and regulation applicable to the Entergy Wholesale Commodities business, see the “Regulation of Entergy’s Business” section in Part I, Item 1.
The regulatory environment applicable to the electric power industry is subject to changes as a result of restructuring initiatives at both the state and federal levels. Entergy cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on the Entergy Wholesale Commodities business. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism, have raised claims that the competitive marketplace is not imprudent; (2) indicatedworking because energy prices in wholesale markets exceed the marginal cost of operating nuclear power plants, and have made proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process, which could require material changes to business planning models. If competitive restructuring of the electric power markets is reversed, modified, discontinued, or delayed, the Entergy Wholesale Commodities business’ results of operations, financial condition, and liquidity could be materially affected.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The power plants owned by the Entergy Wholesale Commodities business are subject to impairment charges in certain circumstances, which could have a material effect on Entergy’s results of operations, financial condition, or liquidity.
Entergy reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that exceptrecoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from the operations of such assets. Projected net cash flows depend on the expected operating life of the assets, the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for $0.8energy and capacity over the remaining life of the assets. In particular, the remaining assets of the Entergy Wholesale Commodities business are subject to further impairment in connection with the closure and sale of its nuclear power plants. Moreover, prior to the closure and sale of these plants, the failure of the Entergy Wholesale Commodities business to achieve forecasted operating results and cash flows, an unfavorable change in forecasted operating results or cash flows, a reduction in the expected remaining useful life of a unit, or a decline in observable industry market multiples could all result in potential additional impairment charges for the affected assets.
If Entergy concludes that any of its nuclear power plants is unlikely to operate through its planned shutdown date, which conclusion would be based on a variety of factors, such a conclusion could result in a further impairment of part or all of the carrying value of the plant. Any impairment charge taken by Entergy with respect to its long-lived assets, including the remaining power plants owned by the Entergy Wholesale Commodities business, would likely be material in the quarter that the charge is taken and could otherwise have a material effect on Entergy’s results of operations, financial condition, or liquidity. For further information regarding evaluating long-lived assets for impairment, see the “Critical Accounting Estimates - Impairment of Long-lived Assets” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries and for further discussion of the impairment charges, see Note 14 to the financial statements.
General Business
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Entergy and the Utility operating companies depend on access to the capital markets and, at times, may face potential liquidity constraints, which could make it more difficult to handle future contingencies such as natural disasters or substantial increases in gas and fuel prices. Disruptions in the capital and credit markets may adversely affect Entergy’s and its subsidiaries’ ability to meet liquidity needs, access capital and operate and grow their businesses, and the cost of capital.
Entergy’s business is capital intensive and dependent upon its ability to access capital at reasonable rates and other terms. At times there are also spikes in the price for natural gas and other commodities that increase the liquidity requirements of the Utility operating companies and Entergy Wholesale Commodities. In addition, Entergy’s and the Utility operating companies’ liquidity needs could significantly increase in the event of a hurricane or other weather-related or unforeseen disaster similar to that experienced in Entergy’s service territory with Hurricane Katrina and Hurricane Rita in 2005, Hurricane Gustav and Hurricane Ike in 2008, Hurricane Isaac in 2012, and Hurricane Laura, Hurricane Delta, and Hurricane Zeta in 2020. The occurrence of one or more contingencies, including a delay in regulatory recovery of fuel or purchased power costs or storm restoration costs, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, changes in regulation or governmental policy (including tax and trade policy), or other unknown events, could cause the financing needs of Entergy and its subsidiaries to increase. In addition, accessing the debt capital markets more frequently in these situations may result in an increase in leverage. Material leverage increases could negatively affect the credit ratings of Entergy and the Utility operating companies, which in turn could negatively affect access to the capital markets.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The inability to raise capital on favorable terms, particularly during times of high interest rates, and uncertainty or reduced liquidity in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses. Access to capital markets could be restricted and/or borrowing costs could be increased due to certain sources of debt and equity capital being unwilling to invest in companies that experience extreme weather events, that rely on fossil fuels or offerings to fund fossil fuel projects, or due to risks related to climate change. Events beyond Entergy’s control may create uncertainty that could increase its cost of capital or impair its ability to access the capital markets, including the ability to draw on its bank credit facilities. Entergy and its subsidiaries are unable to predict the degree of success they will have in renewing or replacing their credit facilities as they come up for renewal. Moreover, the size, terms, and covenants of any new credit facilities may not be comparable to, and may be more restrictive than, existing facilities. If Entergy and its subsidiaries are unable to access the credit and capital markets on terms that are reasonable, they may have to delay raising capital, issue shorter-term securities and/or bear an unfavorable cost of capital, which, in turn, could impact their ability to grow their businesses, decrease earnings, significantly reduce financial flexibility and/or limit Entergy Corporation’s ability to sustain its current common stock dividend level.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
A downgrade in Entergy Corporation’s or its subsidiaries’ credit ratings could negatively affect Entergy Corporation’s and its subsidiaries’ ability to access capital and/or could require Entergy Corporation or its subsidiaries to post collateral, accelerate certain payments, or repay certain indebtedness.
There are a number of factors that rating agencies evaluate to arrive at credit ratings for each of Entergy Corporation and the Registrant Subsidiaries, including each Registrant’s regulatory framework, ability to recover costs and earn returns, diversification and financial strength and liquidity. If one or more rating agencies downgrade Entergy Corporation’s, any of the Utility operating companies’, or System Energy’s ratings, particularly below investment grade, borrowing costs would increase, the potential pool of investors and funding sources would likely decrease, and cash or letter of credit collateral demands may be triggered by the terms of a number of commodity contracts, leases, and other agreements.
Most of Entergy Corporation’s and its subsidiaries’ suppliers and counterparties require sufficient creditworthiness to enter into transactions. If Entergy Corporation’s or its subsidiaries’ ratings decline, particularly below investment grade, or if certain counterparties believe Entergy Corporation or the Utility operating companies are losing creditworthiness and demand adequate assurance under fuel, gas, and purchased power contracts, the counterparties may require posting of collateral in cash or letters of credit, prepayment for fuel, gas or purchased power or accelerated payment, or counterparties may decline business with Entergy Corporation or its subsidiaries. At December 31, 2020 based on power prices at that time, Entergy had liquidity exposure of $62 million under the guarantees in compensation-relatedplace supporting Entergy Wholesale Commodities transactions and $6 million of posted cash collateral. In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as of December 31, 2020, Entergy would have been required to provide approximately $30 million of additional cash or letters of credit under some of the agreements. As of December 31, 2020, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $22 million for a $1 per MMBtu increase in gas prices in both the short- and long-term markets.
Recent U.S. tax legislation may materially adversely affect Entergy’s financial condition, results of operations, and cash flows.
The Tax Cuts and Jobs Act of 2017 and CARES Act of 2020 significantly changed the U.S. Internal Revenue Code, including taxation of U.S. corporations, by, among other things, reducing the federal corporate income tax rate, limiting interest deductions, and altering the expensing of capital expenditures. The interpretive
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
guidance issued by the IRS and state tax authorities may be inconsistent with Entergy’s own interpretation and the legislation could be subject to amendments, which could lessen or increase certain impacts of the legislation.
As further described in Note 3 to the financial statements, as a result of amortization of accumulated deferred income taxes and payment of such amounts to customers in 2019, Entergy’s net regulatory liability for income taxes balance is $1.6 billion as of December 31, 2020. Depending on the outcome of IRS examinations or tax positions and elections that Entergy may make, Entergy and the Registrant Subsidiaries may be required to record additional charges or credits to income tax expense. Further, there may be other material effects resulting from the legislation that have not been identified.
See Note 3 to the financial statements for discussion of the effects of the Tax Cuts and Jobs Act on 2018, 2019 and 2020 results of operations and financial condition, the provisions of the Tax Cuts and Jobs Act, and the uncertainties associated with accounting for the Tax Cuts and Jobs Act, and Note 2 to the financial statements for discussion of the regulatory proceedings that have considered the effects of the Tax Cuts and Jobs Act.
Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s, the Utility operating companies’, and System Energy’s results of operations, financial condition, and liquidity.
Entergy and its subsidiaries make judgments regarding the potential tax effects of various transactions and results of operations to estimate their obligations to taxing authorities. These tax obligations include income, franchise, real estate, sales and use, and employment-related taxes. These judgments include provisions for potential adverse outcomes regarding tax positions that have been taken. Entergy and its subsidiaries also estimate their ability to utilize tax benefits, including those in the form of carryforwards for which the benefits have already been reflected in the financial statements. Changes in federal, state, or local tax laws, adverse tax audit results or adverse tax rulings on positions taken by Entergy and its subsidiaries could negatively affect Entergy’s, the Utility operating companies’, and System Energy’s results of operations, financial condition, and liquidity. For further information regarding Entergy’s income taxes, see Note 3 to the financial statements.
Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to complete strategic transactions, is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies, which could materially affect their future prospects, results of operations, and benefits that they anticipate from such transactions.
Entergy and its subsidiaries’ future prospects and results of operations significantly depend on their ability to successfully implement their business strategies, which are subject to business, regulatory, economic, and other risks and uncertainties, many of which are beyond their control. As a result, Entergy and its subsidiaries may be unable to fully achieve the anticipated results of such strategies.
Additionally, Entergy and its subsidiaries have pursued and may continue to pursue strategic transactions including merger, acquisition, divestiture, joint venture, restructuring, or other strategic transactions. For example, Entergy has entered into an agreement to sell its equity interests in the subsidiary that owns the Palisades Nuclear Plant and the decommissioned Big Rock Point Nuclear Power Plant and an agreement to sell the equity interests of Indian Point 1, Indian Point 2, and Indian Point 3, in each case after each of the plants has been shut down and defueled. Also, a significant portion of Entergy’s utility business over the next several years includes the construction and/or purchase of a variety of generating units. These transactions and plans are or may become subject to regulatory approval and other material conditions or contingencies. The failure to complete these transactions or plans or any future strategic transaction successfully or on a timely basis could have an adverse effect on Entergy’s or its subsidiaries’ financial condition or results of operations and the market’s perception of Entergy’s ability to execute its strategy. Further, these transactions, and any completed or future strategic transactions, involve substantial risks, including the following:
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
•acquired businesses or assets may not produce revenues, earnings, or cash flow at anticipated levels;
•acquired businesses or assets could have environmental, permitting, or other problems for which contractual protections prove inadequate;
•Entergy and/or its subsidiaries may assume liabilities that were not disclosed to them, that exceed their estimates, or for which their rights to indemnification from the seller are limited;
•Entergy may experience issues integrating businesses into its internal controls over financial reporting;
•the disposition of a business, including Entergy’s planned exit from the merchant power business, could divert management’s attention from other business concerns;
•Entergy and/or its subsidiaries may be unable to obtain the necessary regulatory or governmental approvals to close a transaction, such approvals may be granted subject to terms that are unacceptable, or Entergy or its subsidiaries otherwise may be unable to achieve anticipated regulatory treatment of any such transaction or acquired business or assets; and
•Entergy or its subsidiaries otherwise may be unable to achieve the full strategic and financial benefits that they anticipate from the transaction, or such benefits may be delayed or may not occur at all.
Entergy and its subsidiaries may not be successful in managing these or any other significant risks that they may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material effect on their business, financial condition or results of operations.
The completion of capital projects, including the construction of power generation facilities, and other capital improvements involve substantial risks. Should such efforts be unsuccessful, the financial condition, results of operations, or liquidity of Entergy and the Utility operating companies could be materially affected.
Entergy’s and the Utility operating companies’ ability to complete capital projects, including the construction of power generation facilities, or make other capital improvements, in a timely manner and within budget is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise, escalating costs for materials, labor, and environmental compliance, and reliance on suppliers for timely and satisfactory performance. Delays in obtaining permits, shortages in materials and qualified labor, levels of public support or opposition, suppliers and contractors not performing as expected or required under their contracts and/or experiencing financial problems that inhibit their ability to fulfill their obligations under contracts, changes in the scope and timing of projects, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in law or regulation, including environmental compliance requirements, and other events beyond the control of the Utility operating companies or the Entergy Wholesale Commodities business may occur that may materially affect the schedule, cost, and performance of these projects. If these projects or other capital improvements are significantly delayed or become subject to cost overruns or cancellation, Entergy and the Utility operating companies could incur additional costs and termination payments, or face increased risk of potential write-off of the investment in the project. In addition, the Utility operating companies could be exposed to higher costs and market volatility, which could affect cash flow and cost recovery, should their respective regulators decline to approve the construction of the project or new generation needed to meet the reliability needs of customers at the lowest reasonable cost.
For further information regarding capital expenditure plans and other uses of capital in connection with capital projects, including the potential construction and/or purchase of additional generation supply sources within the Utility operating companies’ service territory, and as to the Entergy Wholesale Commodities business, see the “Capital Expenditure Plans and Other Uses of Capital” section of Management’s Financial Discussion and Analysis for Entergy and each of the Registrant Subsidiaries.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Failure to attract, retain and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
We rely on a large and changing workforce of team members, including employees, contractors and temporary staffing. Certain events, such as an aging workforce, mismatching of skill sets, failing to appropriately anticipate future workforce needs, or the unavailability of contract resources may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge base, and the time required for skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, and safety costs, may increase. Failure to hire and adequately train replacement employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate the business, especially considering the workforce needs associated with nuclear generation facilities and new skills required to operate a modernized, technology-enabled power grid. If Entergy and its subsidiaries are unable to successfully attract, retain, and manage an appropriately qualified workforce, their results of operations, financial position, and cash flows could be negatively affected.
The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs to fulfill their obligations related to environmental and other matters.
The businesses in which the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business operate are subject to extensive environmental regulation by local, state, and federal authorities. These laws and regulations affect the manner in which the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business conduct their operations and make capital expenditures. These laws and regulations also affect how the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business manage air emissions, discharges to water, wetlands impacts, solid and hazardous waste storage and disposal, cooling and service water intake, the protection of threatened and endangered species, certain migratory birds and eagles, hazardous materials transportation, and similar matters. Federal, state, and local authorities continually revise these laws and regulations, and the laws and regulations are subject to judicial interpretation and to the permitting and enforcement discretion vested in the implementing agencies. Developing and implementing plans for facility compliance with these requirements can lead to capital, personnel, and operation and maintenance expenditures. Violations of these requirements can subject the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. In addition, the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business potentially are subject to liability under these laws for the costs of remediation of environmental contamination of property now or formerly owned or operated by the Utility operating companies, System Energy, and Entergy Wholesale Commodities and of property contaminated by hazardous substances they generate. The Utility operating companies currently are involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future. The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business have incurred shouldand expect to incur significant costs related to environmental compliance.
Emissions of nitrogen and sulfur oxides, mercury, particulates, greenhouse gases, and other regulated air emissions from generating plants potentially are subject to increased regulation, controls, and mitigation expenses. In addition, existing air regulations and programs promulgated by the EPA often are challenged legally, or are revised or withdrawn by the EPA, sometimes resulting in large-scale changes to anticipated regulatory regimes and the resulting need to shift course, both operationally and economically, depending on the nature of the changes. Risks relating to global climate change, initiatives to compel greenhouse gas emission reductions, and water availability issues are discussed below.
Entergy and its subsidiaries may not be deemed prudent; (3) recommendedable to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if Entergy and its subsidiaries fail to obtain, maintain, or comply with any such approval, the operation of its facilities could be
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
stopped or become subject to additional costs. For further information regarding environmental regulation and environmental matters, see the “Regulation of Entergy’s Business– Environmental Regulation” section of Part I, Item 1.
The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs related to reliability standards.
Entergy’s business is subject to extensive and mandatory reliability standards. Such standards, which are established by the NERC, the SERC, and other regional enforcement entities, are approved by the FERC and frequently are reviewed, amended, and supplemented. Failure to comply with such standards could result in the imposition of fines or civil penalties, and potential exposure to third party claims for alleged violations of such standards. The standards, as well as the laws and regulations that govern them, are subject to judicial interpretation and to the enforcement discretion vested in the implementing agencies. In addition to exposure to civil penalties and fines, the Utility operating companies have incurred and expect to incur significant costs related to compliance with new and existing reliability standards, including costs associated with the Utility operating companies’ transmission system and generation assets. In addition, the retail regulators of the Utility operating companies possess the jurisdiction, and in some cases have exercised such jurisdiction, to impose standards governing the reliable operation of the Utility operating companies’ distribution systems, including penalties if these standards are not met. The changes to the reliability standards applicable to the electric power industry are ongoing, and Entergy cannot predict the ultimate effect that the reliability standards will have on its Utility and Entergy Wholesale Commodities businesses.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas usage and otherwise materially affect the Utility operating companies’ results of operations and system reliability.
Temperatures above normal levels in the summer tend to increase electric cooling demand and revenues, and temperatures below normal levels in the winter tend to increase electric and gas heating demand and revenues. As a corollary, mild temperatures in either season tend to decrease energy usage and resulting revenues. Higher consumption levels coupled with seasonal pricing differentials typically cause the Utility operating companies to report higher revenues in the third quarter of the fiscal year than in the other quarters. Extreme weather conditions including hurricanes or tropical storms, flooding events, or ice storms may stress the Utility operating companies’ generation facilities and transmission and distribution systems, resulting in increased maintenance and capital costs (and potential increased financing needs), limits on their ability to meet peak customer demand, increased regulatory oversight, and reduced customer satisfaction. These extreme conditions could have a material effect on the Utility operating companies’ financial condition, results of operations, and liquidity.
Entergy’s electricity sales volumes are affected by a number of factors including weather and economic conditions, trends in energy efficiency, new technologies, and self-generation alternatives, including the willingness and ability of large industrial customers to develop co-generation facilities that greatly reduce their grid demand. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and rarely have a long-lasting effect on Entergy’s operating results. Others, such as the organic turnover of appliances and their replacement with more efficient ones, adoption of newer technologies including smart thermostats, new building codes, distributed energy resources, energy storage, demand side management, and rooftop solar are having a more permanent effect by reducing sales growth rates from historical norms. As a result of these emerging efficiencies and technologies, the Utility operating companies may lose customers or experience lower average use per customer in the residential and commercial classes, and continuing advances have the potential to further limit sales growth in the future. The Utility operating companies also may face competition from other companies offering products and services to Entergy’s customers. Electricity sales to industrial
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
customers, in particular, benefit from steady economic growth and favorable commodity markets; however, industrial sales are sensitive to changes in conditions in the markets in which its customers operate. Negative changes in any of these or other factors, particularly sustained economic downturns or sluggishness, have the potential to result in slower sales growth or sales declines and increased bad debt expense, which could materially affect Entergy’s and the Utility operating companies’ results of operations, financial condition, and liquidity.
The effects of climate change, environmental and regulatory obligations intended to compel greenhouse gas emission reductions or increase clean or renewable energy requirements or to place a price on greenhouse gas emissions, or achieving voluntary climate commitments could materially affect the financial condition, results of operations, and liquidity of Entergy, the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business.
In an effort to address climate change concerns, some federal, state, and local authorities are calling for additional laws and regulations aimed at known or suspected causes of climate change. For example, in response to the United States Supreme Court’s 2007 decision holding that the EPA has authority to regulate emissions of CO2 and other “greenhouse gases” under the Clean Air Act, the EPA, various environmental interest groups, and other organizations focused considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. Since that ruling, the EPA has promulgated regulations controlling greenhouse gas emissions from certain vehicles, and from new, existing, and significantly modified stationary sources of emissions, including electric generating units. As examples of state action, in the Northeast, the Regional Greenhouse Gas Initiative establishes a cap on CO2 emissions from electric power plants and requires generators to purchase emission permits to cover their CO2 emissions, and a similar program has been developed in California. In Louisiana, the Office of the Governor announced the creation of a Climate Initiatives Task Force and issued an executive order that established a path to net-zero emissions by 2050 while the City Council of New Orleans passed a renewable and clean portfolio standard that sets a goal of net-zero emissions by 2040 and absolute zero emissions by 2050. The impact that continued changes in the governmental response to climate change risk will have on existing and pending environmental laws and regulations related to greenhouse gas emissions is currently unclear.
Developing and implementing plans for compliance with greenhouse gas emissions reduction, clean/renewable energy requirements, or for achieving voluntary climate commitments can lead to additional capital, personnel, and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects. The operations of low or non-emitting generating units (such as nuclear units) at lower than expected capacity factors could require increased generation from higher emitting units, thus increasing the company’s greenhouse gas emission rate. Moreover, long-term planning to meet environmental requirements can be negatively impacted and costs may increase to the extent laws and regulations change prior to full implementation. These requirements could, in turn, lead to changes in the planning or operations of balancing authorities or organized markets in areas where the Utility operating companies, System Energy, or Entergy Wholesale Commodities do business. Violations of such requirements may subject Entergy Wholesale Commodities and the Utility operating companies to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. To the extent Entergy believes any of these costs are recoverable in rates, however, additional material rate increases for customers could be resisted by Entergy’s regulators and, in extreme cases, Entergy’s regulators might attempt to deny or defer timely recovery of these costs. Future changes in regulation or policies governing the emission of CO2 and other greenhouse gases or mix of generation sources could (i) result in significant additional costs to Entergy’s utility operating companies, their suppliers or customers, (ii) make some of Entergy’s electric generating units uneconomical to maintain or operate, (iii) result in the early retirement of generation facilities and stranded costs if Entergy’s utility operating companies are unable to fully recover the costs and investment in generation and (iv) could increase the difficulty that Entergy and its utility operating companies have with obtaining or maintaining required environmental regulatory approvals, each of which could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries. In addition, lawsuits have occurred or are reasonably expected against emitters of greenhouse gases alleging that these
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
companies are liable for personal injuries and property damage caused by climate change. These lawsuits may seek injunctive relief, monetary compensation, and punitive damages.
In addition to the regulatory and financial risks associated with climate change discussed above, potential physical risks from climate change include an increase in sea level, wind and storm surge damages, wildfires, wetland and barrier island erosion, risks of flooding and changes in weather conditions, (such as increases in precipitation, drought, or changes in average temperatures), and potential increased impacts of extreme weather conditions or storms. Entergy subsidiaries own assets in, and serve, communities that are at risk from sea level rise, changes in weather conditions, storms, and loss of the protection offered by coastal wetlands. A significant portion of the nation’s oil and gas infrastructure is located in these areas and susceptible to storm damage that could be aggravated by the physical impacts of climate change, which could give rise to fuel supply interruptions and price spikes. Entergy and its subsidiaries also face the risk that climate change could impact the availability and quality of water supply necessary for operations.
These and other physical changes could result in changes in customer demand, increased costs associated with repairing and maintaining generation facilities and transmission and distribution systems resulting in increased maintenance and capital costs (and potential increased financing needs), limits on the Entergy System’s ability to meet peak customer demand, more frequent and longer lasting outages, increased regulatory oversight, and lower customer satisfaction. Also, to the extent that climate change adversely impacts the economic health of a region or results in energy conservation or demand side management programs, it may adversely impact customer demand and revenues. Such physical or operational risks could have a material effect on Entergy’s, Entergy Wholesale Commodities’, System Energy’s, and the Utility operating companies’ financial condition, results of operations, and liquidity.
In September 2020, Entergy voluntarily committed to achieving net zero carbon emissions by 2050. Technology research and development, innovation, and advancement are critical to Entergy’s ability to achieve this commitment. Moreover, Entergy cannot predict the ultimate impact of achieving this objective, or the various implementation aspects, on its system reliability, or its results of operations, financial condition or liquidity.
Continued and future availability and quality of water for cooling, process, and sanitary uses could materially affect the financial condition, results of operations, and liquidity of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business.
Water is a vital natural resource that is also critical to the Utility operating companies’, System Energy’s, and Entergy Wholesale Commodities’ business operations. Entergy’s facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Entergy’s Utility operating companies also own and/or operate hydroelectric facilities. Accordingly, water availability and quality are critical to Entergy’s business operations. Impacts to water availability or quality could negatively impact both operations and revenues.
Entergy secures water through various mechanisms (ground water wells, surface waters intakes, municipal supply, etc.) and operates under the provisions and conditions set forth by the provider and/or regulatory authorities. Entergy also obtains and operates in substantial compliance with water discharge permits issued under various provisions of the Clean Water Act and/or state water pollution control provisions. Regulations and authorizations for both water intake and use and for waste discharge can become more stringent in times of water shortages, low flows in rivers, low lake levels, low groundwater aquifer volumes, and similar conditions. The increased use of water by industry, agriculture, and the population at large, population growth, and the potential impacts of climate change on water resources may cause water use restrictions that affect Entergy and its subsidiaries.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices, which could materially affect Entergy’s and its subsidiaries’ results of operations, financial condition, and liquidity.
To manage near-term financial exposure related to commodity price fluctuations, Entergy and its subsidiaries, including the Utility operating companies and the Entergy Wholesale Commodities business, may enter into contracts to hedge portions of their purchase and sale commitments, fuel requirements, and inventories of natural gas, uranium and its conversion and enrichment, coal, refined products, and other commodities, within established risk management guidelines. As part of this strategy, Entergy and its subsidiaries may utilize fixed- and variable-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. However, Entergy and its subsidiaries normally cover only a portion of the exposure of their assets and positions to market price volatility, and the coverage will vary over time. In addition, Entergy also elects to leave certain volumes during certain years unhedged. To the extent Entergy and its subsidiaries have unhedged positions, fluctuating commodity prices can materially affect Entergy’s and its subsidiaries’ results of operations and financial position.
Although Entergy and its subsidiaries devote a considerable effort to these risk management strategies, they cannot eliminate all the risks associated with these activities. As a result of these and other factors, Entergy and its subsidiaries cannot predict with precision the impact that risk management decisions may have on their business, results of operations, or financial position.
Entergy’s over-the-counter financial derivatives are subject to rules implementing the Dodd-Frank Wall Street Reform and Consumer Protection Act that are designed to promote transparency, mitigate systemic risk, and protect against market abuse. Entergy cannot predict the impact any proposed or not fully-implemented final rules will have on its ability to hedge its commodity price risk or on over-the-counter derivatives markets as a whole, but such rules and regulations could have a material effect on Entergy's risk exposure, as well as reduce market liquidity and further increase the cost of hedging activities.
Entergy has guaranteed or indemnified the performance of a portion of the obligations relating to hedging and risk management activities. Reductions in Entergy’s or its subsidiaries’ credit quality or changes in the market prices of energy commodities could increase the cash or letter of credit collateral required to be posted in connection with hedging and risk management activities, which could materially affect Entergy’s or its subsidiaries’ liquidity and financial position.
The Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties may not meet their obligations, which may materially affect the Utility operating companies and Entergy Wholesale Commodities.
The hedging and risk management practices of the Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties that owe Entergy and its subsidiaries money, energy, or other commodities will not perform their obligations. Currently, some hedging agreements contain provisions that require the counterparties to provide credit support to secure all or part of their obligations to Entergy or its subsidiaries. If the counterparties to these arrangements fail to perform, Entergy or its subsidiaries may enforce and recover the proceeds from the credit support provided and acquire alternative hedging arrangements, which credit support may not always be adequate to cover the related obligations. In such event, Entergy and its subsidiaries might incur losses in addition to amounts, if any, already paid to the counterparties. In addition, the credit commitments of Entergy’s lenders under its bank facilities may not be honored for a variety of reasons, including unexpected periods of financial distress affecting such lenders, which could materially affect the adequacy of its liquidity sources.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.
The performance of the capital markets affects the values of the assets held in trust under Entergy’s pension and postretirement benefit plans. A decline in the market value of the assets may increase the funding requirements relating to Entergy’s benefit plan liabilities and also result in higher benefit costs. As the value of the assets decreases, the “expected return on assets” component of benefit costs decreases, resulting in higher benefits costs. Additionally, asset losses are incorporated into benefit costs over time, thus increasing benefits costs. Volatility in the capital markets has affected the market value of these assets, which may affect Entergy’s planned levels of contributions in the future. Additionally, changes in interest rates affect the liabilities under Entergy’s pension and postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding and recognition of higher liability carrying costs. The funding requirements of the obligations related to the pension benefit plans can also increase as a result of changes in, among other factors, retirement rates, life expectancy assumptions, or Federal regulations. For further information regarding Entergy’s pension and other postretirement benefit plans, refer to the “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” section of Management’s Financial Discussion and Analysis for Entergy and each of its Registrant Subsidiaries and Note 11 to the financial statements.
The litigation environment in the states in which certain Entergy subsidiaries operate poses a significant risk to those businesses.
Entergy and its subsidiaries are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, asbestos, hazardous material and ratepayer matters, and injuries and damages issues, among other matters. The states in which the Utility operating companies operate have proven to be unusually litigious environments. Judges and juries in these states have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. Entergy and its subsidiaries use legal and appropriate means to contest litigation threatened or filed against them, but the litigation environment in these states poses a significant business risk.
Terrorist attacks, cyber attacks, system failures or data breaches of Entergy’s and its subsidiaries’ or our suppliers’ technology systems may adversely affect Entergy’s results of operations.
Entergy and its subsidiaries operate in a business that requires evolving information technology systems that include sophisticated data collection, processing systems, software, network infrastructure, and other technologies that are becoming more complex and may be subject to mandatory and prescriptive reliability and security standards. The functionality of Entergy’s technology systems depends on its own and its suppliers’ and their contractors’ technology. Suppliers’ and their contractors’ technology systems to which Entergy is connected directly or indirectly support a variety of business processes and activities to store sensitive data, including (i) intellectual property, (ii) proprietary business information, (iii) personally identifiable information of customers and employees, and (iv) data with respect to invoicing and the collection of payments, accounting, procurement, and supply chain activities. Any significant failure or malfunction of such information technology systems could result in loss of data or disruptions of operations.
There have been attacks and threats of attacks on energy infrastructure by cyber actors, including those associated with foreign governments. As an operator of critical infrastructure, Entergy and its subsidiaries face heightened risk of an act or threat of terrorism, cyber attacks, and data breaches, whether as a direct or indirect act against one of Entergy’s generation, transmission or distribution facilities, operations centers, infrastructure, or information technology systems used to manage, monitor, and transport power to customers and perform day-to-day business functions. An actual act could affect Entergy’s ability to operate, including its ability to operate the information technology systems and network infrastructure on which it relies to conduct business.
Given the rapid technological advancements of existing and emerging threats, Entergy’s technology systems remain inherently vulnerable despite implementations and enhancements of the multiple layers of security
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
and controls. If Entergy’s or its subsidiaries’ technology systems were compromised and unable to detect or recover in a timely fashion to a normal state of operations, Entergy or its subsidiaries could be unable to perform critical business functions that are essential to the company’s well-being and could result in a loss of its confidential, sensitive, and proprietary information, including personal information of its customers, employees, suppliers, and others in Entergy’s care.
Any such attacks, failures or data breaches could have a material effect on Entergy’s and the Utility operating companies’ business, financial condition, results of operations or reputation. Although we purchase insurance coverage for cyber-attacks or data breaches, such insurance may not be adequate to cover all losses that might arise in connection with these events. Such events may also expose Entergy to an increased risk of litigation (and associated damages and fines).
(Entergy New Orleans)
The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidity.
Gas rates charged to retail gas customers are comprised primarily of purchased gas cost charges, which provide no return or profit to Entergy New Orleans, and distribution charges, which provide a return or profit to the utility. Distribution charges recover fixed costs on a volumetric basis and, thus, are affected by the amount of gas sold to customers. When purchased gas cost charges increase due to higher gas procurement costs, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy New Orleans, which could adversely affect results of operations. Purchased gas cost charges, which comprise most of a customer’s bill and may be adjusted monthly, represent gas commodity costs that Entergy New Orleans recovers from its customers. Entergy New Orleans’s cash flows can be affected by differences between the time period when gas is purchased and the time when ultimate recovery from customers over ten years but stated thatoccurs.
(System Energy)
System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, the LPSC may wantaffiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings.
System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. Charges under the Unit Power Sales Agreement are paid by the Utility operating companies as consideration for their respective entitlements to consider 15 years; (4) allowed for recoveryreceive capacity and energy. The useful economic life of carrying costsGrand Gulf is finite and earningis limited by the terms of its operating license, which expires in November 2044. System Energy’s financial condition depends both on the receipt of payments from the Utility operating companies under the Unit Power Sales Agreement and on the continued commercial operation of Grand Gulf. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on project costs, butequity and capital structure, and a request in a separate proceeding for FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement. The LPSC has also authorized the filing of a prudence complaint at the FERC relating to Grand Gulf operations. Entergy cannot predict the outcome of any of these proceedings nor can it predict whether any outcome could have a reduced rate approximatingmaterial effect on Entergy’s or System Energy’s results of operations, financial condition or liquidity. See Note 2 to the financial statements for further discussion of the proceedings. The Utility operating companies have agreed to implement certain protocols for providing retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
For information regarding the Unit Power Sales Agreement, the sale and leaseback transactions and certain other agreements relating to the Entergy System companies’ support of System Energy, see Notes 5 and 8 to the
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
financial statements and the “Utility - System Energy and Related Agreements” section of Part I, Item 1.
(Entergy Corporation)
As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock.
Entergy Corporation is a holding company with no material revenue generating operations of its own or material assets other than the stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Entergy Corporation’s ability to satisfy its financial obligations, including the payment of interest and principal on its outstanding debt, and to pay dividends on its common stock depends on the payment to it of dividends or distributions by its subsidiaries. The subsidiaries of Entergy Corporation are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make distributions to Entergy Corporation. The ability of such subsidiaries to make payments of dividends or distributions to Entergy Corporation depends on their results of operations and cash flows and other items affecting retained earnings, and on any applicable legal, regulatory, or contractual limitations on subsidiaries’ ability to pay such dividends or distributions. Prior to providing funds to Entergy Corporation, such subsidiaries have financial and regulatory obligations that must be satisfied, including among others, debt service and, in the case of Entergy Utility Holding Company and Entergy Texas, dividends and distributions on preferred securities. Any distributions from the Registrant Subsidiaries other than Entergy Texas and System Energy are paid directly to Entergy Utility Holding Company and are therefore subject to prior payment of distributions on its preferred securities.
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
The COVID-19 Pandemic
See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the COVID-19 pandemic.
February 2021 Winter Storms
See the “February 2021 Winter Storms” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the February 2021 winter storms. Entergy Arkansas’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $10 million. Natural gas purchases for Entergy Arkansas for February 1st through 25th, 2021 are approximately $105 million compared to natural gas purchases for February 2020 of $10 million.
Results of Operations
2020 Compared to 2019
Net Income
Net income decreased $17.7 million primarily due to lower volume/weather, a formula rate plan provision recorded in 2020 to reflect the 2019 historical year netting adjustment, and higher depreciation and amortization expenses, partially offset by higher retail electric price and lower other operation and maintenance expenses. See Note 2 to the financial statements for discussion of the 2019 historical year netting adjustment.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2020 to 2019:
| | | | | |
| Amount |
| (In Millions) |
2019 operating revenues | $2,259.6 | |
Fuel, rider, and other revenues that do not significantly affect net income | (278.5) | |
Volume/weather | (72.2) | |
Retail electric price | 57.4 | |
Return of unprotected excess accumulated deferred income taxes to customers | 118.2 | |
2020 operating revenues | $2,084.5 | |
Entergy Arkansas’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The volume/weather variance is primarily due to a decrease of 1,069 GWh, or 5%, in billed electricity usage, including decreased commercial and industrial usage as a result of the COVID-19 pandemic, and the effect of less favorable weather on residential and commercial sales, partially offset by an increase in residential usage as a
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
result of the COVID-19 pandemic. See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the COVID-19 pandemic.
The retail electric price variance is primarily due to the $56.5 million annual formula rate plan increase related to the 2020 projected test year included in the 2019 formula rate plan filing effective with the first billing cycle of January 2020. See Note 2 to the financial statements for further discussion of the formula rate plan filing.
The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through a tax adjustment rider beginning in April 2018. In 2020, $8.1 million was returned to customers as compared to $126.3 million in 2019. There is no effect on net income as the reduction in operating revenues in each period was offset by a reduction in income tax expense. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
Other Income Statement Variances
Nuclear refueling outage expenses decreased primarily due to the amortization of lower costs associated with the most recent outages as compared to previous outages.
Other operation and maintenance expenses decreased primarily due to:
•a decrease of $18.3 million in nuclear generation expenses primarily due to lower nuclear labor costs, including contract labor, in part as a result of the COVID-19 pandemic;
•a decrease of $13.2 million in non-nuclear generation expenses primarily due to lower long-term service agreement expenses;
•an $11.2 million write-off in 2019 of specific costs related to the potential construction of scrubbers at the White Bluff plant. See Note 2 to the financial statements for discussion of the write-off;
•higher nuclear insurance refunds of $7.8 million;
•a decrease of $5.9 million primarily due to contract costs in 2019 related to initiatives to explore new customer products and services; and
•a decrease of $5.8 million in energy efficiency costs.
The decrease was partially offset by the effects of recording in 2019 a final judgment to resolve claims in the ANO damages case against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $11.9 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expense. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Other income increased primarily due to changes in decommissioning trust fund investment activity.
Other regulatory credits - net for 2020 includes a provision of $43.5 million to reflect the 2019 historical year netting adjustment included in the APSC’s December 2020 order in the 2020 formula rate plan proceeding. See Note 2 to the financial statements for discussion of the 2020 formula rate plan proceeding.
The effective income tax rates were 16.3% for 2020 and (21.6%) for 2019. The difference in the effective income tax rate versus the federal statutory rate of 21% for 2019 was primarily due to the amortization of excess accumulated deferred income taxes. See Notes 2 and 3 to the financial statements for a discussion of the effects and regulatory activity regarding the Tax Cuts and Jobs Act. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2019 Compared to 2018
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 21, 2020, for discussion of results of operations for 2019 compared to 2018.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2020, 2019, and 2018 were as follows:
| | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 | |
| (In Thousands) |
Cash and cash equivalents at beginning of period | $3,519 | | | $119 | | | $6,216 | | |
| | | | | | |
Net cash provided by (used in): | | | | | | |
Operating activities | 659,818 | | | 677,766 | | | 211,825 | | |
Investing activities | (795,709) | | | (676,293) | | | (688,727) | | |
Financing activities | 324,500 | | | 1,927 | | | 470,805 | | |
Net increase (decrease) in cash and cash equivalents | 188,609 | | | 3,400 | | | (6,097) | | |
| | | | | | |
Cash and cash equivalents at end of period | $192,128 | | | $3,519 | | | $119 | | |
2020 Compared to 2019
Operating Activities
Net cash flow provided by operating activities decreased $17.9 million in 2020 primarily due to:
•the timing of recovery of fuel and purchased power costs;
•lower collections of receivables from customers, in part due to the COVID-19 pandemic; and
•the timing of payments to vendors.
The decrease was partially offset by:
•a decrease in the return of unprotected excess accumulated deferred income taxes to customers in 2020 as compared to 2019. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act;
•$25 million in proceeds received from the DOE in 2020 resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
•a decrease of $15.8 million in pension contributions in 2020. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Investing Activities
Net cash flow used in investing activities increased $119.4 million in 2020 primarily due to:
•an increase of $79.5 million in storm spending;
•an increase of $47.3 million in non-nuclear generation construction expenditures primarily due to increased spending on various projects in 2020;
•an increase of $39.4 million in nuclear construction expenditures primarily as a result of work performed in 2020 on various ANO 2 outage projects;
•an increase of $38.5 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and service deliveries, and the timing of cash payments during the nuclear fuel cycle; and
•an increase of $30.3 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of Entergy Arkansas’s distribution system, including increased spending on advanced metering infrastructure.
The increase was partially offset by:
•a decrease of $56 million in transmission construction expenditures primarily due to a lower scope of work performed in 2020 as compared to 2019; and
•$55 million in proceeds received from the DOE in 2020 resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.
Financing Activities
Net cash flow provided by financing activities increased $322.6 million in 2020 primarily due to:
•issuances of $100 million of 4.0% Series mortgage bonds in March 2020 and $675 million of 2.65% Series mortgage bonds in September 2020;
•money pool activity;
•a decrease of $41.6 million in net long-term repayments in 2020 on the Entergy Arkansas nuclear fuel company variable interest entity credit facility; and
•a decrease of $20 million in common equity distributions in 2020 in order to maintain Entergy Arkansas’s capital structure.
The increase was partially offset by:
•the issuance of $350 million of 4.20% Series mortgage bonds in March 2019;
•the repayment in October 2020 of $200 million of 4.90% Series mortgage bonds due December 2052; and
•the repayment in October 2020 of $125 million of 4.75% Series mortgage bonds due June 2063.
Decreases in Entergy Arkansas’s payable to the money pool are a use of cash flow, and Entergy Arkansas’s payable to the money pool decreased by $21.6 million in 2020 compared to decreasing by $161.1 million in 2019. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
See Note 5 to the financial statements for further details of long-term debt.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2019 Compared to 2018
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 21, 2020, for discussion of operating, investing, and financing cash flow activities for 2019 compared to 2018.
Capital Structure
Entergy Arkansas’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio is primarily due to the net issuances of long-term debt in 2020.
| | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
Debt to capital | 54.8 | % | | 53.0 | % |
Effect of excluding the securitization bonds | — | % | | — | % |
Debt to capital, excluding securitization bonds (a) | 54.8 | % | | 53.0 | % |
Effect of subtracting cash | (1.2 | %) | | — | % |
Net debt to net capital, excluding securitization bonds (a) | 53.6 | % | | 53.0 | % |
(a)Calculation excludes the securitization bonds, which are non-recourse to Entergy Arkansas.
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because the securitization bonds, which have been repaid as of December 31, 2020, were non-recourse to Entergy Arkansas, as more fully described in Note 5 to the financial statements. Entergy Arkansas also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because net debt indicates Entergy Arkansas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Arkansas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also acknowledgingmaintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing distributions, Entergy Arkansas may receive equity contributions to maintain its capital structure.
Uses of Capital
Entergy Arkansas requires capital resources for:
•construction and other capital investments;
•debt maturities or retirements;
•working capital purposes, including the financing of fuel and purchased power costs; and
•distribution and interest payments.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| 2021 | | 2022 | | 2023 |
| (In Millions) |
Planned construction and capital investment: | | | | | |
Generation | $340 | | | $355 | | | $430 | |
Transmission | 40 | | | 45 | | | 190 | |
Distribution | 95 | | | 255 | | | 420 | |
Utility Support | 105 | | | 80 | | | 75 | |
Total | $580 | | | $735 | | | $1,115 | |
Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2022-2023 | | 2024-2025 | | After 2025 | | Total |
| (In Millions) |
Long-term debt (a) | $611 | | | $543 | | | $581 | | | $4,713 | | | $6,448 | |
Operating leases (b) | $14 | | | $21 | | | $15 | | | $11 | | | $61 | |
Finance leases (b) | $3 | | | $5 | | | $3 | | | $2 | | | $13 | |
Purchase obligations (c) | $452 | | | $618 | | | $509 | | | $3,882 | | | $5,461 | |
(a)Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.
(b)Lease obligations are discussed in Note 10 to the financial statements.
(c)Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Arkansas, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which are discussed in Note 8 to the financial statements.
In addition to the contractual obligations given above, Entergy Arkansas currently expects to contribute approximately $66.6 million to its qualified pension plans and approximately $517 thousand to its other postretirement health care and life insurance plans in 2021, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations, Entergy Arkansas has $252 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Arkansas includes specific investments in renewables such as the Searcy Solar Facility, Walnut Bend Solar Facility, and West Memphis Solar Facility; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including advanced meters and related investments; resource planning, including potential generation and renewables projects; system improvements; investments in ANO 1 and 2; software and security; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt maturities in Note 5 to the financial statements.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Arkansas pays distributions from its earnings at a percentage determined monthly.
Renewables
Searcy Solar Facility
In March 2019, Entergy Arkansas announced that it signed an agreement for the purchase of an approximately 100 MW solar energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. The purchase is contingent upon, among other things, obtaining necessary approvals from applicable federal and state regulatory and permitting agencies. The project is being constructed by a subsidiary of NextEra Energy Resources. Entergy Arkansas will purchase the facility upon mechanical completion and after the other purchase contingencies have been met. Closing is expected to occur by the end of 2021. In May 2019, Entergy Arkansas filed a petition with the APSC seeking a finding that the LPSC may consider ordering no return;transaction is in the public interest and (5) indicatedrequesting all necessary approvals. In September 2019 other parties filed testimony largely supporting the resource acquisition but disputing Entergy Arkansas’s proposed method of cost recovery. Entergy Arkansas filed its rebuttal testimony in October 2019. In February 2020, Entergy Arkansas, the Attorney General, and the APSC general staff filed a partial settlement agreement asking the APSC to approve, based on the record in the proceeding, all issues except certain issues that are submitted to the APSC for determination. In April 2020 the APSC issued an order approving Entergy Louisiana should be directedArkansas’s acquisition of the Searcy Solar facility as being in the public interest, but declined to securitize project costs, if legally feasibleapprove Entergy Arkansas’s preferred cost recovery rider mechanism, finding instead, based on the particular facts and circumstances presented, that the formula rate plan rider was a sufficient recovery mechanism for this resource.
Walnut Bend Solar Facility
In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 100 MW Walnut Bend Solar Facility is in the public interest. Entergy Arkansas requested a decision by the APSC by June 15, 2021 and primarily requests cost recovery through the formula rate plan rider. A procedural schedule was established with a hearing scheduled in April 2021. Closing is expected to occur in 2022.
West Memphis Solar Facility
In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 180 MW West Memphis Solar Facility is in the public interest. Entergy Arkansas requested a decision by the APSC by September 7, 2021 and primarily requests cost recovery through the formula rate plan rider. Closing is expected to occur in 2023.
Sources of Capital
Entergy Arkansas’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Entergy Arkansas may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest rates are favorable.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
All debt and common and preferred membership interest issuances by Entergy Arkansas require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in Entergy Arkansas’s bond indentures and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Arkansas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| | | | | | | | | | | | | | | | | | | | |
2020 | | 2019 | | 2018 | | 2017 |
(In Thousands) |
$3,110 | | ($21,634) | | ($182,738) | | ($166,137) |
See Note 4 to the financial statements for a description of the money pool.
Entergy Arkansas has a credit facility in the amount of $150 million scheduled to expire in September 2024. Entergy Arkansas also has a $25 million credit facility scheduled to expire in April 2021. The $150 million credit facility includes fronting commitments for the issuance of letters of credit against $5 million of the borrowing capacity of the facility. As of December 31, 2020, there were no cash borrowings and no letters of credit outstanding under the credit facilities. In addition, Entergy Arkansas is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2020, a $1 million letter of credit was outstanding under Entergy Arkansas’s uncommitted letter of credit facility. See Note 4 to the financial statements for further discussion of the credit facilities.
The Entergy Arkansas nuclear fuel company variable interest entity has a credit facility in the amount of $80 million scheduled to expire in September 2022. As of December 31, 2020, $12.2 million in loans were outstanding under the credit facility for the Entergy Arkansas nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of the nuclear fuel company variable interest entity credit facility.
Entergy Arkansas obtained authorization from the FERC through July 2022 for short-term borrowings not to exceed an aggregate amount of $250 million at any time outstanding and borrowings by its nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of Entergy Arkansas’s short-term borrowing limits. The long-term securities issuances of Entergy Arkansas are limited to amounts authorized by the FERC. The APSC has concurrent jurisdiction over Entergy Arkansas’s first mortgage bond/secured issuances. Entergy Arkansas has obtained long-term financing authorization from the FERC that extends through July 2022. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2022.
State and Local Rate Regulation and Fuel-Cost Recovery
Retail Rates
2018 Formula Rate Plan Filing
In July 2018, Entergy Arkansas filed with the APSC its 2018 formula rate plan filing to set its formula rate for the 2019 calendar year. The filing showed Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2019 test period to be below the formula rate plan bandwidth. Additionally, the filing included the first netting adjustment under the current formula rate plan for the historical test year 2017, reflecting the change in formula rate plan revenues associated with actual 2017 results when compared to the allowed rate of return on equity. The filing included a projected $73.4 millionrevenue deficiency for 2019 and a $95.6 million revenue deficiency for the 2017 historical test year, for a total revenue requirement of $169 million for this filing. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to four percent of total revenue, which originally was $65.4 million but was increased to $66.7 million based upon the APSC staff’s updated calculation of 2018 revenue. In October 2018, Entergy Arkansas and the parties to the proceeding filed joint motions to approve a partial settlement agreement as to certain factual issues and agreed to brief contested legal issues. In November 2018 the APSC held a hearing and was briefed on a contested legal issue. In December 2018 the APSC issued a decision related to the initial legal brief, approved the partial settlement agreement and $66.7 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan, with updated rates going into effect for the first billing cycle of January 2019.
2019 Formula Rate Plan Filing
In July 2019, Entergy Arkansas filed with the APSC its 2019 formula rate plan filing to set its formula rate for the 2020 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2020 and a netting adjustment for the historical year 2018. The total proposed formula rate plan rider revenue change designed to produce a target rate of return on common equity of 9.75% is $15.3 million, which is based upon a deficiency of approximately $61.9 million for the 2020 projected year, netted with a credit of approximately $46.6 million in the 2018 historical year netting adjustment. During 2018 Entergy Arkansas experienced higher-than expected sales volume, and actual costs were lower than forecasted. These changes, coupled with a reduced income tax rate resulting from the Tax Cuts and Jobs Act, resulted in the credit for the historical year netting adjustment. In the fourth quarter 2018, Entergy Arkansas recorded a provision of $35.1 million that reflected the estimate of the historical year netting adjustment that was expected to be included in the 2019 filing. In 2019, Entergy Arkansas recorded additional provisions totaling $11.5 million to reflect the updated estimate of the historical year netting adjustment included in the 2019 filing. In October 2019 other parties in the proceeding filed their errors and objections requesting certain adjustments to Entergy Arkansas’s filing that would reduce or eliminate Entergy Arkansas’s proposed revenue change. Entergy Arkansas filed its response addressing the requested adjustments in October 2019. In its response, Entergy Arkansas accepted certain of the adjustments recommended by the General Staff of the APSC that would reduce the proposed formula rate plan rider revenue change to $14 million. Entergy Arkansas disputed the remaining adjustments proposed by the parties. In October 2019, Entergy Arkansas filed a unanimous settlement agreement with the other parties in the proceeding seeking APSC approval of a revised total formula rate plan rider revenue change of $10.1 million. In its July 2019 formula rate plan filing, Entergy Arkansas proposed to recover an $11.2 million regulatory asset, amortized over five years, associated with specific costs related to the potential construction of scrubbers at the White Bluff plant. Although Entergy Arkansas does not concede that the regulatory asset lacks merit, for purposes of reaching a settlement on the total formula rate plan rider amount, Entergy Arkansas agreed not to include the White Bluff scrubber regulatory asset cost in the 2019 formula rate plan filing or future filings. Entergy Arkansas recorded a write-off in 2019 of the $11.2 million White Bluff scrubber regulatory asset. In December 2019 the APSC approved the settlement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2020.
2020 Formula Rate Plan Filing
In July 2020, Entergy Arkansas filed with the APSC its 2020 formula rate plan filing to set its formula rate for the 2021 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2021, as amended through subsequent filings in the proceeding, and a netting adjustment for the historical year 2019. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2021 projected year is 8.22% resulting in a revenue deficiency of $64.3 million. The earned rate of return on common equity for the 2019 historical year was 9.07% resulting in a $23.9 million netting adjustment. The total proposed revenue change for the 2021 projected year and 2019 historical year netting adjustment was $88.2 million. By operation of the formula rate plan, Entergy Arkansas’s recovery of the revenue requirement is subject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $74.3 million. In October 2020 other parties in the proceeding filed their errors
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
and objections recommending certain adjustments, and Entergy Arkansas filed responsive testimony disputing these adjustments. As part of the formula rate plan tariff the calculation for the revenue constraint was updated based on actual revenues which had the effect of reducing the initially-proposed $74.3 million revenue requirement increase to $72.6 million. In October 2020, Entergy Arkansas filed with the APSC a unanimous settlement agreement reached with the other parties that resolved all but one issue. As a result of the settlement agreement, Entergy Arkansas’s requested revenue increase was $68.4 million, including a $44.5 million increase for the projected 2021 year and a $23.9 million netting adjustment. The remaining issue litigated concerned the methodology used to calculate the netting adjustment within the formula rate plan. In December 2020 the APSC issued an order rejecting the netting adjustment method used by Entergy Arkansas. Applying the approach ordered by the APSC changed the netting adjustment for the 2019 historical year from a $23.9 million deficiency to $43.5 million excess. Overall, the decision reduced Entergy Arkansas’s revenue adjustment for 2021 to $1 million. In December 2020, Entergy Arkansas filed a petition for rehearing of the APSC’s decision, and in January 2021 the APSC granted further consideration of Entergy Arkansas’s petition. Based on the progress of the proceeding to date, in December 2020, Entergy Arkansas recorded a regulatory liability of $43.5 million to reflect the netting adjustment for 2019, as included in the APSC’s December 2020 order, which would be returned to customers in 2021. Also with the formula rate plan filing, Entergy Arkansas is requesting an extension of the formula rate plan rider for a second five-year term. Decisions by the APSC on the netting adjustment rehearing and the extension are expected in March 2021.
Internal Restructuring
In November 2017, Entergy Arkansas filed an application with the APSC seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy Arkansas to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. In July 2018, Entergy Arkansas filed a settlement, reached by all parties in the APSC proceeding, resolving all issues. The APSC approved the settlement agreement and restructuring in August 2018. Pursuant to the settlement agreement, Entergy Arkansas will credit retail customers $39.6 million over six years, beginning in 2019. Entergy Arkansas also received the required FERC and NRC approvals.
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Production Cost Allocation Rider
The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section in Note 2 to the financial statements.
Energy Cost Recovery Rider
Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly customer bills. The rider utilizes the prior calendar-year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over- or under-recovery, including carrying charges, of the energy costs for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs.
In January 2014, Entergy Arkansas filed a motion with the APSC relating to its upcoming energy cost rate redetermination filing that was made in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude from the redetermination of its 2014 energy cost rate $65.9 million of incremental fuel and replacement energy costs incurred in 2013 as a result of the ANO stator incident. Entergy Arkansas requested that the APSC authorize Entergy Arkansas to retain that amount in its deferred fuel balance, with recovery to be reviewed in a later period after more information was available regarding various claims associated with the ANO stator incident. In February 2014 the APSC approved Entergy Arkansas’s request to retain that amount in its deferred fuel balance. In July 2017, Entergy Arkansas filed for a change in rates pursuant to its formula rate plan rider. In that proceeding, the APSC approved a settlement agreement agreed upon by the parties, including a provision that requires Entergy Arkansas to initiate a regulatory proceeding for the purpose of recovering funds currently withheld from rates and related to the stator incident, including the $65.9 million of deferred fuel and purchased energy costs previously noted, subject to certain timelines and conditions set forth in the settlement agreement. See the “ANO Damage, Outage, and NRC Reviews” section in Note 8 to the financial statements for further discussion of the ANO stator incident.
In March 2017, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01164 per kWh to $0.01547 per kWh. The APSC staff filed testimony in March 2017 recommending that the redetermined rate be implemented with the first billing cycle of April 2017 under the normal operation of the tariff. Accordingly, the redetermined rate went into effect on March 31, 2017 pursuant to the tariff. In July 2017 the Arkansas Attorney General requested additional information to support certain of the costs included in Entergy Arkansas’s 2017 energy cost rate redetermination.
In March 2018, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Arkansas’s annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of the redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for suspension were questions pertaining to how Entergy Arkansas forecasted sales and potential implications of the Tax Act. Entergy Arkansas replied to the Attorney General’s filing and stated that, to the extent there are questions pertaining to its load forecasting or the operation of the energy cost recovery rider, those issues exceed the scope of the instant rate redetermination. Entergy Arkansas also stated that potential effects of the Tax Act are appropriately considered in the APSC’s separate proceeding regarding potential implications of the tax law. The APSC general staff filed a reply to the Attorney General’s filing and agreed that Entergy Arkansas’s filing complied with the terms of the energy cost recovery rider. The redetermined rate became effective with the first billing cycle of April 2018. Subsequently in April 2018 the APSC issued an order declining to suspend Entergy Arkansas’s energy cost recovery rider rate and declining to require further investigation at that time of the issues suggested by the Attorney General in the
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
proceeding. Following a period of discovery, the Attorney General filed a supplemental response in October 2018 raising new issues with Entergy Arkansas’s March 2018 rate redetermination and asserting that $45.7 million of the increase should be collected subject to refund pending further investigation. Entergy Arkansas filed to dismiss the Attorney General’s supplemental response, the APSC general staff filed a motion to strike the Attorney General’s filing, and the Attorney General filed a supplemental response disputing Entergy Arkansas and the APSC staff’s filing. Applicable APSC rules and processes authorize its general staff to initiate periodic audits of Entergy Arkansas’s energy cost recovery rider. In late-2018 the APSC general staff notified Entergy Arkansas it has initiated an audit of the 2017 fuel costs. The time in which the audit will be complete is uncertain at this time.
In March 2019, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01882 per kWh to $0.01462 per kWh and became effective with the first billing cycle in April 2019. In March 2019 the Arkansas Attorney General filed a response to Entergy Arkansas’s annual adjustment and included with its filing a motion for investigation of alleged overcharges to customers in connection with the FERC’s October 2018 order in the opportunity sales proceeding. Entergy Arkansas filed its response to the Attorney General’s motion in April 2019 in which Entergy Arkansas stated its intent to initiate a proceeding to address recovery issues related to the October 2018 FERC order. In May 2019, Entergy Arkansas initiated the opportunity sales recovery proceeding, discussed below, and requested that the APSC establish that proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC October 2018 order and related FERC orders in the opportunity sales proceeding. In June 2019 the APSC granted Entergy Arkansas’s request and also denied the Attorney General’s motion in the energy cost recovery proceeding seeking an investigation into Entergy Arkansas’s annual energy cost recovery rider adjustment and referred the evaluation of such matters to the opportunity sales recovery proceeding.
In March 2020, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01462 per kWh to $0.01052 per kWh. The redetermined rate became effective with the first billing cycle in April 2020 through the normal operation of the tariff.
Opportunity Sales Proceeding
In June 2009 the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third quarter 2010,parties: (a) violated the provisions of the System Agreement that allocated the energy generated by Entergy System resources; (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity; and (c) violated the provision of the System Agreement that prohibited sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challenged sales made beginning in 2002 and requested refunds. In July 2009 the Utility operating companies filed a response to the complaint arguing among other things that the System Agreement contemplates that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company. The FERC subsequently ordered a hearing in the proceeding.
After a hearing, the ALJ issued an initial decision in December 2010. The ALJ found that the System Agreement allowed for Entergy Arkansas to make the sales to third parties but concluded that the sales should be accounted for in the same manner as joint account sales. The ALJ concluded that “shareholders” should make refunds of the damages to the Utility operating companies, along with interest. Entergy disagreed with several aspects of the ALJ’s initial decision and in January 2011 filed with the FERC exceptions to the decision.
The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith. The FERC found, however, that the System Agreement does not provide authority for an individual Utility operating company to allocate the energy associated
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
with such opportunity sales as part of its load but provides a different allocation authority. The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement. The FERC in its decision established further hearing procedures to quantify the effect of repricing the opportunity sales in accordance with the FERC’s June 2012 decision. The hearing was held in May 2013 and the ALJ issued an initial decision in August 2013. The LPSC, the APSC, the City Council, and FERC staff filed briefs on exceptions and/or briefs opposing exceptions. Entergy filed a brief on exceptions requesting that the FERC reverse the initial decision and a brief opposing certain exceptions taken by the LPSC and FERC staff.
In April 2016 the FERC issued orders addressing requests for rehearing filed in July 2012 and the ALJ’s August 2013 initial decision. The first order denied Entergy’s request for rehearing and affirmed the FERC’s earlier rulings that Entergy’s original methodology for allocating energy costs to the opportunity sales was incorrect and, as a result, Entergy Arkansas must make payments to the other Utility operating companies to put them in the same position that they would have been in absent the incorrect allocation. The FERC clarified that interest should be included with the payments. The second order affirmed in part, and reversed in part, the rulings in the ALJ’s August 2013 initial decision regarding the methodology that should be used to calculate the payments Entergy Arkansas is to make to the other Utility operating companies. The FERC affirmed the ALJ’s ruling that a full re-run of intra-system bills should be performed but required that methodology be modified so that the sales have the same priority for purposes of energy allocation as joint account sales. The FERC reversed the ALJ’s decision that any payments by Entergy Arkansas should be reduced by 20%. The FERC also reversed the ALJ’s decision that adjustments to other System Agreement service schedules and excess bandwidth payments should not be taken into account when calculating the payments to be made by Entergy Arkansas. The FERC held that such adjustments and excess bandwidth payments should be taken into account but ordered further proceedings before an ALJ to address whether a cap on any reduction due to bandwidth payments was necessary and to implement the other adjustments to the calculation methodology.
In May 2016, Entergy Services filed a request for rehearing of the FERC’s April 2016 order arguing that payments made by Entergy Arkansas should be reduced as a result of the timing of the LPSC’s approval of certain contracts. Entergy Services also filed a request for clarification and/or rehearing of the FERC’s April 2016 order addressing the ALJ’s August 2013 initial decision. The APSC and the LPSC also filed requests for rehearing of the FERC’s April 2016 order. In September 2017 the FERC issued an order denying the request for rehearing on the issue of whether any payments by Entergy Arkansas to the other Utility operating companies should be reduced due to the timing of the LPSC’s approval of Entergy Arkansas’s wholesale baseload contract with Entergy Louisiana. In November 2017 the FERC issued an order denying all of the remaining requests for rehearing of the April 2016 order. In November 2017, Entergy Services filed a petition for review in the D.C. Circuit of the FERC’s orders in the first two phases of the opportunity sales case. In December 2017 the D.C. Circuit granted Entergy Services’ request to hold the appeal in abeyance pending final resolution of the related proceeding before the FERC. In January 2018 the APSC and the LPSC filed separate petitions for review in the D.C. Circuit, and the D.C. Circuit consolidated the appeals with Entergy Services’ appeal.
The hearing required by the FERC’s April 2016 order was held in May 2017. In July 2017 the ALJ issued an initial decision addressing whether a cap on any reduction due to bandwidth payments was necessary and whether to implement the other adjustments to the calculation methodology. In August 2017 the Utility operating companies, the LPSC, the APSC, and FERC staff filed individual briefs on exceptions challenging various aspects of the initial decision. In September 2017 the Utility operating companies, the LPSC, the APSC, the MPSC, the City Council, and FERC staff filed separate briefs opposing exceptions taken by various parties.
Based on testimony previously submitted in the case and its assessment of the April 2016 FERC orders, in the first quarter 2016, Entergy Arkansas recorded a liability of $87 million, which included interest, for its estimated increased costs and payment to the other Utility operating companies, and a deferred fuel regulatory asset of $75 million. Following its assessment of the course of the proceedings, including the FERC’s denial of rehearing in
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
November 2017 described above, in the fourth quarter 2017, Entergy Arkansas recorded an additional liability of $35 million and a regulatory asset of $31 million.
In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to cap the reduction in Entergy Arkansas’s payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ’s decision that Grand Gulf sales from January through September 2000 should be included in the calculation of Entergy Arkansas’s payment. The FERC affirmed on other grounds the ALJ’s rejection of the LPSC’s claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.
In December 2018, Entergy made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. The December 2018 compliance filing is pending FERC action. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:
| | | | | | | | | | | |
| Total refunds including interest |
| Payment/(Receipt) |
| (In Millions) |
| Principal | Interest | Total |
Entergy Arkansas | $68 | $67 | $135 |
Entergy Louisiana | ($30) | ($29) | ($59) |
Entergy Mississippi | ($18) | ($18) | ($36) |
Entergy New Orleans | ($3) | ($4) | ($7) |
Entergy Texas | ($17) | ($16) | ($33) |
Entergy Arkansas previously recognized a regulatory asset with a balance of $116 million as of December 31, 2018 for a portion of the payments due as a result of this proceeding.
As described above, the FERC’s opportunity sales orders have been appealed to the D.C. Circuit. In February 2020 all of the appeals were consolidated and in April 2020 the D.C. Circuit established a briefing schedule. Briefing was completed in September 2020 and oral argument was heard in December 2020.
In February 2019 the LPSC filed a new complaint relating to two issues that were raised in the opportunity sales proceeding, but that, in its October 2018 order, the FERC held were outside the scope of the proceeding. In March 2019, Entergy Services filed an answer and motion to dismiss the new complaint. In November 2019 the FERC issued an order denying the LPSC’s complaint. The order concluded that the settlement agreement approved by the FERC in December 2015 terminating the System Agreement barred the LPSC’s new complaint. In December 2019 the LPSC requested rehearing of the FERC’s November 2019 order, and in July 2020 the FERC issued an order dismissing the LPSC’s request for rehearing. In September 2020 the LPSC appealed to the D.C. Circuit the FERC’s orders dismissing the new opportunity sales complaint. In November 2020 the D.C. Circuit issued an order establishing that briefing will occur in January 2021 through April 2021.
In May 2019, Entergy Arkansas filed an application and supporting testimony with the APSC requesting approval of a special rider tariff to recover the costs of these payments from its retail customers over a 24-month period. The application requested that the APSC approve the rider to take effect within 30 days or, if suspended by the APSC as allowed by commission rule, approve the rider to take effect in the first billing cycle of the first month occurring 30 days after issuance of the APSC’s order approving the rider. In June 2019 the APSC suspended
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Arkansas’s tariff and granted Entergy Arkansas’s motion asking the APSC to establish the proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC’s October 2018 order and related FERC orders in the opportunity sales proceeding. In January 2020 the APSC adopted a procedural schedule with a hearing in April 2020. In January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed a joint motion seeking to dismiss Entergy Arkansas’s application alleging that the APSC, in a prior proceeding, ruled on the issues addressed in the application and determined that Entergy Arkansas’s requested relief violates the filed rate doctrine and the prohibition against retroactive ratemaking. Entergy Arkansas responded to the joint motion in February 2020 rebutting these arguments, including demonstrating that the claims in this proceeding differ substantially from those the APSC addressed previously and that the payment resulting from a FERC tariff violation for which Entergy Arkansas seeks retail cost recovery in this proceeding differs materially from the refunds resulting from a FERC tariff amendment that the APSC previously rejected on filed rate doctrine and the retroactive ratemaking grounds. In addition, in January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed testimony opposing the recovery by Entergy Arkansas of the opportunity sales payment but also claiming that certain components of the payment should be segregated and refunded to customers. In March 2020, Entergy Arkansas filed rebuttal testimony.
In July 2020 the APSC issued a decision finding that Entergy Arkansas’s application is not in the public interest. The order also directed Entergy Arkansas to refund to its retail customers within 30 days of the order the FERC-determined over-collection of $13.7 million, plus interest, associated with a recalculated bandwidth remedy. In addition to these primary findings, the order also denied the Attorney General’s request for Entergy Arkansas to prepare a compliance filing detailing all of the retail impacts from the opportunity sales and denied a request by the Arkansas Electric Energy Consumers to recalculate all costs using the revised responsibility ratio. Entergy Arkansas filed a motion for temporary stay of the 30-day requirement to allow Entergy Arkansas a reasonable opportunity to seek rehearing of the APSC order, but in July 2020 the APSC denied Entergy Arkansas’s request for a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas’s stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. In September 2020, Entergy Arkansas filed a complaint in the U. S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments. In October 2020 the APSC filed a motion to dismiss Entergy Arkansas’s complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court scheduled a hearing for February 26, 2021 regarding issues addressed in the pre-trial conference report.
Net Metering Legislation
An Arkansas law was enacted effective July 2019 that, among other things, expands the definition of a “net metering customer” to include two additional types of customers: (1) customers that lease net metering facilities, subject to certain leasing arrangements, and (2) government entities or other entities exempt from state and federal income taxes that enter into a service contract for a net metering facility. The latter provision would allow eligible entities, many of whom are small and large general service customers, to purchase renewable energy directly from third party providers and receive bill credits for these purchases. The APSC was given authority under this law to address certain matters, such as cost shifting and the appropriate compensation for net metered energy and has initiated proceedings for this purpose. Because of the size and number of customers eligible under this new law, there is a risk of loss of load and the shifting of costs to customers. A hearing was held in December 2019, with utilities, cooperatives, the Arkansas Attorney General, industrial customers, and Entergy Arkansas advocating the need for establishment of a reasonable rate structure that takes into account impacts to non-net metering customers; an additional hearing was conducted in February 2020 for purposes of public comment only. The APSC issued an order in June 2020, and in July 2020 several parties, including Entergy Arkansas, filed for rehearing on multiple
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
grounds, including for the reasons that it imposes an unreasonable rate structure and allows facilities to net meter that do not meet the statutory definition of net metering facilities. After granting the rehearing requests, the APSC issued an order in September 2020 largely upholding its June 2020 order. In October 2020, Entergy Arkansas and several other parties filed an appeal of the APSC’s September 2020 order.
Separately, as directed by the APSC general staff, the APSC opened a proceeding to compel utilities to amend their net metering tariffs to incorporate the provisions of the legislation that the APSC general staff considered “black letter law.” Entergy Arkansas, the Arkansas Attorney General, and other intervenors opposed this directive pending the development of the rules for implementation that are being considered in the separate net metering rulemaking docket. Nevertheless, reserving its rights, Entergy Arkansas has complied with the directive to amend its tariffs. Asserting procedural and due process violations, in January 2020, Entergy Arkansas and the Arkansas Attorney General separately appealed certain APSC orders in the proceeding.
COVID-19 Orders
In April 2020, in light of the COVID-19 pandemic, the APSC issued an order requiring utilities, to the extent they had not already done so, to suspend service disconnections during the remaining pendency of the Arkansas Governor’s emergency declaration or until the APSC rescinds the directive. The order also authorizes utilities to establish a regulatory asset to record costs resulting from the suspension of service disconnections, directs that in future proceedings the APSC will consider whether the request for recovery of these regulatory assets is reasonable and necessary, and requires utilities to track and report the costs and any savings directly attributable to suspension of disconnects. In May 2020 the APSC approved Entergy Arkansas expanding deferred payment agreements to assist customers during the COVID-19 pandemic. Quarterly reporting began in August 2020 and the APSC ordered additional reporting in October 2020 regarding utilities’ transitional plans for ending the moratorium on service disconnects. In February 2021 the APSC issued an order finding that it is not in the public interest to immediately lift the moratorium on service disconnects, but to announce a target date of May 3, 2021. In March 2021 the APSC will issue an order either confirming the lifting of the moratorium on service disconnects or extending the moratorium. As of December 31, 2020, Entergy Arkansas recorded a regulatory asset of $10.5 million for costs associated with the COVID-19 pandemic.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation– Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Nuclear Matters
Entergy Arkansas owns and, through an affiliate, operates the ANO 1 and ANO 2 nuclear power plants. Entergy Arkansas is, therefore, subject to the risks related to owning and operating nuclear plants. These include risks related to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, to position Entergy’s nuclear fleet to meet its operational goals; the performance and capacity factors of these nuclear plants including the financial requirements to address emerging issues like stress corrosion cracking of certain materials within the plant systems; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license amendments, and decommissioning; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts and types of insurance commercially available for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident. In the event of an unanticipated early shutdown of either ANO 1 or ANO 2, Entergy Arkansas may be required to
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
file with the APSC a rate mechanism to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. ANO 1’s operating license expires in 2034 and ANO 2’s operating license expires in 2038.
Environmental Risks
Entergy Arkansas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Arkansas is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Arkansas’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Arkansas’s financial position or results of operations.
In the first quarter 2019, Entergy Arkansas recorded a revision to its estimated decommissioning cost liabilities for ANO 1 and ANO 2 as a result of a revised decommissioning cost study. The revised estimates resulted in a $126.2 million increase in its decommissioning cost liabilities, along with corresponding increases in the related asset retirement cost assets that will be depreciated over the remaining lives of the units.
Nuclear Decommissioning Costs
See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Impairment of Long-lived Assets
See “Impairment of Long-lived Assets” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Qualified Pension and Other Postretirement Benefits
Entergy Arkansas’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Costs and Sensitivities
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
Actuarial Assumption | | Change in Assumption | | Impact on 2021 Qualified Pension Cost | | Impact on 2020 Qualified Projected Benefit Obligation |
| | | | Increase/(Decrease) | | |
Discount rate | | (0.25%) | | $2,406 | | $46,791 |
Rate of return on plan assets | | (0.25%) | | $2,914 | | $— |
Rate of increase in compensation | | 0.25% | | $1,838 | | $8,922 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
Actuarial Assumption | | Change in Assumption | | Impact on 2021 Postretirement Benefit Cost | | Impact on 2020 Accumulated Postretirement Benefit Obligation |
| | | | Increase/(Decrease) | | |
Discount rate | | (0.25%) | | $174 | | $6,576 |
Health care cost trend | | 0.25% | | $225 | | $4,516 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Employer Contributions
Total qualified pension cost for Entergy Arkansas in 2020 was $81.7 million, including $21.1 million in settlement costs. Entergy Arkansas anticipates 2021 qualified pension cost to be $61.6 million. Entergy Arkansas contributed $60 million to its qualified pension plans in 2020 and estimates pension contributions will be approximately $66.6 million in 2021, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021.
Total other postretirement health care and life insurance benefit income for Entergy Arkansas in 2020 was $10.1 million. Entergy Arkansas expects 2021 postretirement health care and life insurance benefit income of approximately $11.1 million. Entergy Arkansas contributed $2.2 million to its other postretirement plans in 2020 and estimates 2021 contributions will be approximately $517 thousand.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the member and Board of Directors of
Entergy Arkansas, LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Arkansas, LLC and Subsidiaries (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of income, cash flows and changes in member’s equity (pages 332 through 336 and applicable items in pages 51 through 238), for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate and Regulatory Matters —Entergy Arkansas, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Arkansas Public Service Commission (the “APSC”), which has jurisdiction with respect to the rates of electric companies in Arkansas, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment;
regulatory assets and liabilities; income taxes; operating revenues; operation and maintenance expense; and depreciation and amortization expense.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the APSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the APSC and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs, including costs related to the Opportunity Sales Proceeding and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the APSC and the FERC, involved especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the APSC and the FERC included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the APSC and the FERC for the Company and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the APSC’s and the FERC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, including the Opportunity Sales Proceeding, we inspected the Company’s filings with the APSC and the FERC, including the annual formula rate plan filing, and considered the filings with the APSC and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
•We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order, including the Opportunity Sales Proceeding, to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 2021
We have served as the Company’s auditor since 2001.
| | | | | | | | | | | | | | | | | | | | |
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
CONSOLIDATED INCOME STATEMENTS |
| | |
| | For the Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | (In Thousands) |
| | | | | | |
OPERATING REVENUES | | | | | | |
Electric | | $2,084,494 | | | $2,259,594 | | | $2,060,643 | |
| | | | | | |
OPERATING EXPENSES | | | | | | |
Operation and Maintenance: | | | | | | |
Fuel, fuel-related expenses, and gas purchased for resale | | 271,896 | | | 458,907 | | | 517,245 | |
Purchased power | | 187,690 | | | 204,640 | | | 252,390 | |
Nuclear refueling outage expenses | | 55,737 | | | 68,769 | | | 77,915 | |
Other operation and maintenance | | 669,518 | | | 720,217 | | | 724,831 | |
Decommissioning | | 73,319 | | | 68,030 | | | 60,420 | |
Taxes other than income taxes | | 121,057 | | | 115,869 | | | 104,771 | |
Depreciation and amortization | | 338,029 | | | 307,351 | | | 292,649 | |
Other regulatory credits - net | | (35,310) | | | (11,186) | | | (14,807) | |
TOTAL | | 1,681,936 | | | 1,932,597 | | | 2,015,414 | |
| | | | | | |
OPERATING INCOME | | 402,558 | | | 326,997 | | | 45,229 | |
| | | | | | |
OTHER INCOME | | | | | | |
Allowance for equity funds used during construction | | 15,019 | | | 15,499 | | | 16,557 | |
Interest and investment income | | 35,579 | | | 26,020 | | | 25,406 | |
Miscellaneous - net | | (21,908) | | | (18,566) | | | (14,874) | |
TOTAL | | 28,690 | | | 22,953 | | | 27,089 | |
| | | | | | |
INTEREST EXPENSE | | | | | | |
Interest expense | | 144,834 | | | 140,087 | | | 124,459 | |
Allowance for borrowed funds used during construction | | (6,595) | | | (6,332) | | | (7,781) | |
TOTAL | | 138,239 | | | 133,755 | | | 116,678 | |
| | | | | | |
INCOME (LOSS) BEFORE INCOME TAXES | | 293,009 | | | 216,195 | | | (44,360) | |
| | | | | | |
Income taxes | | 47,777 | | | (46,769) | | | (297,067) | |
| | | | | | |
NET INCOME | | 245,232 | | | 262,964 | | | 252,707 | |
| | | | | | |
Preferred dividend requirements | | 0 | | | 0 | | | 1,249 | |
| | | | | | |
EARNINGS APPLICABLE TO COMMON EQUITY | | $245,232 | | | $262,964 | | | $251,458 | |
| | | | | | |
See Notes to Financial Statements. | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | For the Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | (In Thousands) |
OPERATING ACTIVITIES | | | | | | |
Net income | | $245,232 | | | $262,964 | | | $252,707 | |
Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 490,457 | | | 465,299 | | | 443,698 | |
Deferred income taxes, investment tax credits, and non-current taxes accrued | | 87,019 | | | 94,368 | | | 129,524 | |
Changes in assets and liabilities: | | | | | | |
Receivables | | (24,507) | | | (58,077) | | | 4,294 | |
Fuel inventory | | (10,066) | | | (10,597) | | | 6,210 | |
Accounts payable | | (22,773) | | | 3,059 | | | (126,405) | |
Prepaid taxes and taxes accrued | | 6 | | | 24,942 | | | 9,568 | |
Interest accrued | | (43) | | | 3,895 | | | 678 | |
Deferred fuel costs | | (1,186) | | | 72,560 | | | 43,869 | |
Other working capital accounts | | (11,061) | | | 18,783 | | | (30,118) | |
Provisions for estimated losses | | 6,289 | | | 14,901 | | | 14,250 | |
Other regulatory assets | | (165,534) | | | (131,873) | | | 32,460 | |
Other regulatory liabilities | | 106,878 | | | 39,293 | | | (341,682) | |
| | | | | | |
Pension and other postretirement liabilities | | 42,576 | | | 5,831 | | | (40,157) | |
Other assets and liabilities | | (83,469) | | | (127,582) | | | (187,071) | |
Net cash flow provided by operating activities | | 659,818 | | | 677,766 | | | 211,825 | |
INVESTING ACTIVITIES | | | | | | |
Construction expenditures | | (775,595) | | | (641,525) | | | (660,044) | |
Allowance for equity funds used during construction | | 15,019 | | | 15,306 | | | 17,013 | |
Nuclear fuel purchases | | (100,678) | | | (54,344) | | | (99,417) | |
Proceeds from sale of nuclear fuel | | 30,638 | | | 22,782 | | | 54,810 | |
| | | | | | |
Proceeds from nuclear decommissioning trust fund sales | | 321,360 | | | 317,377 | | | 300,801 | |
Investment in nuclear decommissioning trust funds | | (336,392) | | | (336,519) | | | (315,163) | |
Payment for purchase of assets | | (5,988) | | | 0 | | | 0 | |
Changes in money pool receivable - net | | (3,110) | | | 0 | | | 0 | |
| | | | | | |
| | | | | | |
| | | | | | |
Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | 55,001 | | | 0 | | | 0 | |
| | | | | | |
Insurance proceeds | | 0 | | | 0 | | | 14,790 | |
Other | | 4,036 | | | 630 | | | (1,517) | |
Net cash flow used in investing activities | | (795,709) | | | (676,293) | | | (688,727) | |
FINANCING ACTIVITIES | | | | | | |
Proceeds from the issuance of long-term debt | | 1,071,121 | | | 834,038 | | | 958,434 | |
Retirement of long-term debt | | (632,175) | | | (548,952) | | | (690,488) | |
Capital contribution from parent | | 0 | | | 0 | | | 350,000 | |
Redemption of preferred stock | | 0 | | | 0 | | | (32,660) | |
Change in money pool payable - net | | (21,634) | | | (161,104) | | | 16,601 | |
Changes in short-term borrowings - net | | 0 | | | 0 | | | (49,974) | |
Distributions/dividends paid: | | | | | | |
Common equity | | (95,000) | | | (115,000) | | | (91,751) | |
Preferred stock | | 0 | | | 0 | | | (1,606) | |
Other | | 2,188 | | | (7,055) | | | 12,249 | |
Net cash flow provided by financing activities | | 324,500 | | | 1,927 | | | 470,805 | |
Net increase (decrease) in cash and cash equivalents | | 188,609 | | | 3,400 | | | (6,097) | |
Cash and cash equivalents at beginning of period | | 3,519 | | | 119 | | | 6,216 | |
Cash and cash equivalents at end of period | | $192,128 | | | $3,519 | | | $119 | |
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
Cash paid (received) during the period for: | | | | | | |
Interest - net of amount capitalized | | $140,735 | | | $131,134 | | | $118,731 | |
Income taxes | | ($21,971) | | | ($33,989) | | | $44,393 | |
See Notes to Financial Statements. | | | | | | |
| | | | | | | | | | | | | | |
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
CONSOLIDATED BALANCE SHEETS |
ASSETS |
| | |
| | December 31, |
| | 2020 | | 2019 |
| | (In Thousands) |
| | | | |
CURRENT ASSETS | | | | |
Cash and cash equivalents: | | | | |
Cash | | $24,108 | | | $3,519 | |
Temporary cash investments | | 168,020 | | | 0 | |
Total cash and cash equivalents | | 192,128 | | | 3,519 | |
Securitization recovery trust account | | 0 | | | 4,036 | |
Accounts receivable: | | | | |
Customer | | 183,719 | | | 117,679 | |
Allowance for doubtful accounts | | (18,334) | | | (1,169) | |
Associated companies | | 34,216 | | | 29,178 | |
Other | | 35,845 | | | 117,653 | |
Accrued unbilled revenues | | 109,000 | | | 108,489 | |
Total accounts receivable | | 344,446 | | | 371,830 | |
| | | | |
| | | | |
Fuel inventory - at average cost | | 43,811 | | | 33,745 | |
Materials and supplies - at average cost | | 237,640 | | | 211,320 | |
Deferred nuclear refueling outage costs | | 32,692 | | | 48,875 | |
| | | | |
| | | | |
Prepayments and other | | 13,296 | | | 14,096 | |
| | | | |
TOTAL | | 864,013 | | | 687,421 | |
| | | | |
OTHER PROPERTY AND INVESTMENTS | | | | |
Decommissioning trust funds | | 1,273,921 | | | 1,101,283 | |
| | | | |
Other | | 341 | | | 345 | |
TOTAL | | 1,274,262 | | | 1,101,628 | |
| | | | |
UTILITY PLANT | | | | |
Electric | | 12,905,322 | | | 12,293,483 | |
| | | | |
Construction work in progress | | 234,213 | | | 197,775 | |
Nuclear fuel | | 163,044 | | | 195,547 | |
TOTAL UTILITY PLANT | | 13,302,579 | | | 12,686,805 | |
Less - accumulated depreciation and amortization | | 5,255,355 | | | 5,019,826 | |
UTILITY PLANT - NET | | 8,047,224 | | | 7,666,979 | |
| | | | |
DEFERRED DEBITS AND OTHER ASSETS | | | | |
Regulatory assets: | | | | |
| | | | |
Other regulatory assets (includes securitization property of $0 as of December 31, 2020 and $1,706 as of December 31, 2019) | | 1,832,384 | | | 1,666,850 | |
Deferred fuel costs | | 68,220 | | | 67,690 | |
Other | | 14,028 | | | 15,065 | |
TOTAL | | 1,914,632 | | | 1,749,605 | |
| | | | |
TOTAL ASSETS | | $12,100,131 | | | $11,205,633 | |
| | | | |
See Notes to Financial Statements. | | | | |
| | | | | | | | | | | | | | |
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
CONSOLIDATED BALANCE SHEETS |
LIABILITIES AND EQUITY |
| | |
| | December 31, |
| | 2020 | | 2019 |
| | (In Thousands) |
| | | | |
CURRENT LIABILITIES | | | | |
Currently maturing long-term debt | | $485,000 | | | $0 | |
| | | | |
Accounts payable: | | | | |
Associated companies | | 59,448 | | | 111,785 | |
Other | | 208,591 | | | 202,201 | |
Customer deposits | | 98,506 | | | 101,411 | |
Taxes accrued | | 81,837 | | | 81,831 | |
| | | | |
Interest accrued | | 22,745 | | | 22,788 | |
Deferred fuel costs | | 53,065 | | | 53,721 | |
Current portion of unprotected excess accumulated deferred income taxes | | 0 | | | 9,296 | |
Other | | 40,628 | | | 38,760 | |
TOTAL | | 1,049,820 | | | 621,793 | |
| | | | |
NON-CURRENT LIABILITIES | | | | |
Accumulated deferred income taxes and taxes accrued | | 1,286,123 | | | 1,183,126 | |
Accumulated deferred investment tax credits | | 30,500 | | | 31,701 | |
Regulatory liability for income taxes - net | | 467,031 | | | 478,174 | |
Other regulatory liabilities | | 686,872 | | | 559,555 | |
Decommissioning | | 1,314,160 | | | 1,242,616 | |
Accumulated provisions | | 70,169 | | | 63,880 | |
Pension and other postretirement liabilities | | 361,682 | | | 319,075 | |
Long-term debt (includes securitization bonds of $0 as of December 31, 2020 and $6,772 as of December 31, 2019) | | 3,482,507 | | | 3,517,208 | |
Other | | 75,098 | | | 62,568 | |
TOTAL | | 7,774,142 | | | 7,457,903 | |
| | | | |
Commitments and Contingencies | | 0 | | 0 |
| | | | |
| | | | |
| | | | |
EQUITY | | | | |
Member's equity | | 3,276,169 | | | 3,125,937 | |
TOTAL | | 3,276,169 | | | 3,125,937 | |
| | | | |
TOTAL LIABILITIES AND EQUITY | | $12,100,131 | | | $11,205,633 | |
| | | | |
See Notes to Financial Statements. | | | | |
| | | | | |
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY |
For the Years Ended December 31, 2020, 2019, and 2018 |
| |
| |
| Member's Equity |
| (In Thousands) |
| |
Balance at December 31, 2017 | $2,376,754 | |
Net income | 252,707 | |
Capital contributions from parent | 350,000 | |
| |
Common equity distributions | (91,751) | |
Non-cash contribution from parent | 94,335 | |
Preferred stock dividends | (1,249) | |
Other | 2,307 | |
Balance at December 31, 2018 | $2,983,103 | |
Net income | 262,964 | |
| |
| |
Common equity distributions | (115,000) | |
| |
| |
Other | (5,130) | |
Balance at December 31, 2019 | $3,125,937 | |
Net income | 245,232 | |
| |
| |
Common equity distributions | (95,000) | |
| |
| |
| |
Balance at December 31, 2020 | $3,276,169 | |
| |
See Notes to Financial Statements. | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | (In Thousands) |
| | | | | | | | | | |
Operating revenues | | $2,084,494 | | | $2,259,594 | | | $2,060,643 | | | $2,139,919 | | | $2,086,608 | |
Net income | | $245,232 | | | $262,964 | | | $252,707 | | | $139,844 | | | $167,212 | |
Total assets | | $12,100,131 | | | $11,205,633 | | | $10,401,596 | | | $10,134,029 | | | $9,606,117 | |
Long-term obligations (a) | | $3,482,507 | | | $3,517,208 | | | $3,225,759 | | | $2,983,749 | | | $2,746,435 | |
| | | | | | | | | | |
(a) Includes long-term debt (excluding currently maturing debt) and preferred stock without sinking fund. |
| | | | | | | | | | |
| | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | (Dollars In Millions) |
| | | | | | | | | | |
Electric Operating Revenues: | | | | | | | | | | |
Residential | | $841 | | | $795 | | | $807 | | | $768 | | | $789 | |
Commercial | | 466 | | | 539 | | | 426 | | | 495 | | | 495 | |
Industrial | | 462 | | | 521 | | | 434 | | | 472 | | | 446 | |
Governmental | | 18 | | | 21 | | | 17 | | | 19 | | | 18 | |
Total billed retail | | 1,787 | | | 1,876 | | | 1,684 | | | 1,754 | | | 1,748 | |
Sales for resale: | | | | | | | | | | |
Associated companies | | 105 | | | 118 | | | 104 | | | 128 | | | 49 | |
Non-associated companies | | 68 | | | 140 | | | 145 | | | 121 | | | 118 | |
Other | | 124 | | | 126 | | | 128 | | | 137 | | | 172 | |
Total | | $2,084 | | | $2,260 | | | $2,061 | | | $2,140 | | | $2,087 | |
| | | | | | | | | | |
Billed Electric Energy Sales (GWh): | | | | | | | | | | |
Residential | | 7,584 | | | 7,996 | | | 8,248 | | | 7,298 | | | 7,618 | |
Commercial | | 5,356 | | | 5,822 | | | 5,967 | | | 5,825 | | | 5,988 | |
Industrial | | 7,586 | | | 7,759 | | | 8,071 | | | 7,528 | | | 6,795 | |
Governmental | | 223 | | | 241 | | | 239 | | | 237 | | | 237 | |
Total retail | | 20,749 | | | 21,818 | | | 22,525 | | | 20,888 | | | 20,638 | |
Sales for resale: | | | | | | | | | | |
Associated companies | | 1,659 | | | 2,180 | | | 1,773 | | | 1,782 | | | 1,609 | |
Non-associated companies | | 4,198 | | | 7,206 | | | 6,447 | | | 6,549 | | | 7,115 | |
Total | | 26,606 | | | 31,204 | | | 30,745 | | | 29,219 | | | 29,362 | |
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
The COVID-19 Pandemic
See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the COVID-19 pandemic.
Hurricane Laura, Hurricane Delta, and Hurricane Zeta
In August 2020 and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of Entergy Louisiana’s service area. The storms resulted in widespread outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta are currently estimated to be approximately $2.0 billion, including approximately $1.67 billion in capital costs and approximately $330 million in non-capital costs. This estimate includes all costs to restore power and repair or replace the damages from the hurricanes, except for the cost to repair or replace damage incurred to an Entergy Louisiana determinedtransmission line in southeast Louisiana, and the amount of that it was probable thatcost could be significant. The restoration plan for this transmission line and the Little Gypsy repowering project wouldrelated cost estimate is still being evaluated. Also, Entergy Louisiana’s revenues were adversely affected in 2020, primarily due to power outages resulting from the hurricanes. Entergy Louisiana is considering all reasonable avenues to recover storm-related costs from Hurricane Laura, Hurricane Delta, and Hurricane Zeta, including securitization. Storm cost recovery or financing will be abandonedsubject to review by applicable regulatory authorities.
Entergy Louisiana recorded accounts payable and accordingly reclassified $199.8 million of project costs fromcorresponding construction work in progress and regulatory assets for the estimated costs incurred that were necessary to areturn customers to service. Entergy Louisiana recorded the regulatory asset. A hearingassets in accordance with its accounting policies and based on the issues, excepthistoric treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. There are well established mechanisms and precedent for cost allocation among customer classes, was held before the ALJaddressing these catastrophic events and providing for recovery of prudently incurred storm costs in November 2010. In January 2011 all parties participated in a mediation on the disputed issues, resulting in a settlement of all disputed issues, including cost recoveryaccordance with applicable regulatory and cost allocation. The settlement provides forlegal principles. Because Entergy Louisiana has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, $200 million asor the timing of March 31, 2011, and carrying costs on that amount on specified terms thereafter. The settlement also provides for Entergy Louisiana to recover the approved project costs by securitization. such recovery.
In April 2011,October 2020, Entergy Louisiana filed an application withat the LPSC seeking approval of certain ratemaking adjustments to authorize the securitizationfacilitate issuance of the investment recoveryshorter-term bonds to provide interim financing for restoration costs associated with the projectHurricane Laura, Hurricane Delta, and to issue a financing order by whichHurricane Zeta. Subsequently, Entergy Louisiana could accomplish such securitization.and the LPSC staff filed a joint motion seeking approval to exclude from the derivation of Entergy Louisiana’s capital structure and cost rate of debt for ratemaking purposes, including the allowance for funds used during construction, shorter-term debt up to $1.1 billion issued by Entergy Louisiana to fund costs associated with Hurricane Laura, Hurricane Delta, and Hurricane Zeta costs on an interim basis. In August 2011November 2020 the LPSC issued an order approving the settlementjoint motion, and alsoEntergy Louisiana issued $1.1 billion of 0.62% Series mortgage bonds due November 2023. Also in November 2020, Entergy Louisiana drew $257 million from its funded storm reserves.
In December 2020, Entergy Louisiana provided the LPSC with notification that it intends to initiate a storm cost recovery proceeding in the near future, which will permit the LPSC to retain any outside consultants and counsel needed to review the storm cost recovery application. In February 2021 the LPSC voted to retain outside counsel and consultants to assist in the review of Entergy Louisiana’s upcoming storm cost recovery application, which is expected to be filed in March 2021.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
February 2021 Winter Storms
issued
See the “February 2021 Winter Storms” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a financing orderdiscussion of the February 2021 winter storms. Entergy Louisiana’s preliminary estimate for the securitization.cost of mobilizing crews and restoring power is approximately $50 million to $60 million. Natural gas purchases for Entergy Louisiana for February 1st through 25th, 2021 are approximately $190 million compared to natural gas purchases for February 2020 of $39 million.
Results of Operations
2020 Compared to 2019
Net Income
Net income increased $390.8 million primarily due to the $382.8 million reduction in deferred income tax expense related to the basis of assets contributed in the 2015 Entergy Louisiana and Entergy Gulf States Louisiana business combination as a result of the resolution of the 2014-2015 IRS audit in the fourth quarter 2020 and the $58 million reduction in income tax expense resulting from an IRS settlement in the first quarter 2020 related to the uncertain tax position regarding the Hurricane Isaac Louisiana Act 55 financing, which also resulted in a $29 million ($21 million net-of-tax) regulatory charge to reflect Entergy Louisiana’s agreement to share the savings with customers. Also contributing to the increase were higher retail electric price, lower other operation and maintenance expenses, and a lower effective income tax rate. The increase was partially offset by higher depreciation and amortization expenses, lower volume/weather, lower other income, higher interest expense, and higher taxes other than income taxes. See Note 53 to the financial statements for afurther discussion of the September 2011 issuancetax audit resolution and the tax settlement.
Operating Revenues
Following is an analysis of the securitization bonds.change in operating revenues comparing 2020 to 2019:
| | | | | |
| Amount |
| (In Millions) |
2019 operating revenues | $4,285.2 | |
Fuel, rider, and other revenues that do not significantly affect net income | (330.3) | |
Volume/weather | (68.8) | |
Return of unprotected excess accumulated deferred income taxes to customers | 7.5 | |
Retail electric price | 176.3 | |
2020 operating revenues | $4,069.9 | |
StateEntergy Louisiana’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and Local Rate Regulationother costs such that the revenues and Fuel-Cost Recoveryexpenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The rates that Entergy Louisiana charges for its services significantly influence its financial position, resultsvolume/weather variance is primarily due to decreased commercial and industrial usage as a result of operations,the COVID-19 pandemic, the effects of Hurricane Laura, Hurricane Delta, and liquidity. Entergy Louisiana is regulatedHurricane Zeta on sales, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the LPSC, is primarily responsible for approvaleffect of less favorable weather on residential sales, partially offset by increased residential usage as a result of the rates charged to customers.
Retail Rates - Electric
Filings with the LPSC
2014 Formula Rate Plan Filing
In connection with the approval of the business combination of Entergy Gulf States Louisiana and Entergy Louisiana, the LPSC authorized the filing of a single, joint, formula rate plan evaluation report for Entergy Gulf States Louisiana’s and Entergy Louisiana’s 2014 calendar year operations.COVID-19 pandemic. The joint evaluation report was filed in September 2015 and reflected an earned return on common equity of 9.09%. As such, no adjustment to base formula rate plan revenue was required. The following adjustments were required under the formula rate plan, however: a decrease in the additional capacity mechanism for Entergy Louisiana of $17.8 million;industrial usage is partially offset by an increase in demand from expansion projects, primarily in the additional capacity mechanismtransportation and chemicals industries. See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for Entergy Gulf States Louisiana of $4.3 million; and a reduction of $5.5 million to the MISO cost recovery mechanism to collect approximately $35.7 million on a combined-company basis. Under the order approving the business combination, following completiondiscussion of the prescribed review period, rates were implemented with the first billing cycle of December 2015, subject to refund. In June 2017 the LPSC staff and Entergy Louisiana filed an unopposed joint report of proceedings, which was accepted by the LPSC in June 2017, finalizing the results of this proceeding with no changes to rates already implemented.
2015 Formula Rate Plan Filing
In May 2016, Entergy Louisiana filed its formula rate plan evaluation report for its 2015 calendar year operations. The evaluation report reflected an earned return on common equity of 9.07%. As such, no adjustment to base formula rate plan revenue was required. The following other adjustments, however, were required under the formula rate plan: an increase in the legacy Entergy Louisiana additional capacity mechanism of $14.2 million; a separate increase in legacy Entergy Louisiana revenue of $10 million primarily to reflect the effects of the termination of the System Agreement; an increase in the legacy Entergy Gulf States Louisiana additional capacity mechanism of $0.5 million; a decrease in legacy Entergy Gulf States Louisiana revenue of $58.7 million primarily to reflect the effects of the termination of the System Agreement; and an increase of $11 million to the MISO cost recovery mechanism. Rates were implemented with the first billing cycle of September 2016, subject to refund. Following implementation of the as-filed rates in September 2016, there were several interim updates to Entergy Louisiana’s formula rate plan, including the one submitted in December 2016, reflecting implementation of the settlement of the Waterford 3 replacement steam generator project prudence review described below. In June 2017 the LPSC staff and Entergy Louisiana filed a joint report of proceedings, which was accepted by the LPSC in June 2017, finalizing the results of the May 2016 evaluation report, interim updates, and corresponding proceedings with no changes to rates already implemented.
Extension of MISO Cost Recovery Mechanism Rider
In November 2016, Entergy Louisiana filed with the LPSC a request to extend the MISO cost recovery mechanism rider provision of its formula rate plan. In March 2017 the LPSC staff submitted direct testimony generally supportive of a one-year extension of the MISO cost recovery mechanism and the intervenor in the proceeding did not
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
oppose an extensionCOVID-19 pandemic. See “Hurricane Laura, Hurricane Delta, and Hurricane Zeta” above for this period of time. In July 2017 an uncontested joint stipulation authorizing a one-year extensiondiscussion of the MISO cost recovery mechanism rider was approved.storms.
2016 Formula Rate Plan Filing
In May 2017, Entergy Louisiana filed itsThe return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through changes in the formula rate plan evaluation reporteffective May 2018. In 2020, $31.1 million was returned to customers as compared to $38.6 million in 2019. There was no effect on net income as the reduction in operating revenues was offset by a reduction in income tax expense. See Note 2 to the financial statements for its 2016 calendar year operations. further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
The evaluation report reflectedretail electric price variance is primarily due to an earned return on common equity of 9.84%. As such, no adjustment to base formula rate plan revenue was required. Adjustments, however, were required under the formula rate plan; the 2016 formula rate plan evaluation report showed a decreaseincrease in formula rate plan revenues effective June 2019 due to the inclusion of the first-year revenue requirement for the J. Wayne Leonard Power Station (formerly St. Charles Power Station) and effective April 2020 due to the inclusion of approximately $16.9 million, comprised of a decreasethe first-year revenue requirement for the Lake Charles Power Station and increases in legacy Entergy Louisiana formula rate plan revenue of $3.5 million, a decrease in legacy Entergy Gulf States Louisiana formula rate plan revenue of $9.7 million,revenues effective September 2019 and a decrease in incremental formula rate plan revenue of $3.7 million. Additionally, the formula rate plan evaluation report called for a decrease of $40.5 million in the MISO cost recovery revenue requirement from the present level of $46.8 million to $6.3 million. Rates reflecting these adjustments were implemented with the first billing cycle of September 2017, subject to refund. In September 2017 the LPSC issued its report indicating that no changes to Entergy Louisiana’s original formula rate plan evaluation report were required but reserved for several issues, including Entergy Louisiana’s September 2017 update to its formula rate plan evaluation report.
Formula Rate Plan Extension Request
In August 2017, Entergy Louisiana filed a request with the LPSC seeking to extend its formula rate plan for three years (2017-2019) with limited modifications to its terms. Those modifications include: a one-time resetting of base rates2020. See Note 2 to the midpoint of the band at Entergy Louisiana’s authorized return on equity of 9.95%financial statements for the 2017 test year; narrowingfurther discussion of the formula rate plan bandwidthproceedings.
Other Income Statement Variances
Other operation and maintenance expenses decreased primarily due to:
•a decrease of $10.2 million in nuclear generation expenses primarily due to a lower scope of work performed in 2020 as compared to 2019, in part as a result of the COVID-19 pandemic;
•a decrease of $9.5 million primarily due to contract costs in 2019 related to initiatives to explore new customer products and services;
•a decrease of $6.8 million in loss provisions;
•higher nuclear insurance refunds of $5.9 million;
•a decrease of $5.8 million in energy efficiency costs due to the timing of recovery from customers; and
•a totaldecrease of 160 basis points$4.3 million in non-nuclear generation expenses primarily due to 80 basis points;a lower scope of work performed during plant outages in 2020 as compared to the same period in 2019, partially offset by increases resulting from the J. Wayne Leonard Power Station (formerly St. Charles Power Station) and the Lake Charles Power Station being placed in service.
The decrease was partially offset by:
•an increase of $4.1 million in compensation and benefits costs primarily due to an increase in net periodic pension and other postretirement benefits costs as a forward-looking mechanism that would allow Entergy Louisiana to recover certain transmission-related costs contemporaneously with when those projects begin delivering benefits to customers. Entergy Louisiana requested that the LPSC consider its request on an expedited basis, in an effort to maintain Entergy Louisiana’s current cycle for implementing rate adjustments, i.e., September 2018, without the need for filingresult of a full base rate case proceeding. Several parties have interveneddecrease in the proceedingdiscount rate used to value the benefit liabilities. See “Critical Accounting Estimates” below and all parties have been participatingNote 11 to the financial statements for further discussion of pension and other postretirement benefit costs; and
•several individually insignificant items.
Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher property assessments.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the J. Wayne Leonard Power Station (formerly St. Charles Power Station), which was placed into service in May 2019 and the Lake Charles Power Station, which was placed in service in March 2020.
Other regulatory charges (credits) include regulatory charges of $32.6 million recorded in the fourth quarter 2020 due to a settlement discussions.
Waterfordwith the IRS related to the uncertain tax position regarding Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing because the savings will be shared with customers and $29 million recorded in the first quarter 2020 due to a settlement with the IRS related to the uncertain tax position regarding Hurricane Isaac Louisiana Act 55 financing because the savings will be shared with customers. See Note 3 Replacement Steam Generator Project
Followingto the completionfinancial statements for further discussion of the Waterford 3 replacement steam generator project, the LPSC undertook a prudence review in connection with a filing made by Entergy Louisiana in April 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project;settlements and 5) the outage length and replacement power costs. In July 2014 the LPSC staff filed testimony recommending potential project and replacement power cost disallowances of up to $71 million, citing a need for further explanation or documentation from Entergy Louisiana. An intervenor filed testimony recommending disallowance of $141 million of incremental project costs, claiming the steam generator fabricator was imprudent. Entergy Louisiana provided further documentation and explanation requested by the LPSC staff. An evidentiary hearing was held in December 2014. At the hearing the parties maintained the positions reflected in pre-filed testimony. Entergy Louisiana believed that the replacement steam generator costs were prudently incurred and applicable legal principles supported their recovery in rates. Nevertheless, Entergy Louisiana recorded a write-off of $16 million of Waterford 3’s plant balance in December 2014 because of the uncertainty at the time associated with the resolution of the prudence review. In December 2015 the ALJ issued a proposed recommendation, which was subsequently finalized, concluding that Entergy Louisiana prudently managed the Waterford 3 replacement steam generator project, including the selection, use, and oversight of contractors, and could not reasonably have anticipated the damage to the steam generators. Nevertheless, the ALJ concluded that Entergy Louisiana was liable for the conduct of its contractor and subcontractor and, therefore, recommended a disallowance of $67 million in capital costs. Additionally, the ALJ concluded that Entergy Louisiana did not sufficiently justify the incurrence of $2 million in replacement power costs during the replacement outage. Although the ALJ’s recommendation had not yet been considered by the LPSC, after considering the progress of the proceeding in light of the ALJ recommendation, Entergy
savings obligations.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other income decreased primarily due to:
Louisiana recorded
•a decrease in the fourth quarter 2015 approximately $77allowance for equity funds used during construction due to higher construction work in progress in 2019, including the J. Wayne Leonard Power Station (formerly St. Charles Power Station) and the Lake Charles Power Station projects; and
•changes in decommissioning trust fund activity.
Interest expense increased primarily due to:
•the issuances of $300 million of 4.20% Series mortgage bonds and $350 million of 2.90% Series mortgage bonds, each in charges,March 2020;
•the issuance of $525 million of 4.20% Series mortgage bonds in March 2019; and
•a decrease in the allowance for borrowed funds used during construction due to higher construction work in progress in 2019, including a $45 million asset write-offthe J. Wayne Leonard Power Station (formerly St. Charles Power Station) and a $32 million regulatory charge,Lake Charles Power Station projects.
The effective income tax rates were (54.6%) for 2020 and 15% for 2019. The difference in the effective income tax rate versus the federal statutory rate of 21% for 2020 was primarily due to reflect that a portioncompletion of the assets associated with2014-2015 IRS audit effectively settling the Waterfordtax positions for those years. The difference in the effective income tax rate versus the federal statutory rate of 21% for 2019 was primarily due to the amortization of excess accumulated deferred income taxes. See Notes 2 and 3 replacement steam generator project was no longer probable of recovery. Entergy Louisiana maintained thatto the ALJ’s recommendation contained significant factual and legal errors.
In October 2016 the parties reachedfinancial statements for a settlement in this matter. The settlement was approved by the LPSC in December 2016. The settlement effectively provided for an agreed-upon disallowance of $67 million of plant, which had been previously written off by Entergy Louisiana, as discussed above. The refund to customers of approximately $71 million as a resultdiscussion of the settlement approved byeffects and regulatory activity regarding the LPSC was made to customers in January 2017. Of the $71 million of refunds, $68 million was credited to customers through Entergy Louisiana’s formula rate plan, outside of sharing,Tax Cuts and $3 million through its fuel adjustment clause. Entergy Louisiana had previously recorded a provision of $48 million for this refund. The previously-recorded provision included the cumulative revenues recorded through December 2016 relatedJobs Act. See Note 3 to the $67 million of disallowed plant. An additional regulatory charge of $23 million was recorded in fourth quarter 2016 to reflect the effectsfinancial statements for a reconciliation of the settlement. The settlement also provided that Entergy Louisiana could retain the value associated with potential service credits agreed to by the project contractor,federal statutory rates of 21% to the extent they are realizedeffective income tax rates.
2019 Compared to 2018
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in the future. Following a review by the parties, an unopposed joint report of proceedings was filed by the LPSC staff and Entergy Louisiana in May 2017 and the LPSC accepted the joint report of proceedings resolving the matter.
Ninemile 6
In July 2014, Entergy Gulf States Louisiana and Entergy Louisiana filed an unopposed stipulation with the LPSC, which was subsequently approved, that estimated a first year revenue requirement associated with Ninemile 6 and provided a mechanism to update the revenue requirement as the in-service date approached. In late-December 2014, roughly contemporaneous with the unit's placement in service, a final updated estimated revenue requirement of $26.8 million for Entergy Gulf States Louisiana and $51.1 million for Entergy Louisiana was filed. The December 2014 estimate formed the basis of rates implemented effective with the first billing cycle of January 2015. In July 2015, Entergy Louisiana submitted to the LPSC a compliance filing including an estimate at completion, inclusive of interconnection costs and transmission upgrades, of approximately $648 million, or $76 million less than originally estimated, along with other project details and supporting evidence, to enable the LPSC to review the prudenceItem 7 of Entergy Louisiana’s management ofAnnual Report on Form 10-K for the project. Testimonyyear ended December 31, 2019, filed by the LPSC staff generally supported the prudence of the management of the project and recovery of the costs incurred to complete the project. The LPSC staff had questioned the warranty coverage for one element of the project. In October 2016 all parties agreed to a stipulation providing that 100% of Ninemile 6 construction costs was prudently incurred and is eligible for recovery from customers, but reserving the LPSC’s rights to review the prudence of Entergy Louisiana’s actions regarding one element of the project. This stipulation was approved by the LPSC in January 2017.
Union Power Station and Deactivation or Retirement Decisions for Entergy Louisiana Plants
In January 2015, Entergy Gulf States Louisiana filed its application with the LPSCSEC on February 21, 2020, for approvaldiscussion of results of operations for 2019 compared to 2018.
Liquidity and Capital Resources
Cash Flow
Cash flows for the acquisitionyears ended December 31, 2020, 2019, and cost recovery of two power blocks of the Union Power Station for an expected base purchase price of approximately $237 million per power block, subject to adjustments. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station. In March 2016, Entergy Louisiana acquired Power Blocks 3 and 4 of Union Power Station for an aggregate purchase price of approximately $474 million and implemented rates to collect the estimated first-year revenue requirement with the first billing cycle of March 2016.2018 were as follows:
| | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 |
| (In Thousands) |
Cash and cash equivalents at beginning of period | $2,006 | | | $43,364 | | | $35,907 | |
| | | | | |
Net cash provided by (used in): | | | | | |
Operating activities | 1,072,986 | | | 1,236,002 | | | 1,395,204 | |
Investing activities | (1,944,671) | | | (1,653,634) | | | (1,878,208) | |
Financing activities | 1,597,699 | | | 376,274 | | | 490,461 | |
Net increase (decrease) in cash and cash equivalents | 726,014 | | | (41,358) | | | 7,457 | |
| | | | | |
Cash and cash equivalents at end of period | $728,020 | | | $2,006 | | | $43,364 | |
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2020 Compared to 2019
Operating Activities
Net cash flow provided by operating activities decreased $163 million in 2020 primarily due to:
•an increase of $186.1 million in storm spending in 2020, primarily due to Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration efforts. See “Hurricane Laura, Hurricane Delta, and Hurricane Zeta” above for discussion of storm restoration efforts;
•lower collections of receivables from customers, in part due to the COVID-19 pandemic;
•the timing of recovery of fuel and purchased power costs; and
•an increase of $21.5 million in interest paid.
The decrease was partially offset by:
•a decrease in $43.7 million in spending on nuclear refueling outages;
•the timing of payments to vendors; and
•income tax refunds of $14.7 million in 2020 compared to $15.3 million in income tax payments in 2019. Entergy Louisiana had income tax refunds in 2020 and income tax payments in 2019 in accordance with an intercompany tax allocation agreement. Entergy Louisiana had income tax refunds in 2020 as a result of a refund of an overpayment on a prior year state income tax return.
Investing Activities
Net cash flow used in investing activities increased $291 million in 2020 primarily due to:
•an increase of $709.7 million in storm spending 2020, primarily due to Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration efforts, See “Hurricane Laura, Hurricane Delta, and Hurricane Zeta” above for discussion of storm restoration efforts;
•the purchase of Washington Parish Energy Center in November 2020 for approximately $222 million. See Note 14 to the financial statements for further discussion of the Washington Parish Energy Center purchase;
•an increase of $16.7 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of Entergy Louisiana’s distribution system, including increased spending on advanced metering infrastructure; and
•money pool activity.
The increase was partially offset by:
•an increase of $302.2 million in net receipts from storm reserve escrow accounts;
•a decrease of $207.8 million in non-nuclear generation construction expenditures due to higher spending in 2019 on the Lake Charles Power Station and J. Wayne Leonard Power Station (formerly St. Charles Power Station) projects;
•a decrease of $133.1 million in transmission construction expenditures primarily due to a lower scope of work performed on various projects in 2020 as compared to 2019;
•a decrease of $89.5 million in nuclear construction expenditures primarily due to a lower scope of work performed on various nuclear projects in 2020 as compared to 2019; and
•a decrease of $26.1 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material, and service deliveries, and the timing of cash payments during the nuclear fuel cycle.
Increases in Entergy Louisiana’s receivable from the money pool are a use of cash flow, and Entergy Louisiana’s receivable from the money pool increased by $13.4 million in 2020 compared to decreasing by $46.8
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
million in 2019. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Financing Activities
Net cash flow provided by financing activities increased $1,221.4 million in 2020 primarily due to:
•the issuance of $1.1 billion of 0.62% Series mortgage bonds in November 2020;
•the issuance of $350 million of 2.90% Series mortgage bonds and $300 million of 4.20% Series mortgage bonds, each in March 2020;
•the issuance of $300 million of 2.90% Series mortgage bonds and $300 million of 1.60% Series mortgage bonds, each in November 2020; and
•a decrease of $186.5 million in common equity distributions in 2020 primarily due to upcoming capital expenditures.
The increase was partially offset by:
•the issuance of $525 million of 4.20% Series mortgage bonds in March 2019;
•the repayment in August 2020 of $250 million of 3.95% Series mortgage bonds due October 2020;
•the repayment in December 2020 of $200 million of 5.25% Series mortgage bonds due July 2052;
•money pool activity;
•the repayment in December 2020 of $100 million of 4.70% Series mortgage bonds due June 2063; and
•net repayments of long-term borrowings of $62 million in 2020 on the nuclear fuel company variable interest entities’ credit facilities.
Decreases in Entergy Louisiana’s payable to the money pool are a use of cash flow, and Entergy Louisiana’s payable to the money pool decreased by $82.8 million in 2020 compared to increasing by $82.8 million in 2019.
See Note 5 to the financial statements for details of long-term debt.
2019 Compared to 2018
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Louisiana’s Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 21, 2020, for discussion of operating, investing, and financing cash flow activities for 2019 compared to 2018.
Capital Structure
Entergy Louisiana’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio for Entergy Louisiana is primarily due to the net issuances of long-term debt in 2020.
| | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
Debt to capital | 54.8 | % | | 53.4 | % |
Effect of excluding securitization bonds | 0.0 | % | | (0.1 | %) |
Debt to capital, excluding securitization bonds (a) | 54.8 | % | | 53.3 | % |
Effect of subtracting cash | (2.1 | %) | | (0.1 | %) |
Net debt to net capital, excluding securitization bonds (a) | 52.7 | % | | 53.2 | % |
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
(a)Calculation excludes the securitization bonds, which are non-recourse to Entergy Louisiana.
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Louisiana uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition because the securitization bonds are non-recourse to Entergy Louisiana, as more fully described in Note 5 to the financial statements. Entergy Louisiana also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition because net debt indicates Entergy Louisiana’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Louisiana seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Louisiana may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing distributions, Entergy Louisiana may receive equity contributions to maintain its capital structure.
Uses of Capital
Entergy Louisiana requires capital resources for:
•construction and other capital investments;
•debt maturities or retirements;
•working capital purposes, including the financing of fuel and purchased power costs; and
•distribution and interest payments.
Following are the amounts of Entergy Louisiana’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| 2021 | | 2022 | | 2023 |
| (In Millions) |
Planned construction and capital investment: | | | | | |
Generation | $365 | | | $460 | | | $785 | |
Transmission | 425 | | | 340 | | | 230 | |
Distribution | 540 | | | 485 | | | 500 | |
Utility Support | 160 | | | 130 | | | 115 | |
Total | $1,490 | | | $1,415 | | | $1,630 | |
In addition to the planned spending in the table above, Entergy Louisiana also expects to pay for $845 million of capital investments in 2021 related to Hurricane Laura, Hurricane Delta, and Hurricane Zeta restoration work that have been accrued as of December 31, 2020.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Louisiana’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2022-2023 | | 2024-2025 | | After 2025 | | Total |
| (In Millions) |
Long-term debt (a) | $557 | | | $2,294 | | | $1,495 | | | $9,506 | | | $13,852 | |
Operating leases (b) | $13 | | | $19 | | | $10 | | | $4 | | | $46 | |
Finance leases (b) | $4 | | | $7 | | | $4 | | | $2 | | | $17 | |
Purchase obligations (c) | $687 | | | $1,463 | | | $1,472 | | | $4,838 | | | $8,460 | |
(a)Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.
(b)Lease obligations are discussed in Note 10 to the financial statements.
(c)Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Louisiana, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Vidalia purchased power agreement and the Unit Power Sales Agreement, both of which are discussed in Note 8 to the financial statements.
In addition to the contractual obligations given above, Entergy Louisiana currently expects to contribute approximately $59.9 million to its qualified pension plans and approximately $15.6 million to its other postretirement health care and life insurance plans in 2021, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021. See “Critical Accounting Estimates- Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Louisiana includes specific investments such as transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to maintain reliability and improve service to customers, including advanced meters and related investments; resource planning, including potential generation and renewables projects; system improvements; investments in River Bend and Waterford 3; software and security; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
As a termwholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Louisiana pays distributions from its earnings at a percentage determined monthly.
Sources of Capital
Entergy Louisiana’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•storm reserve escrow accounts;
•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Entergy Louisiana may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest rates are favorable.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
All debt and common and preferred membership interest issuances by Entergy Louisiana require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indentures and other agreements. Entergy Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Louisiana’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the LPSC-approved settlement authorizingfollowing years.
| | | | | | | | | | | | | | | | | | | | |
2020 | | 2019 | | 2018 | | 2017 |
(In Thousands) |
$13,426 | | ($82,826) | | $46,843 | | $11,173 |
See Note 4 to the purchase of Power Blocks 3 and 4financial statements for a description of the Union Power Station, money pool.
Entergy Louisiana agreedhas a credit facility in the amount of $350 million scheduled to makeexpire in September 2024. The credit facility includes fronting commitments for the issuance of letters of credit against $15 million of the borrowing capacity of the facility. As of December 31, 2020, there were no cash borrowings and no letters of credit outstanding under the credit facility. In addition, Entergy Louisiana is a filing withparty to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2020, $2.2 million in letters of credit were outstanding under Entergy Louisiana’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
The Entergy Louisiana nuclear fuel company variable interest entities have two separate credit facilities, each in the amount of $105 million and scheduled to expire in September 2022. As of December 31, 2020, $18.9 million of loans were outstanding under the credit facility for the Entergy Louisiana River Bend nuclear fuel company variable interest entity. As of December 31, 2020, $39.3 million in loans were outstanding under the Entergy Louisiana Waterford nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for additional discussion of the nuclear fuel company variable interest entity credit facilities.
Entergy Louisiana obtained authorizations from the FERC through July 2022 for the following:
•short-term borrowings not to exceed an aggregate amount of $450 million at any time outstanding;
•long-term borrowings and security issuances; and
•borrowings by its nuclear fuel company variable interest entities.
See Note 4 to the financial statements for further discussion of Entergy Louisiana’s short-term borrowing limits.
Hurricane Isaac
In June 2014 the LPSC voted to review its decisionsapprove a series of orders which (i) quantified $290.8 million of Hurricane Isaac system restoration costs as prudently incurred; (ii) determined $290 million as the level of storm reserves to deactivate Ninemile 3 and Willow Glen 2 and 4 and its decision to retire Little Gypsy 1. In January 2016,be re-established; (iii) authorized Entergy Louisiana made its compliance filingto utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs; and (iv) granted other requested relief associated with the LPSC.storm reserves and Act 55 financing of Hurricane Isaac system restoration costs. Entergy Louisiana LPSC staff, and intervenors participated incommitted to pass on to customers a technical conference in March 2016 where Entergy Louisiana presented information on its deactivation/retirement decisionsminimum of $30.8 million of customer benefits through annual customer credits of approximately $6.2 million for these four units in addition to information on the current deactivation decisionsfive years. Approvals for the ten-year planning horizon. Parties have requested further proceedings onAct 55 financings were obtained from the prudenceLouisiana Utilities Restoration Corporation and the Louisiana State Bond Commission. See Note 2 to the financial statements for a discussion of the decision to deactivate Willow Glen 2 and 4. No party contests the prudenceAugust 2014 issuance of bonds under Act 55 of the decision to deactivate Willow Glen 2 and 4 or suggests reactivation of these units; however, issues have been raised related to Entergy Louisiana’s decision to give up its transmission service rights in MISO for Willow Glen 2 and 4 rather than placing the units into suspended status for the three-year term permitted by MISO. An evidentiary hearing was held in August 2017 and post-hearing briefs were submitted in October 2017. A decision is expected in 2018.Louisiana Legislature.
Retail Rates - Gas
In accordance with the settlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of 10.45%the upper end of the earnings band as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015.
2014 Rate Stabilization Plan FilingStorm Cost Recovery
In January 2015, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2014. The filing showed an earned return on common equity of 7.20%, which resulted in a $706 thousand rate increase. In April 2015 the LPSC issued findings recommending two adjustments to Entergy Gulf States Louisiana’s as-filed results, and an additional recommendation that did not affect the results. The LPSC staff’s recommended adjustments increase the earned return on equity for the test year to 7.24%. Entergy Gulf States Louisiana accepted the LPSC staff’s recommendations and a revenue increase of $688 thousand was implemented with the first billing cycle of May 2015.
2015 Rate Stabilization Plan Filing
In January 2016, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2015. The filing showed an earned return on common equity of 10.22%, which is within the authorized bandwidth, therefore requiring no change in rates. In March 2016 the LPSC staff issued its report stating that the 2015 gas rate stabilization plan filing was in compliance with the exception of several issues that required additional information, explanation, or clarification for which the LPSC staff had reserved the right to further review. In July 2016 the parties to the proceeding filed an unopposed joint report and motion for entry of order accepting the report that indicated no outstanding issues remained in the filing.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
In February 2016, Entergy Louisiana filed a motion requesting to extend the term of the gas rate stabilization plan in substantially similar form for an additional three-year term and included a request for sharing of non-jurisdictional compressed natural gas revenues. Following discovery and the filing of testimony by the LPSC staff, Entergy Louisiana and the LPSC submitted a joint motion for hearing an uncontested stipulated settlement resolving the proceeding. A hearing on the stipulation was held in November 2016. The ALJ issued a report of proceedings that was presented with the parties’ stipulation to the LPSC for consideration. The stipulation approving Entergy Louisiana’s requested extension of the rate stabilization plan was approved by the LPSC in December 2016.
2016 Rate Stabilization Plan Filing
In January 2017, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2016. The filing of the evaluation report for test year 2016 reflected an earned return on common equity of 6.37%. As part of the original filing, pursuant to the extraordinary cost provision of the rate stabilization plan, Entergy Louisiana sought to recover approximately $1.5 million in deferred operation and maintenance expenses incurred to restore service and repair damage resulting from flooding and widespread rainfall in southeast Louisiana that occurred in August 2016. Entergy Louisiana requested to recover the prudently incurred August 2016 storm restoration costs over ten years, outside of the rate stabilization plan sharing provisions. As a result, Entergy Louisiana’s filing sought an annual increase in revenue of $1.4 million. Following review of the filing, except for the proposed extraordinary cost recovery, the LPSC staff confirmed Entergy Louisiana’s filing was consistent with the principles and requirements of the rate stabilization plan. The extraordinary cost recovery request associated with the 2016 flood-related deferred operation and maintenance expenses incurred for gas operations was removed from the rate stabilization plan pending LPSC consideration in a separate docket. In April 2017 the LPSC approved a joint report of proceedings and Entergy Louisiana submitted a revised evaluation report reflecting a $1.2 million annual increase in revenue with rates implemented with the first billing cycle of May 2017.
In connection with the joint report of proceedings accepted by the LPSC, in May 2017, Entergy Louisiana filed an application to initiate a separate proceeding to recover through the extraordinary cost provision of the gas rate stabilization plan the deferred operation and maintenance expenses of $1.4 million incurred to restore service and repair damage resulting from flooding and widespread rainfall in southeast Louisiana that occurred in August 2016. The LPSC staff submitted its direct testimony in the proceeding recommending recovery of $0.9 million. Entergy Louisiana filed rebuttal testimony responding to the LPSC staff’s recommendation. The procedural schedule was suspended to allow the parties to engage in settlement negotiations, and in February 2018 the LPSC staff and Entergy Louisiana filed an unopposed settlement. If approved by the LPSC, the settlement would provide for Entergy Louisiana to recover, over ten years, the approximately $1.4 million in deferred operation and maintenance expense and related carrying charges. The settlement further provides for recovery to commence in May 2018.
2017 Rate Stabilization Plan Filing
In January 2018, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for test year ended September 30, 2017. The filing of the evaluation report for the test year 2017 reflected an earned return on common equity of 9.06%. This earned return is below the earnings sharing band of the rate stabilization plan and results in a rate increase of $0.1 million. Due to the enactment in late-December 2017 of the Tax Cuts and Jobs Act, Entergy Louisiana did not have adequate time to reflect the effects of this tax legislation in the rate stabilization plan. As a result, Entergy Louisiana will file a supplement to the January 2018 evaluation report to reflect, among other things, a 21% federal corporate income tax rate. Any rate change resulting from the revised rate stabilization plan will become effective in rates in May 2018.
Fuel and purchased power recovery
Entergy Louisiana recovers electric fuel and purchased power costs for the billing month based upon the level of such costs incurred two months prior to the billing month. Entergy Louisiana’s purchased gas adjustments include
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
estimates for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
In April 2010 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit included a review of the reasonableness of charges flowed through the fuel adjustment clause by Entergy Louisiana for the period from 2005 through 2009. The LPSC staff issued its audit report in January 2013. The LPSC staff recommended that Entergy Louisiana refund approximately $1.9 million, plus interest, to customers and realign the recovery of approximately $1 million from Entergy Louisiana’s fuel adjustment clause to base rates. The recommended refund was made by Entergy Louisiana in May 2013 in the form of a credit to customers through its fuel adjustment clause filing. In October 2016 the LPSC staff filed testimony affirming the recommendation in its audit report on the lone remaining issue that nuclear dry fuel storage costs should be realigned to base rates. The parties agreed to remove that remaining issue to a separate docket because the same issue was outstanding in the Entergy Gulf States Louisiana audit for the same time period. In November 2016 the LPSC approved the resolution of this audit and the creation of a new docket for the resolution of the proper method of recovery for nuclear dry fuel storage costs. In December 2016 the LPSC opened a new docket in order to resolve the issue regarding the proper methodology for the recovery of nuclear dry fuel storage costs. In October 2017 the LPSC approved the continued recovery of the nuclear dry fuel storage costs through the fuel adjustment clause, resolving the open issue in the audit.
In December 2011 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates. The audit included a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009. In March 2016 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $8.6 million, plus interest, to customers and realign the recovery of approximately $12.7 million from Entergy Gulf States Louisiana’s fuel adjustment clause to base rates. In September 2016 the LPSC staff filed testimony stating that it was no longer recommending a disallowance of $3.4 million of the $8.6 million discussed above, but otherwise maintained positions from its report. Subsequently, the parties entered into a settlement, which was approved by the LPSC in November 2016. The settlement recognized the dry cask storage recovery method issue, which was addressed in the separate proceeding approved by the LPSC in October 2017, provided for a refund of $5 million, which was made to legacy Entergy Gulf States Louisiana customers in December 2016, and resolved all other issues raised in the audit.
In July 2014 the LPSC authorized its staff to initiate an audit of Entergy Gulf States Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period from 2010 through 2013. Discovery commenced in July 2015. No report of audit has been issued.
In July 2014 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Louisiana through its fuel adjustment clause for the period from 2010 through 2013. Discovery commenced in July 2015. No report of audit has been issued.
In June 2016 the LPSC staff provided notice of audits of Entergy Louisiana’s fuel adjustment clause filings and purchased gas adjustment clause filings. In recognition of the business combination that occurred in 2015, the audit notice was issued to Entergy Louisiana and will also include a review of charges to legacy Entergy Gulf States Louisiana customers prior to the business combination. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2014 through 2015 and charges flowed through Entergy Louisiana’s purchased gas adjustment clause for the period from 2012 through 2015. Discovery commenced in March 2017. No report of audit has been issued.
Due to higher fuel costs for the operating month of January 2018 resulting in part from recent cold weather, higher Henry Hub prices, and an increase in total fuel and purchased power costs, Entergy Louisiana plans to cap the
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
average fuel adjustment charge to be billed in March 2018 at $0.03060 per kWh and to defer billing of all fuel costs in excess of the capped amounts by including such costs in the over- or under-recovery account.
Industrial and Commercial Customers
Entergy Louisiana’s large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Louisiana’s industrial customer base. Entergy Louisiana responds by working with industrial and commercial customers and negotiating electric service contracts to provide competitive rates that match specific customer needs and load profiles. Entergy Louisiana actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation– Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Nuclear Matters
Entergy Louisiana owns and, through an affiliate, operates the River Bend and Waterford 3 nuclear power plants. Entergy Louisiana is, therefore, subject to the risks related to owning and operating nuclear plants. These include risks related to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, to position Entergy’s nuclear fleet to meet its operational goals, including the financial requirements to address emerging issues like stress corrosion cracking of certain materials within the plant systems and the Fukushima event; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license renewal and amendments, and decommissioning; the performance and capacity factors of these nuclear plants; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts and types of insurance commercially available for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident. In the event of an unanticipated early shutdown of River Bend or Waterford 3, Entergy Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.
Waterford 3’s operating license is currently due to expire in December 2024. In March 2016, Entergy Louisiana filed an application with the NRC for an extension of Waterford 3’s operating license to 2044. River Bend’s operating license is currently due to expire in August 2025. In May 2017, Entergy Louisiana filed an application with the NRC for an extension of River Bend’s operating license to 2045. In October 2017 an intervenor filed with the NRC a petition to intervene and request for a hearing on the River Bend license renewal application. As provided by NRC procedure, a panel of the Atomic Safety and Licensing Board has been designated to determine whether the intervenor’s three proposed contentions, or allegations of errors or omissions in the license renewal application, are admissible and, if so, to rule on any admitted contentions. In January 2018 the Atomic Safety and Licensing Board denied the petition to intervene and the request for hearing.
Environmental Risks
Entergy Louisiana’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Louisiana is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
“Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Louisiana’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Louisiana’s financial position or results of operations.
Nuclear Decommissioning Costs
See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Unbilled Revenue
See “Unbilled Revenue” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the unbilled revenue amounts.
Impairment of Long-lived Assets and Trust Fund Investments
See “Impairment of Long-lived Assets and Trust Fund Investments” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets and trust fund investments.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
Entergy Louisiana’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
|
| | | | | | |
Actuarial Assumption | | Change in Assumption | | Impact on 2018 Qualified Pension Cost | | Impact on 2017 Projected Qualified Benefit Obligation |
| | | | Increase/(Decrease) | | |
Discount rate | | (0.25%) | | $3,737 | | $54,506 |
Rate of return on plan assets | | (0.25%) | | $3,309 | | $— |
Rate of increase in compensation | | 0.25% | | $1,726 | | $8,824 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
|
| | | | | | |
Actuarial Assumption | | Change in Assumption | | Impact on 2018 Postretirement Benefit Cost | | Impact on 2017 Accumulated postretirement Benefit Obligation |
| | | | Increase/(Decrease) | | |
Discount rate | | (0.25%) | | $753 | | $10,727 |
Health care cost trend | | 0.25% | | $1,219 | | $8,675 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Funding
Total qualified pension cost for Entergy Louisiana in 2017 was $44.3 million. Entergy Louisiana anticipates 2018 qualified pension cost to be $52.1 million. In 2016, Entergy Louisiana refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $14.2 million. Entergy Louisiana contributed $87.5 million to its pension plans in 2017 and estimates pension contributions will be approximately $71.9 million in 2018, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018.
Total postretirement health care and life insurance benefit costs for Entergy Louisiana in 2017 were $12.6 million. Entergy Louisiana expects 2018 postretirement health care and life insurance benefit costs of approximately $11.2 million. In 2016, Entergy Louisiana refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $3.5 million. Entergy Louisiana contributed $14.4 million to its other postretirement plans in 2017 and estimates that 2018 contributions will be approximately $19 million.
Federal Healthcare Legislation
See “Qualified Pension and Other Postretirement Benefits -Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the members and Board of Directors of
Entergy Louisiana, LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Louisiana, LLC and Subsidiaries (the “Company”) as of December 31, 2017 and 2016, the related consolidated statements of income, comprehensive income, cash flows, and changes in equity (pages 349 through 354 and applicable items in pages 55 through 230), for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 2018
We have served as the Company’s auditor since 2001.
|
| | | | | | | | | | | | |
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
CONSOLIDATED INCOME STATEMENTS |
| | |
| | For the Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In Thousands) |
| | | | | | |
OPERATING REVENUES | | | | | | |
Electric | |
| $4,246,020 |
| |
| $4,126,343 |
| |
| $4,361,524 |
|
Natural gas | | 54,530 |
| | 50,705 |
| | 55,622 |
|
TOTAL | | 4,300,550 |
| | 4,177,048 |
| | 4,417,146 |
|
| | | | | | |
OPERATING EXPENSES | | |
| | |
| | |
|
Operation and Maintenance: | | |
| | |
| | |
|
Fuel, fuel-related expenses, and gas purchased for resale | | 912,060 |
| | 804,433 |
| | 850,869 |
|
Purchased power | | 980,070 |
| | 890,058 |
| | 1,129,910 |
|
Nuclear refueling outage expenses | | 52,074 |
| | 51,361 |
| | 44,480 |
|
Other operation and maintenance | | 969,400 |
| | 923,779 |
| | 997,546 |
|
Decommissioning | | 49,457 |
| | 46,944 |
| | 43,445 |
|
Taxes other than income taxes | | 175,359 |
| | 165,665 |
| | 167,966 |
|
Depreciation and amortization | | 467,369 |
| | 451,290 |
| | 437,036 |
|
Other regulatory charges (credits) - net | | (152,080 | ) | | 44,131 |
| | 27,562 |
|
TOTAL | | 3,453,709 |
| | 3,377,661 |
| | 3,698,814 |
|
| | | | | | |
OPERATING INCOME | | 846,841 |
| | 799,387 |
| | 718,332 |
|
| | | | | | |
OTHER INCOME | | |
| | |
| | |
|
Allowance for equity funds used during construction | | 51,485 |
| | 27,925 |
| | 19,192 |
|
Interest and investment income | | 164,550 |
| | 154,778 |
| | 150,168 |
|
Miscellaneous - net | | (11,960 | ) | | (11,597 | ) | | (13,190 | ) |
TOTAL | | 204,075 |
| | 171,106 |
| | 156,170 |
|
| | | | | | |
INTEREST EXPENSE | | |
| | |
| | |
|
Interest expense | | 275,185 |
| | 273,283 |
| | 259,894 |
|
Allowance for borrowed funds used during construction | | (25,914 | ) | | (14,571 | ) | | (10,702 | ) |
TOTAL | | 249,271 |
| | 258,712 |
| | 249,192 |
|
| | | | | | |
INCOME BEFORE INCOME TAXES | | 801,645 |
| | 711,781 |
| | 625,310 |
|
| | | | | | |
Income taxes | | 485,298 |
| | 89,734 |
| | 178,671 |
|
| | | | | | |
NET INCOME | | 316,347 |
| | 622,047 |
| | 446,639 |
|
| | | | | | |
Preferred distribution requirements and other | | — |
| | — |
| | 5,737 |
|
| | | | | | |
EARNINGS APPLICABLE TO COMMON EQUITY | |
| $316,347 |
| |
| $622,047 |
| |
| $440,902 |
|
| | | | | | |
See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | | | | | |
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| | |
| | For the Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In Thousands) |
| | | | | | |
Net Income | |
| $316,347 |
| |
| $622,047 |
| |
| $446,639 |
|
| | | | | | |
Other comprehensive income | | |
| | |
| | |
|
Pension and other postretirement liabilities | | |
| | |
| | |
|
(net of tax expense of $234, $5,034, and $14,316) | | 2,042 |
| | 7,970 |
| | 22,811 |
|
Other comprehensive income | | 2,042 |
| | 7,970 |
| | 22,811 |
|
| | | | | | |
Comprehensive Income | |
| $318,389 |
| |
| $630,017 |
| |
| $469,450 |
|
| | | | | | |
See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | | | | | |
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | For the Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In Thousands) |
OPERATING ACTIVITIES | | | | | | |
Net income | |
| $316,347 |
| |
| $622,047 |
| |
| $446,639 |
|
Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 621,018 |
| | 620,211 |
| | 593,635 |
|
Deferred income taxes, investment tax credits, and non-current taxes accrued | | 575,804 |
| | 178,549 |
| | 97,461 |
|
Changes in working capital: | | |
| | |
| | |
|
Receivables | | (53,829 | ) | | (102,200 | ) | | (12,795 | ) |
Fuel inventory | | 11,010 |
| | (2,693 | ) | | (887 | ) |
Accounts payable | | 58,880 |
| | (36,720 | ) | | 23,641 |
|
Prepaid taxes and taxes accrued | | 128,261 |
| | (235,246 | ) | | 105,687 |
|
Interest accrued | | (70 | ) | | 1,218 |
| | 2,933 |
|
Deferred fuel costs | | 23,236 |
| | (17,023 | ) | | 4,222 |
|
Other working capital accounts | | (30,911 | ) | | 6,462 |
| | (41,890 | ) |
Changes in provisions for estimated losses | | (8,324 | ) | | 490 |
| | (8,946 | ) |
Changes in other regulatory assets | | 492,696 |
| | 57,579 |
| | 130,762 |
|
Changes in other regulatory liabilities | | 605,453 |
| | 62,351 |
| | 96,234 |
|
Deferred tax rate change recognized as regulatory liability/asset | | (1,207,808 | ) | | — |
| | — |
|
Changes in pension and other postretirement liabilities | | (32,309 | ) | | (52,559 | ) | | (98,695 | ) |
Other | | (161,909 | ) | | (64,554 | ) | | (182,485 | ) |
Net cash flow provided by operating activities | | 1,337,545 |
| | 1,037,912 |
| | 1,155,516 |
|
INVESTING ACTIVITIES | | |
| | |
| | |
|
Construction expenditures | | (1,662,835 | ) | | (1,030,416 | ) | | (845,227 | ) |
Allowance for equity funds used during construction | | 51,485 |
| | 27,925 |
| | 19,192 |
|
Insurance proceeds | | 5,305 |
| | 10,564 |
| | — |
|
Nuclear fuel purchases | | (197,829 | ) | | (73,618 | ) | | (244,040 | ) |
Proceeds from the sale of nuclear fuel | | 42,634 |
| | 63,304 |
| | 54,595 |
|
Payment for purchase of plant | | — |
| | (474,670 | ) | | — |
|
Payments to storm reserve escrow account | | (2,110 | ) | | (1,063 | ) | | (308 | ) |
Receipts from storm reserve escrow account | | 8,835 |
| | — |
| | — |
|
Changes in securitization account | | 880 |
| | 351 |
| | (137 | ) |
Proceeds from nuclear decommissioning trust fund sales | | 231,293 |
| | 219,182 |
| | 123,474 |
|
Investment in nuclear decommissioning trust funds | | (266,592 | ) | | (257,209 | ) | | (158,028 | ) |
Changes in money pool receivable - net | | 11,330 |
| | (16,349 | ) | | (3,339 | ) |
Proceeds from sale of assets | | — |
| | — |
| | 59,610 |
|
Payment for purchase of assets | | (9,805 | ) | | — |
| | — |
|
Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | — |
| | 57,934 |
| | — |
|
Net cash flow used in investing activities | | (1,787,409 | ) | | (1,474,065 | ) | | (994,208 | ) |
FINANCING ACTIVITIES | | |
| | |
| | |
|
Proceeds from the issuance of long-term debt | | 733,344 |
| | 2,450,063 |
| | 77,172 |
|
Retirement of long-term debt | | (407,736 | ) | | (1,488,870 | ) | | (180,595 | ) |
Redemption of preferred membership interests | | — |
| | — |
| | (110,286 | ) |
Changes in credit borrowings - net | | 39,746 |
| | (56,562 | ) | | 14,322 |
|
Distributions paid: | | |
| | |
| | |
|
Common equity | | (91,250 | ) | | (285,500 | ) | | (226,000 | ) |
Preferred membership interests | | — |
| | — |
| | (6,082 | ) |
Other | | (2,183 | ) | | (4,230 | ) | | (15,253 | ) |
Net cash flow provided by (used in) financing activities | | 271,921 |
| | 614,901 |
| | (446,722 | ) |
Net increase (decrease) in cash and cash equivalents | | (177,943 | ) | | 178,748 |
| | (285,414 | ) |
Cash and cash equivalents at beginning of period | | 213,850 |
| | 35,102 |
| | 320,516 |
|
Cash and cash equivalents at end of period | |
| $35,907 |
| |
| $213,850 |
| |
| $35,102 |
|
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
|
Cash paid (received) during the period for: | | |
| | |
| | |
|
Interest - net of amount capitalized | |
| $266,871 |
| |
| $324,456 |
| |
| $243,745 |
|
Income taxes | |
| ($234,199 | ) | |
| $156,605 |
| |
| $89,124 |
|
Non-cash financing activities: | | | | | | |
Capital contribution from parent | |
| $— |
| |
| $— |
| |
| ($267,826 | ) |
See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | |
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
CONSOLIDATED BALANCE SHEETS |
ASSETS |
| | |
| | December 31, |
| | 2017 | | 2016 |
| | (In Thousands) |
| | | | |
CURRENT ASSETS | | | | |
Cash and cash equivalents: | | | | |
Cash | |
| $5,836 |
| |
| $49,972 |
|
Temporary cash investments | | 30,071 |
| | 163,878 |
|
Total cash and cash equivalents | | 35,907 |
| | 213,850 |
|
Accounts receivable: | | |
| | |
|
Customer | | 254,308 |
| | 213,517 |
|
Allowance for doubtful accounts | | (8,430 | ) | | (6,277 | ) |
Associated companies | | 143,524 |
| | 155,794 |
|
Other | | 60,893 |
| | 54,186 |
|
Accrued unbilled revenues | | 153,118 |
| | 159,176 |
|
Total accounts receivable | | 603,413 |
| | 576,396 |
|
Fuel inventory | | 39,728 |
| | 50,738 |
|
Materials and supplies - at average cost | | 299,881 |
| | 294,421 |
|
Deferred nuclear refueling outage costs | | 65,711 |
| | 22,535 |
|
Prepaid taxes | | — |
| | 110,104 |
|
Prepayments and other | | 34,035 |
| | 41,687 |
|
TOTAL | | 1,078,675 |
| | 1,309,731 |
|
| | | | |
OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
Investment in affiliate preferred membership interests | | 1,390,587 |
| | 1,390,587 |
|
Decommissioning trust funds | | 1,312,073 |
| | 1,140,707 |
|
Storm reserve escrow account | | 284,759 |
| | 291,485 |
|
Non-utility property - at cost (less accumulated depreciation) | | 245,255 |
| | 217,494 |
|
Other | | 18,999 |
| | 28,844 |
|
TOTAL | | 3,251,673 |
| | 3,069,117 |
|
| | | | |
UTILITY PLANT | | |
| | |
|
Electric | | 19,678,536 |
| | 18,827,532 |
|
Natural gas | | 191,899 |
| | 172,816 |
|
Construction work in progress | | 1,281,452 |
| | 670,201 |
|
Nuclear fuel | | 337,402 |
| | 249,807 |
|
TOTAL UTILITY PLANT | | 21,489,289 |
| | 19,920,356 |
|
Less - accumulated depreciation and amortization | | 8,703,047 |
| | 8,420,596 |
|
UTILITY PLANT - NET | | 12,786,242 |
| | 11,499,760 |
|
| | | | |
DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
Regulatory assets: | | |
| | |
|
Regulatory asset for income taxes - net | | — |
| | 470,480 |
|
Other regulatory assets (includes securitization property of $71,367 as of December 31, 2017 and $92,951 as of December 31, 2016) | | 1,145,842 |
| | 1,168,058 |
|
Deferred fuel costs | | 168,122 |
| | 168,122 |
|
Other | | 18,310 |
| | 16,003 |
|
TOTAL | | 1,332,274 |
| | 1,822,663 |
|
| | | | |
TOTAL ASSETS | |
| $18,448,864 |
| |
| $17,701,271 |
|
| | | | |
See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | | |
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
CONSOLIDATED BALANCE SHEETS |
LIABILITIES AND EQUITY |
| | |
| | December 31, |
| | 2017 | | 2016 |
| | (In Thousands) |
| | | | |
CURRENT LIABILITIES | | | | |
Currently maturing long-term debt | |
| $675,002 |
| |
| $200,198 |
|
Short-term borrowings | | 43,540 |
| | 3,794 |
|
Accounts payable: | | |
| | |
|
Associated companies | | 126,685 |
| | 82,106 |
|
Other | | 404,374 |
| | 358,741 |
|
Customer deposits | | 150,623 |
| | 148,601 |
|
Taxes accrued | | 18,157 |
| | — |
|
Interest accrued | | 75,528 |
| | 75,598 |
|
Deferred fuel costs | | 71,447 |
| | 48,211 |
|
Other | | 79,037 |
| | 80,013 |
|
TOTAL | | 1,644,393 |
| | 997,262 |
|
| | | | |
NON-CURRENT LIABILITIES | | |
| | |
|
Accumulated deferred income taxes and taxes accrued | | 2,050,371 |
| | 2,691,118 |
|
Accumulated deferred investment tax credits | | 121,870 |
| | 126,741 |
|
Regulatory liability for income taxes - net | | 725,368 |
| | — |
|
Other regulatory liabilities | | 761,059 |
| | 880,974 |
|
Decommissioning | | 1,140,461 |
| | 1,082,685 |
|
Accumulated provisions | | 302,448 |
| | 310,772 |
|
Pension and other postretirement liabilities | | 748,384 |
| | 780,278 |
|
Long-term debt (includes securitization bonds of $77,736 as of December 31, 2017 and $99,217 as of December 31, 2016) | | 5,469,069 |
| | 5,612,593 |
|
Other | | 176,637 |
| | 137,039 |
|
TOTAL | | 11,495,667 |
| | 11,622,200 |
|
| | | | |
Commitments and Contingencies | |
|
| |
|
|
| | | | |
EQUITY | | |
| | |
|
Member’s equity | | 5,355,204 |
| | 5,130,251 |
|
Accumulated other comprehensive loss | | (46,400 | ) | | (48,442 | ) |
TOTAL | | 5,308,804 |
| | 5,081,809 |
|
| | | | |
TOTAL LIABILITIES AND EQUITY | |
| $18,448,864 |
| |
| $17,701,271 |
|
| | | | |
See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | | | | | | | | | |
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
For the Years Ended December 31, 2017, 2016, and 2015 |
| | | | | |
| | | Common Equity | | |
| Preferred Membership Interests | | Member’s Equity | | Accumulated Other Comprehensive Income (Loss) | | Total |
| (In Thousands) |
| | | | | | | |
Balance at December 31, 2014 |
| $110,000 |
| |
| $4,316,210 |
| |
| ($79,223 | ) | |
| $4,346,987 |
|
Net income | — |
| | 446,639 |
| | — |
| | 446,639 |
|
Other comprehensive income | — |
| | — |
| | 22,811 |
| | 22,811 |
|
Preferred stock redemption | (110,000 | ) | | — |
| | — |
| | (110,000 | ) |
Non-cash contribution from parent | — |
| | 267,826 |
| | — |
| | 267,826 |
|
Distributions to parent | — |
| | (226,000 | ) | | — |
| | (226,000 | ) |
Distributions declared on preferred membership interests | — |
| | (5,737 | ) | | — |
| | (5,737 | ) |
Other | — |
| | (5,214 | ) | | — |
| | (5,214 | ) |
Balance at December 31, 2015 |
| $— |
| |
| $4,793,724 |
| |
| ($56,412 | ) | |
| $4,737,312 |
|
Net income | — |
| | 622,047 |
| | — |
| | 622,047 |
|
Other comprehensive income | — |
| | — |
| | 7,970 |
| | 7,970 |
|
Distributions to parent | — |
| | (285,500 | ) | | — |
| | (285,500 | ) |
Other | — |
| | (20 | ) | | — |
| | (20 | ) |
Balance at December 31, 2016 |
| $— |
| |
| $5,130,251 |
| |
| ($48,442 | ) | |
| $5,081,809 |
|
Net income | — |
| | 316,347 |
| | — |
| | 316,347 |
|
Other comprehensive income | — |
| | — |
| | 2,042 |
| | 2,042 |
|
Distributions declared on common equity | — |
| | (91,250 | ) | | — |
| | (91,250 | ) |
Other | — |
| | (144 | ) | | — |
| | (144 | ) |
Balance at December 31, 2017 |
| $— |
| |
| $5,355,204 |
| |
| ($46,400 | ) | |
| $5,308,804 |
|
| | | | | | | |
See Notes to Financial Statements. | |
| | |
| | |
| | |
|
|
| | | | | | | | | | | | | | | | | | | |
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | |
| 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| (In Thousands) |
| | | | | | | | | |
Operating revenues |
| $4,300,550 |
| |
| $4,177,048 |
| |
| $4,417,146 |
| |
| $4,740,504 |
| |
| $4,399,511 |
|
Net income |
| $316,347 |
| |
| $622,047 |
| |
| $446,639 |
| |
| $446,022 |
| |
| $414,126 |
|
Total assets |
| $18,448,864 |
| |
| $17,701,271 |
| |
| $16,387,447 |
| |
| $16,423,825 |
| |
| $15,275,863 |
|
Long-term obligations (a) |
| $5,469,069 |
| |
| $5,612,593 |
| |
| $4,806,790 |
| |
| $4,882,813 |
| |
| $4,383,273 |
|
| | | | | | | | | |
(a) Includes long-term debt (excluding currently maturing debt).
| | | | |
| | | | | | | | | |
| 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| (Dollars In Millions) |
| | | | | | | | | |
Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
|
Residential |
| $1,198 |
| |
| $1,196 |
| |
| $1,292 |
| |
| $1,358 |
| |
| $1,304 |
|
Commercial | 956 |
| | 930 |
| | 989 |
| | 1,044 |
| | 1,003 |
|
Industrial | 1,534 |
| | 1,350 |
| | 1,420 |
| | 1,569 |
| | 1,457 |
|
Governmental | 69 |
| | 67 |
| | 67 |
| | 70 |
| | 68 |
|
Total retail | 3,757 |
| | 3,543 |
| | 3,768 |
| | 4,041 |
| | 3,832 |
|
Sales for resale: | |
| | |
| | |
| | |
| | |
|
Associated companies | 278 |
| | 368 |
| | 406 |
| | 427 |
| | 320 |
|
Non-associated companies | 64 |
| | 50 |
| | 36 |
| | 80 |
| | 48 |
|
Other | 147 |
| | 165 |
| | 152 |
| | 121 |
| | 140 |
|
Total |
| $4,246 |
| |
| $4,126 |
| |
| $4,362 |
| |
| $4,669 |
| |
| $4,340 |
|
| | | | | | | | | |
Billed Electric Energy Sales (GWh): | |
| | |
| | |
| | |
| | |
|
Residential | 13,357 |
| | 13,810 |
| | 14,399 |
| | 14,415 |
| | 14,026 |
|
Commercial | 11,342 |
| | 11,478 |
| | 11,700 |
| | 11,555 |
| | 11,402 |
|
Industrial | 29,754 |
| | 28,517 |
| | 27,713 |
| | 27,025 |
| | 25,734 |
|
Governmental | 790 |
| | 794 |
| | 756 |
| | 732 |
| | 723 |
|
Total retail | 55,243 |
| | 54,599 |
| | 54,568 |
| | 53,727 |
| | 51,885 |
|
Sales for resale: | |
| | |
| | |
| | |
| | |
|
Associated companies | 4,793 |
| | 7,345 |
| | 7,500 |
| | 6,240 |
| | 5,168 |
|
Non-associated companies | 1,711 |
| | 1,690 |
| | 770 |
| | 1,051 |
| | 979 |
|
Total | 61,747 |
| | 63,634 |
| | 62,838 |
| | 61,018 |
| | 58,032 |
|
| | | | | | | | | |
ENTERGY MISSISSIPPI, INC.
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
Net Income
2017 Compared to 2016
Net income increased $0.8 million primarily due to higher other income, lower other operation and maintenance expenses, and lower interest expense, substantially offset by higher depreciation and amortization expenses and a higher effective income tax rate.
2016 Compared to 2015
Net income increased $16.5 million primarily due to lower other operation and maintenance expenses, higher net revenues, and a lower effective income tax rate, partially offset by higher depreciation and amortization expenses.
Net Revenue
2017 Compared to 2016
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory credits. Following is an analysis of the change in net revenue comparing 2017 to 2016.
|
| | | |
| Amount |
| (In Millions) |
| |
2016 net revenue |
| $705.4 |
|
Volume/weather | (18.2 | ) |
Retail electric price | 13.5 |
|
Other | 2.4 |
|
2017 net revenue |
| $703.1 |
|
The volume/weather variance is primarily due to the effect of less favorable weather on residential and commercial sales.
The retail electric price variance is primarily due to a $19.4 million net annual increase in rates, effective with the first billing cycle of July 2016, and an increase in the energy efficiency rider, effective with the first billing cycle of February 2017, each as approved by the MPSC. The increase was partially offset by decreased storm damage rider revenues due to resetting the storm damage provision to zero beginning with the November 2016 billing cycle. Entergy Mississippi resumed billing the storm damage rider effective with the September 2017 billing cycle. See Note 2 to the financial statements for more discussion of the formula rate plan and the storm damage rider.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
2016 Compared to 2015
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2016 to 2015.
|
| | | |
| Amount |
| (In Millions) |
| |
2015 net revenue |
| $696.3 |
|
Retail electric price | 12.9 |
|
Volume/weather | 4.7 |
|
Net wholesale revenue | (2.4 | ) |
Reserve equalization | (2.8 | ) |
Other | (3.3 | ) |
2016 net revenue |
| $705.4 |
|
The retail electric price variance is primarily due to a $19.4 million net annual increase in revenues, as approved by the MPSC, effective with the first billing cycle of July 2016, and an increase in revenues collected through the storm damage rider. See Note 2 to the financial statements for more discussion of the formula rate plan and the storm damage rider.
The volume/weather variance is primarily due to an increase of 153 GWh, or 1%, in billed electricity usage, including an increase in industrial usage, partially offset by the effect of less favorable weather on residential and commercial sales. The increase in industrial usage is primarily due to expansion projects in the pulp and paper industry, increased demand for existing customers, primarily in the metals industry, and new customers in the wood products industry.
The net wholesale revenue variance is primarily due to Entergy Mississippi’s exit from the System Agreement in November 2015.
The reserve equalization revenue variance is primarily due to the absence of reserve equalization revenue as compared to the same period in 2015 resulting from Entergy Mississippi’s exit from the System Agreement in November 2015.
Other Income Statement Variances
2017 Compared to 2016
Other operation and maintenance expenses decreased primarily due to:
a decrease of $12 million in fossil-fueled generation expenses primarily due to lower long-term service agreement costs and a lower scope of work done during plant outages in 2017 as compared to the same period in 2016; and
a decrease of $3.6 million in storm damage provisions. See Note 2 to the financial statements for a discussion on storm cost recovery.
The decrease was partially offset by an increase of $4.8 million in energy efficiency costs and an increase of $2.7 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 2017 as compared to the prior year.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Other income increased primarily due to interest income recorded in connection with the opportunity sales proceeding, interest income recorded on the deferred fuel balance, and an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2017 as compared to 2016. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding.
Interest expense decreased primarily due to the refinancing at lower interest rates of certain first mortgage bonds in 2016 and the retirement, at maturity, of $125 million of 3.25% Series first mortgage bonds in June 2016. See Note 5 to the financial statements for details of long-term debt.
2016 Compared to 2015
Other operation and maintenance expenses decreased primarily due to:
a decrease of $9.4 million in fossil-fueled generation expenses primarily due to a lower scope of work done during plant outages in 2016 as compared to the same period in 2015;
a decrease of $6.1 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;
a decrease of $2 million due to lower write-offs of uncollectible customer accounts in 2016;
a decrease of $2 million in energy efficiency costs; and
several individually insignificant items.
The decrease was partially offset by an increase of $7.1 million in storm damage provisions and an increase of $6 million in distribution expenses primarily due to higher vegetation maintenance. See Note 2 to the financial statements for a discussion of storm cost recovery.Entergy Louisiana’s filings to recover storm-related costs.
DepreciationOther
In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and amortization expenses increased primarily due to additions to plant in service.
Income Taxes
The effective incomethe second is captioned “In re: Investigation of tax ratesstructure issues for 2017,all LPSC-jurisdictional utilities.” In April 2016 and 2015 were 40.2%, 36.9%, and 40.0%, respectively. See Note 3the LPSC clarified that the concerns giving rise to the financial statements fortwo dockets arose as a reconciliationresult of its review of the federal statutory ratestructure of 35%the Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax obligation at the parent level of a consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the effective income tax rates.
Income Tax Legislation
Seedirective from other commissioners but several remarked that the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussionintent of the Tax Cuts and Jobs Act, the federal income tax legislation enacted in December 2017. Note 3directive was not initiated to the financial statements contains additional discussionpursue retail open access. In furtherance of the effectdirective, the LPSC issued a notice of the Act on 2017 resultsopening of operationsa docket to conduct a rulemaking to research and financial position, the provisions of the Act, and the uncertainties associated with accountingevaluate customer-centered options for the Act, and Note 2 to the financial statements discusses proceedings commenced orall electric customer classes as well as other responses by Entergy’s regulators to the Act.regulatory environments in January 2020.
Entergy Mississippi Inc.
Management’s Financial Discussion and Analysis
Fuel Recovery
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2017, 2016, and 2015 were as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
| (In Thousands) |
Cash and cash equivalents at beginning of period |
| $76,834 |
| |
| $145,605 |
| |
| $61,633 |
|
| | | | | |
Net cash provided by (used in): | |
| | |
| | |
|
Operating activities | 226,585 |
| | 212,280 |
| | 372,279 |
|
Investing activities | (417,226 | ) | | (289,444 | ) | | (245,127 | ) |
Financing activities | 119,903 |
| | 8,393 |
| | (43,180 | ) |
Net increase (decrease) in cash and cash equivalents | (70,738 | ) | | (68,771 | ) | | 83,972 |
|
| | | | | |
Cash and cash equivalents at end of period |
| $6,096 |
| |
| $76,834 |
| |
| $145,605 |
|
Operating Activities
Net cash flow provided by operating activities increased $14.3 million in 2017 primarily dueEntergy Mississippi’s rate schedules include energy cost recovery riders to the timing of recovery ofrecover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs in 2017 as comparedof the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to 2016 and an increaseannual audits conducted pursuant to the authority of $12.6 million in income tax refunds in 2017 as compared to 2016.the MPSC.
To help stabilize electricity costs, Entergy Mississippi had income tax refunds in 2017 and 2016 in accordance with an intercompany income tax allocation agreement. The 2017 income tax refunds were primarily due to the utilization of Entergy Mississippi’s federal net operating losses and state income tax refunds resultingreceived approval from the carrybackMPSC to hedge its exposure to natural gas price volatility through the use of net operating losses. The increase was partially offset by the timing of payments to vendors.
Net cash flow provided by operating activities decreased $160 million in 2016 primarily due to the timing of recovery of fuel and purchased power costs in 2016 as compared to the same period in 2015 and $15.3 million in insurance proceeds received in 2015 related to the unplanned outage event that occurred at the Baxter Wilson (Unit 1) power plant in September 2013. The decrease was partially offset by income tax refunds of $12.5 million in 2016 compared to income tax payments of $61.3 million in 2015.financial instruments. Entergy Mississippi had income tax refunds in 2016 and income tax payments in 2015 in accordance with an intercompany income tax allocation agreement. The 2016 income tax refunds resulted primarily from adjustments associated with the settlementhedges approximately one-third of the 2010-2011 IRS audit whereasprojected exposure to natural gas price changes for the income tax payments in 2015 were primarily duegas used to serve its native electric load for all months of the resultsyear. The hedge quantity is reviewed on an annual basis.
Part I Item 1
Entergy Corporation, Utility operating companies, and the reversal of taxable temporary differences as well as final settlement of amounts outstanding associated with the 2006-2007 IRS audit. System Energy
Storm Cost Recovery
See Note 32 to the financial statements for a discussion of the income tax audits.
Investing Activities
Net cash flow used in investing activities increased $127.8 million in 2017 primarily due to:
an increase of $48.4 million in transmission construction expenditures primarily due to a higher scope of work performed in 2017 as compared to 2016;
an increase of $39.2 million in fossil-fueled generation construction expenditures primarily due to a higher scope of work performed in 2017 as compared to 2016; and
an increase of $30.2 million in distribution construction expenditures primarily due to an increase in storm spending in 2017 as compared to 2016 and increased spending on digital technology improvements within the customer contact centers.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Net cash flow used in investing activities increased $44.3 million in 2016 primarily due to:
an increase of $72.4 million in transmission construction expenditures primarily due to a higher scope of work performed in 2016 as compared to 2015;
insurance proceeds of $12.9 million received in 2015 related to the unplanned outage event that occurred at the Baxter Wilson (Unit 1) power plant in September 2013;
an increase of $11.4 million in distribution construction expenditures primarily due to a higher scope of non-storm related work performed in 2016 as compared to 2015; and
an increase of $10.1 million due to various information technology projects and upgrades.
The increase was partially offset by a decrease of $20.1 million in fossil-fueled generation construction expenditures primarily due to a decreased scope of work performed during plant outages in 2016 as compared to 2015 and money pool activity.
Decreases in Entergy Mississippi’s receivable from the money pool are a source of cash flow, and Entergy Mississippi’s receivable from the money pool decreased by $15.3 million in 2016 compared to increasing by $25.3 million in 2015. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Financing Activities
Net cash flow provided by financing activities increased $111.5 million in 2017 primarily due to the issuance of $150 million of 3.25% Series first mortgage bonds in November 2017 and the redemption of $30 million of 6.25% Series preferred stock in 2016, partially offset by the net issuance of $61.4 million of long-term debt in 2016.
Entergy Mississippi’s financing activities provided $8.4 million of cash in 2016 compared to using $43.2 million in 2015 primarily due to the net issuance of $61.4 million of long-term debt in 2016 and a decrease of $16 million in common stock dividends paid in 2016, partially offset by the redemption of $30 million of 6.25% Series preferred stock. The decrease in dividends paid was primarily because of lower operating cash flows and higher capital expenditures, each discussed above.
See Note 5 to the financial statements for details on long-term debt.
Capital Structure
Entergy Mississippi’s capitalization is balanced between equity and debt, as shown in the following table. The increase in the debt to capital ratio for Entergy Mississippi is primarily due to the issuance of long-term debt in 2017.
|
| | | | | |
| December 31, 2017 | | December 31, 2016 |
Debt to capital | 51.5 | % | | 50.2 | % |
Effect of subtracting cash | (0.2 | %) | | (1.8 | %) |
Net debt to net capital | 51.3 | % | | 48.4 | % |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, capital lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt, preferred stock without sinking fund, and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Mississippi uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Mississippi’s financial condition. Entergy Mississippi uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
and creditors in evaluating Entergy Mississippi’s financial condition because net debt indicates Entergy Mississippi’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Mississippi seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Mississippi may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure. In addition, in certain infrequent circumstances, such as large transactions that would materially alter the capital structure if financed entirely with debt and reducing dividends, Entergy Mississippi may receive equity contributions to maintain the targeted capital structure.
Uses of Capital
Entergy Mississippi requires capital resources for:
construction and other capital investments;
debt and preferred stock maturities or retirements;
working capital purposes, including the financing of fuel and purchased power costs; and
dividend and interest payments.
Following are the amountsproceedings regarding recovery of Entergy Mississippi’s planned construction and other capital investments.storm-related costs.
|
| | | | | | | | | | | |
| 2018 | | 2019 | | 2020 |
| (In Millions) |
Planned construction and capital investment: | | | | | |
Generation |
| $55 |
| |
| $45 |
| |
| $260 |
|
Transmission | 145 |
| | 100 |
| | 105 |
|
Distribution | 125 |
| | 140 |
| | 130 |
|
Utility Support | 70 |
| | 50 |
| | 35 |
|
Total |
| $395 |
| |
| $335 |
| |
| $530 |
|
Following are the amounts of Entergy Mississippi’s existing debt obligations and lease obligations (includes estimated interest payments) and other purchase obligations.
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2019-2020 | | 2021-2022 | | After 2022 | | Total |
| (In Millions) |
Long-term debt (a) |
| $50 |
| |
| $234 |
| |
| $80 |
| |
| $1,784 |
| |
| $2,148 |
|
Operating leases |
| $12 |
| |
| $19 |
| |
| $12 |
| |
| $6 |
| |
| $49 |
|
Purchase obligations (b) |
| $280 |
| |
| $519 |
| |
| $490 |
| |
| $5,304 |
| |
| $6,593 |
|
| |
(a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
(b) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Mississippi, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the financial statements. |
In addition to the contractual obligations given above, Entergy Mississippi currently expects to contribute approximately $14.9 million to its qualified pension plans and approximately $110 thousand to other postretirement health care and life insurance plans in 2018, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018 See “Critical Accounting Estimates
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
– Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Mississippi includes amounts associated with specific investments such as transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including investment to support advanced metering; resource planning, including potential generation projects; system improvements; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the financial statements.
As a wholly-owned subsidiary, Entergy Mississippi dividends its earnings to Entergy Corporation at a percentage determined monthly. Provisions in Entergy Mississippi’s articles of incorporation relating to preferred stock restrict the amount of retained earnings available for the payment of cash dividends or other distributions on its common and preferred stock.
Advanced Metering Infrastructure (AMI)
In November 2016, Entergy Mississippi filed an application seeking an order from the MPSC granting a certificate of public convenience and necessity and finding that Entergy Mississippi’s deployment of AMI is in the public interest. Entergy Mississippi proposed to replace existing meters with advanced meters that enable two-way data communication; to design and build a secure and reliable network to support such communications; and to implement support systems. AMI is intended to serve as the foundation of Entergy Mississippi’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, and Entergy Mississippi provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal benefit to customers of $496 million over a 15-year period, which when netted against the costs of AMI results in $183 million of net customer benefits. Entergy Mississippi also sought to continue to include in rate base the remaining book value, approximately $56 million at December 31, 2015, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Mississippi proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019, subject to approval by the MPSC, with deployment of the communications network expected to begin in 2018. Entergy Mississippi proposed to include the AMI deployment costs and the quantified benefits in existing rate mechanisms, primarily through future formula rate plan filings and/or future energy cost recovery rider schedule re-determinations, as applicable. In May 2017 the Mississippi Public Utilities Staff and Entergy Mississippi entered into and filed a joint stipulation supporting Entergy Mississippi’s filing, and the MPSC issued an order approving the filing without material changes, finding that Entergy Mississippi’s deployment of AMI is in the public interest and granting a certificate of public convenience and necessity. The MPSC order also confirmed that Entergy Mississippi shall continue to include in rate base the remaining book value of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates.
Sources of Capital
Entergy Mississippi’s sources to meet its capital requirements include:
internally generated funds;
cash on hand;
debt or preferred stock issuances; and
bank financing under new or existing facilities.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Entergy Mississippi may refinance, redeem, or otherwise retire debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
All debt and common and preferred stock issuances by Entergy Mississippi require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in its corporate charter, bond indenture, and other agreements. Entergy Mississippi has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Mississippi’s receivables from the money pool were as follows as of December 31 for each of the following years.
|
| | | | | | |
2017 | | 2016 | | 2015 | | 2014 |
(In Thousands) |
$1,633 | | $10,595 | | $25,930 | | $644 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Mississippi has four separate credit facilities in the aggregate amount of $102.5 million scheduled to expire May 2018. No borrowings were outstanding under the credit facilities as of December 31, 2017. In addition, Entergy Mississippi is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2017, a $15.3 million letter of credit was outstanding under Entergy Mississippi’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
Entergy Mississippi obtained authorizations from the FERC through October 2019 for short-term borrowings not to exceed an aggregate amount of $175 million at any time outstanding and long-term borrowings and security issuances. See Note 4 to the financial statements for further discussion of Entergy Mississippi’s short-term borrowing limits.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Mississippi charges for electricity significantly influence its financial position, results of operations, and liquidity. Entergy Mississippi is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the MPSC, is primarily responsible for approval of the rates charged to customers.
Formula Rate Plan
In August 2012 the MPSC opened inquiries to review whether the current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan was still appropriate or could be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan proceeding. In March 2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans. The docket remains open.
Entergy New Orleans
Fuel Recovery
Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.
Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of its natural gas hedging program consistent with the City Council’s stated policy objectives. The program uses financial instruments to hedge exposure to volatility in the wholesale price of natural gas purchased to serve Entergy New Orleans gas customers. Entergy New Orleans hedges up to 25% of actual gas sales made during the winter months.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy New Orleans’s efforts to recover storm-related costs.
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Energy Efficiency Programs
A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. The rate settlement provided an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provided a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. In January 2015 the City Council approved funding for the Energy Smart program from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In April 2017 the City Council approved an implementation plan for the Energy Smart program from April 2017 through December 2019. The City Council directed that the $11.8 million balance reported for Energy Smart funds be used to continue funding the program for Entergy New Orleans’s legacy customers and that the Energy Smart Algiers program continue to be funded through the Algiers fuel adjustment clause, until additional customer funding is required for the legacy customers. In September 2017, Entergy New Orleans filed a supplemental plan and proposed several options for an interim cost recovery mechanism necessary to recover program costs during the period between when existing funds directed to Energy Smart programs are depleted and when new rates from the 2018 combined rate case, which includes a cost recovery mechanism for Energy Smart funding, take effect. In December 2017 the City Council approved an energy efficiency cost recovery rider as an interim funding mechanism for Energy Smart, subject to verification that no additional funding sources exist. In June 2018 the City Council also approved a resolution recommending that Entergy New Orleans allocate approximately $13.5 million of benefits resulting from the Tax Act to Energy Smart. See Note 2 to the financial statements for discussion of Entergy New Orleans’s application with the City Council seeking approval of an implementation plan for the Energy Smart program from April 2020 through December 2022.
Entergy Texas
Fuel Recovery
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included in base rates. Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. The PUCT fuel cost proceedings are discussed in Note 2 to the financial statements.
At the PUCT’s April 2013 open meeting, the PUCT Commissioners discussed their view that a purchased power capacity rider was good public policy. The PUCT issued an order in May 2013 adopting the rule allowing for a purchased power capacity rider, subject to an offsetting adjustment for load growth. The rule, as adopted, also includes a process for obtaining pre-approval by the PUCT of purchased power agreements. Entergy Texas has not exercised the option to recover its capacity costs under the new rider mechanism, but will continue to evaluate the benefits of utilizing the new rider to recover future capacity costs.
Electric Industry Restructuring
In June 2009, a law was enacted in Texas that required Entergy Texas to cease all activities relating to Entergy Texas’s transition to competition. The law allows Entergy Texas to remain a part of the SERC Reliability Corporation (SERC) Region, although it does not prevent Entergy Texas from joining another power region. The law provides that proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding
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exist. Under the law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT’s certification of Entergy Texas’s power region.
The law also contains provisions that allow Entergy Texas to take advantage of a cost recovery mechanism that permits annual filings for the recovery of reasonable and necessary expenditures for transmission infrastructure improvement and changes in wholesale transmission charges. This mechanism was previously available to other non-ERCOT Texas utility companies, but not to Entergy Texas.
The law further amended already existing law that had required Entergy Texas to propose for PUCT approval a tariff to allow eligible customers the ability to contract for competitive generation. The amending language in the law provides, among other things, that: 1) the tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers who choose not to participate in the tariff; 2) Entergy Texas shall “purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer;” and 3) Entergy Texas shall provide and price transmission service and ancillary services under that tariff at a rate that is unbundled from its cost of service. The law directs that the PUCT may not issue an order on the tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction.
The PUCT determined that unrecovered costs that may be recovered through the rider consist only of those costs necessary to implement and administer the competitive generation program and do not include lost revenues or embedded generation costs. The amount of customer load that may be included in the competitive generation service program is limited to 115 MW.
In September 2011 the PUCT adopted a proposed rule implementing a distribution cost recovery factor to recover capital and capital-related costs related to distribution infrastructure. The distribution cost recovery factor permits utilities once per year to implement an increase or decrease in rates above or below amounts reflected in base rates to reflect depreciation expense, federal income tax and other taxes, and return on investment. The distribution cost recovery factor rider may be changed a maximum of four times between base rate cases.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery factor rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas franchises are considered to be contracts and, therefore, are terminable pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.
Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
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Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas, and holds non-exclusive franchises to provide electric service in approximately 68 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire over the period 2020-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
Property and Other Generation Resources
Owned Generating Stations
The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2020, is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Owned and Leased Capability MW(a) |
Company | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
Entergy Arkansas | | 5,175 | | | 2,091 | | | 1,817 | | | 1,194 | | | 73 | | | — | |
Entergy Louisiana | | 11,317 | | | 8,827 | | | 2,144 | | | 346 | | | — | | | — | |
Entergy Mississippi | | 3,347 | | | 2,929 | | | — | | | 416 | | | — | | | 2 | |
Entergy New Orleans | | 665 | | | 638 | | | — | | | — | | | — | | | 27 | |
Entergy Texas | | 2,260 | | | 2,005 | | | — | | | 255 | | | — | | | — | |
System Energy | | 1,256 | | | — | | | 1,256 | | | — | | | — | | | — | |
Total | | 24,020 | | | 16,490 | | | 5,217 | | | 2,211 | | | 73 | | | 29 | |
(a)“Owned and Leased Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.
Summer peak load for the Utility has averaged 21,591 MW over the previous decade.
The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 8,801 MW of new long-term resources and the deactivation of about 4,664 MW of legacy generation. As MISO market participants, the Utility operating companies also participate in MISO’s Day Ahead and Real Time Energy and Ancillary Services markets to economically dispatch generation and purchase energy to serve customers reliably and at the lowest reasonable cost.
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Other Generation Resources
RFP Procurements
The Utility operating companies from time to time issue requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies. The RFPs issued by the Utility operating companies have sought resources needed to meet near-term MISO reliability requirements as well as long-term requirements through a broad range of wholesale power products, including limited-term (1 to 3 years) and long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
•Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine J. Wayne Leonard Power Station (previously referred to as the St. Charles generating facility) at its existing Little Gypsy electric generating station. The facility began commercial operation in May 2019;
•Entergy Texas’s construction of the 993 MW, combined-cycle, gas turbine Montgomery County Power Station at its existing Lewis Creek electric generating station. The facility began commercial operation in January 2021;
•Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station site. The facility began commercial operation in March 2020;
•In October 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the facility is scheduled to be in service by early 2022;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020 and the facility is scheduled to be in service by the end of 2021;
•Entergy New Orleans received regulatory approval in August 2019 to construct the New Orleans Solar Station (a 20 MW self-build solar project) located at the NASA Michoud Facility.The facility was placed in service in December 2020;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,000 acres in Lee County, Arkansas. In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2022;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. Closing is expected to occur by the end of 2023; and
•In June 2020, Entergy Texas signed an agreement for the purchase of an approximately 100 MW to-be- constructed solar photovoltaic energy facility that will be sited on approximately 1,200 acres in Liberty County near Dayton, Texas.In September 2020, Entergy Texas filed a petition with the PUCT seeking a finding that the transaction is in the public interest and requesting all necessary approvals.Closing is expected to occur by the end of 2023.
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The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:
•River Bend’s 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
•Entergy Arkansas’s wholesale base load capacity life-of-unit PPAs executed in 2003 totaling approximately 220 MW between Entergy Arkansas and Entergy Louisiana (110 MW) and between Entergy Arkansas and Entergy New Orleans (110 MW) related to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which had not been included in Entergy Arkansas’s retail rates);
•In May 2011, Entergy Texas and Calpine Energy Services, L.P. executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. Entergy Louisiana purchases 50% of the facility’s capacity and energy from Entergy Texas. In July 2014, LS Power purchased the Carville Energy Center and replaced Calpine Energy Services as the counterparty to the agreement;
•In September 2012, Entergy Gulf States Louisiana executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 MW when available, from Rain CII Carbon LLC’s petroleum coke calcining facility in Sulphur, Louisiana. The facility began commercial operation in May 2013. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with the facility;
•In March 2013, Entergy Gulf States Louisiana executed a 20-year agreement for 8.5 MW from Agrilectric Power Partners, LP’s refurbished rice hull-fueled electric generation facility located in Lake Charles, Louisiana. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with Agrilectric;
•In September 2013, Entergy Louisiana executed a 10-year agreement with TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, to purchase approximately 3 MW from its landfill gas-fueled power generation facility located in Cleveland, Texas;
•Entergy Mississippi’s cost-based purchase, beginning in January 2013, of 90 MW from Entergy Arkansas’s share of Grand Gulf (only 60 MW of this PPA came through the RFP process). Cost recovery for the 90 MW was approved by the MPSC in January 2013;
•In April 2015, Entergy Arkansas and Stuttgart Solar, LLC executed a 20-year agreement for 81 MW from a solar photovoltaic electric generation facility located near Stuttgart, Arkansas. The APSC approved the project and deliveries pursuant to that agreement commenced in June 2018;
•In November 2016, Entergy Louisiana and LS Power executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. The transaction received regulatory approval and will begin in June 2022;
•In November 2016, Entergy Louisiana and Occidental Chemical Corporation executed a 10-year agreement for 500 MW from the Taft Cogeneration facility located in Hahnville, Louisiana. The transaction received regulatory approval and began in June 2018;
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
•In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021;
•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a five-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
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•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and is targeting commercial operation in mid-2021; and
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a solar photovoltaic electric generating facility located in Polk County, Texas.The PPA is expected to start when the facility reaches commercial operation in 2023.
In April 2020, Entergy Services, on behalf of Entergy Texas, issued an RFP for combined-cycle gas turbine capacity and energy resources. The RFP was seeking up to 1,000 MW - 1,200 MW of capacity, capacity-related benefits, energy, other electric products, and environmental attributes, if any, from a single generation resource located in the “Eastern Region” of Entergy Texas’s service area. In December 2020, Entergy Texas posted notice that it has elected to proceed with the self-build alternative, Orange County Power Station. The self-build alternative will be conditioned on receipt of required internal and regulatory approvals.
In June 2020, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic resources. The RFP was seeking 300 MW of energy, capacity, capacity-related benefits, other electric products, and environmental attributes from eligible new-build solar photovoltaic generation resources. In December 2020, Entergy Louisiana concluded evaluations of the RFP. Three proposals have been placed on the primary selection list and two proposals have been placed on the secondary selection list. Negotiations are currently in progress.
In January 2021, Entergy Texas provided notice that it intends to issue an RFP for solar generation resources. The RFP is seeking a minimum of 200 MW through a combination of build-own-transfer agreements, self-build alternatives, and power purchase agreements that can provide cost-effective energy supply, fuel diversity, and other benefits to Entergy Texas customers.
Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process, including Entergy Mississippi’s January 2006 acquisition of the 480 MW, combined-cycle, gas-fired Attala power plant; Entergy Gulf States Louisiana’s March 2008 acquisition of the 322 MW, simple-cycle, gas-fired Calcasieu Generating Facility; Entergy Louisiana’s April 2011 acquisition of the 580 MW, combined-cycle, gas-fired Acadia Energy Center Unit 2; Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) March 2016 acquisitions of the 1,980 MW (summer rating), natural gas-fired, combined-cycle gas turbine Union Power Station power blocks, each rated at 495 MW (summer rating); and Entergy Mississippi’s October 2019 acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The Utility operating companies have also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.
The Washington Parish Energy Center is a 361 MW natural gas-fired peaking power plant approximately 60 miles north of New Orleans on a site Entergy Louisiana purchased from Calpine in 2019. In May 2018, Entergy Louisiana received LPSC approval of its certification application for this simple-cycle power plant to be developed pursuant to an agreement between Calpine and Entergy Louisiana. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020.
The Hardin County Peaking Facility is an existing 147 MW simple-cycle gas-fired peaking power plant in Kountze, Texas, owned by East Texas Electric Cooperative. Entergy Texas is currently seeking regulatory certification to move forward with the purchase of the facility. The facility has been in operation since January 2010.
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Power Through Program
In December 2020, Entergy Texas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation that is to be installed at commercial and industrial customer premises. If approved, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.”
Interconnections
The Utility operating companies’ generating units are interconnected to a transmission system operating at various voltages up to 500 kV. These generating units consist of steam-electric production facilities, combustion-turbine generators, pressurized and boiling water nuclear reactors, and inverter-based technologies operating in the MISO energy and ancillary services market. Entergy’s Utility operating companies are MISO market participants and are interconnected with many neighboring utilities. MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. As a Regional Transmission Organization, MISO assures consumers of unbiased regional grid management and open access to the transmission facilities under MISO’s functional supervision. In addition, the Utility operating companies are members of SERC Reliability Corporation (SERC). SERC is a nonprofit corporation responsible for promoting and improving the reliability, adequacy, and critical infrastructure of the bulk power supply systems in all or portions of 16 central and southeastern states.SERC serves as a regional entity with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing Bulk Electric System reliability standards within the SERC Region.
Gas Property
As of December 31, 2020, Entergy New Orleans distributed and transported natural gas for distribution within New Orleans, Louisiana, through approximately 2,600 miles of gas pipeline. As of December 31, 2020, the gas properties of Entergy Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Louisiana’s financial position.
Title
The Utility operating companies’ generating stations are generally located on properties owned in fee simple. Most of the substations and transmission and distribution lines are constructed on private property or public rights-of-way pursuant to easements, servitudes, or appropriate franchises. Some substation properties are owned in fee simple. The Utility operating companies generally have the right of eminent domain, whereby they may perfect title to, or secure easements or servitudes on, private property for their utility operations.
Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are subject to the liens of mortgages securing bonds issued by those companies. The Lewis Creek generating station of Entergy Texas was acquired by merger with a subsidiary of Entergy Texas and is currently not subject to the lien of the Entergy Texas indenture.
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Fuel Supply
The sources of generation and average fuel cost per kWh for the Utility operating companies and System Energy for the years 2018-2020 were:
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| | Natural Gas | | Nuclear | | Coal | | Purchased Power | | MISO Purchases |
Year | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh |
2020 | | 47 | | | 1.92 | | | 29 | | | 0.57 | | | 3 | | | 2.54 | | | 8 | | | 4.36 | | | 13 | | | 2.48 | |
2019 | | 40 | | | 2.33 | | | 28 | | | 0.73 | | | 6 | | | 2.31 | | | 8 | | | 4.86 | | | 18 | | | 2.71 | |
2018 | | 39 | | | 2.84 | | | 27 | | | 0.84 | | | 9 | | | 2.24 | | | 8 | | | 5.23 | | | 17 | | | 3.71 | |
Actual 2020 and projected 2021 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural Gas | | Nuclear | | Coal | | Purchased Power (d) | | MISO Purchases (e) |
| 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 |
Entergy Arkansas (a) | 24 | % | | 35 | % | | 60 | % | | 51 | % | | 10 | % | | 13 | % | | 1 | % | | 1 | % | | 5 | % | | — | |
Entergy Louisiana | 51 | % | | 59 | % | | 26 | % | | 27 | % | | 1 | % | | 2 | % | | 9 | % | | 12 | % | | 13 | % | | — | |
Entergy Mississippi (b) | 73 | % | | 69 | % | | 14 | % | | 22 | % | | 4 | % | | 9 | % | | — | | | — | | | 9 | % | | — | |
Entergy New Orleans (b) | 55 | % | | 56 | % | | 33 | % | | 40 | % | | 1 | % | | 2 | % | | 2 | % | | 2 | % | | 9 | % | | — | |
Entergy Texas | 39 | % | | 60 | % | | 11 | % | | 13 | % | | 2 | % | | 6 | % | | 23 | % | | 21 | % | | 25 | % | | — | |
System Energy (c) | — | | | — | | | 100 | % | | 100 | % | | — | | | — | | | — | | | — | | | — | | | — | |
Utility (a) (b) | 47 | % | | 55 | % | | 29 | % | | 31 | % | | 3 | % | | 6 | % | | 8 | % | | 8 | % | | 13 | % | | — | |
(a)Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2020 and is expected to provide less than 1% of its generation in 2021.
(b)Solar power provided less than 1% of Entergy Mississippi’s and Entergy New Orleans's generation in 2020 and is expected to provide less than 1% of each of Entergy Mississippi’s and Entergy New Orleans's generation in 2021.
(c)Capacity and energy from System Energy’s interest in Grand Gulf is allocated as follows under the Unit Power Sales Agreement: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%. Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.
(d)Excludes MISO purchases.
(e)In December 2013, Entergy integrated its transmission system into the MISO RTO. Entergy offers all of its generation into the MISO energy market on a day-ahead and real-time basis and bids for power in the MISO energy market to serve the demand of its customers, with MISO making dispatch decisions. The MISO purchases metric provided for 2020 is not projected for 2021.
Some of the Utility’s gas-fired plants are also capable of using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in 2021, it is possible that various operational events including weather or pipeline maintenance may require the use of fuel oil.
Natural Gas
The Utility operating companies have long-term firm and short-term interruptible gas contracts for both supply and transportation. Over 50% of the Utility operating companies’ power plants maintain some level of long-
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term firm transportation. Short-term contracts and spot-market purchases satisfy additional gas requirements. Entergy Texas owns a gas storage facility that provides reliable and flexible natural gas service to certain generating stations.
Many factors, including wellhead deliverability, storage, pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
Coal
Entergy Arkansas has committed to seven one- to three-year contracts that will supply approximately 85% of the total coal supply needs in 2021. These contracts are staggered in term so that not all contracts have to be renewed the same year. The remaining 15% of total coal requirements will be satisfied by contracts with a term of less than one year. Based on continued improved Powder River Basin (PRB) coal deliveries by rail and the high cost of alternate sources and modes of transportation, no alternative coal consumption is expected at Entergy Arkansas during 2021. Coal will be transported to Arkansas via an existing transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2021.
Entergy Louisiana has committed to five one- to three-year contracts that will supply approximately 90% of Nelson Unit 6 coal needs in 2021. If needed, additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as for Entergy Arkansas’s plants, no alternative coal consumption is expected at Nelson Unit 6 during 2021. Coal will be transported to Nelson primarily via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2021.
For the year 2020, coal transportation delivery rates to Entergy Arkansas-and Entergy Louisiana-operated coal-fired units were adequate to meet supply needs and obligations, and it is expected that delivery times in 2021 will continue to be consistent. Both Entergy Arkansas and Entergy Louisiana control a sufficient number of railcars to satisfy the rail transportation requirement.
The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2021. Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.
Nuclear Fuel
The nuclear fuel cycle consists of the following:
•mining and milling of uranium ore to produce a concentrate;
•conversion of the concentrate to uranium hexafluoride gas;
•enrichment of the uranium hexafluoride gas;
•fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and
•disposal of spent fuel.
The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated
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uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the owner of a nuclear power plant.
Based upon currently planned fuel cycles, the Utility nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through most of 2023. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. There are a number of possible supply alternatives that may be accessed to mitigate any supplier performance failure, including potentially drawing upon Entergy’s inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.
The effects of market price changes may be reduced and deferred by risk management strategies, such as negotiation of floor and ceiling amounts for long-term contracts, buying for inventory or entering into forward physical contracts at fixed prices when Entergy believes it is appropriate and useful. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance reliability of conversion, enrichment, and fabrication services providers. There are fewer of these providers than for uranium. For conversion and enrichment services, like uranium, Entergy diversifies its supply by supplier and country and may take special measures as needed to ensure supply of enriched uranium for the reliable fabrication of nuclear fuel. For fabrication services, each plant is dependent upon the effective performance of the fabricator of that plant’s nuclear fuel, therefore, Entergy provides additional monitoring, inspection, and oversight for the fabrication process to assure reliability and quality.
Entergy Arkansas, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the financial statements of Entergy and the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These credit facilities are subject to periodic renewal, and the notes are issued periodically, typically for terms between three and seven years.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with one interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with CenterPoint Energy Services which guarantees Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The CenterPoint Energy Service gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans also makes interruptible spot market purchases.
Entergy Louisiana purchased natural gas for resale in 2020 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.
Federal Regulation of the Utility
State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.
System Agreement (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Prior to each operating company’s termination of participation in the System Agreement (Entergy Arkansas in December 2013, Entergy Mississippi in November 2015, and Entergy Louisiana, Entergy New Orleans, and Entergy Texas each in August 2016), the Utility operating companies engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which was a rate schedule approved by the FERC. Under the terms of the System Agreement, generating capacity and other power resources were jointly operated by the Utility operating companies that were participating in the System Agreement. The System Agreement provided, among other things, that parties having generating reserves greater than their allocated share of reserves (long companies) would receive payments from those parties having generating reserves that were less than their allocated share of reserves (short companies). Such payments were at amounts sufficient to cover certain of the long companies’ costs for intermediate and peaking oil/gas-fired generation, including operating expenses, fixed charges on debt, dividend requirements on preferred equity, and a fair rate of return on common equity investment. Under the System Agreement, the rates used to compensate long companies were based on costs associated with the long companies’ steam electric generating units fueled by oil or gas and having an annual average heat rate above 10,000 Btu/kWh. In addition, for all energy exchanged among the Utility operating companies under the System Agreement, the companies purchasing exchange energy were required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs.
Although the System Agreement has terminated, certain of the Utility operating companies’ and their retail regulators are pursuing litigation involving the System Agreement at the FERC and in federal courts. The proceedings include challenges to the allocation of costs as defined by the System Agreement and other matters. See Note 2 to the financial statements for discussion of legal proceedings at the FERC and in federal courts involving the System Agreement.
Transmission and MISO Markets
In December 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO did not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities, MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and congestion management and provides schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the markets. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. Each Utility operating company has its own transmission pricing zone and a formula rate template (included as Attachment O to the MISO tariff) used to
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establish transmission rates within MISO. The terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets and the allocation of transmission upgrade costs, are subject to regulation by the FERC.
System Energy and Related Agreements
System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In July 2001 a rate proceeding commenced by System Energy at the FERC in 1995 became final, with the FERC approving a prospective 10.94% return on equity. In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas’s and Entergy Mississippi’s acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC. See Note 2 to the financial statements for discussion of complaints filed with the FERC regarding System Energy’s return on equity.
Unit Power Sales Agreement
The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.
In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf-related costs and recovers the remaining 78% of its share in rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas’s cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans that sell a portion of the output of Entergy Arkansas’s retained share of Grand Gulf to those companies, with the remainder of the retained share being sold to Entergy Mississippi through a separate life-of-resources purchased power agreement. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted rate relief with respect to costs associated with Entergy Louisiana’s share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Entergy Louisiana retains and does not recover from retail ratepayers 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause at 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC’s approval. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of the output of Entergy Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted rate relief for those purchases by the MPSC through its annual unit power cost rate mechanism.
Availability Agreement
The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the financing by System Energy
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of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges.
The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.
System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for its two outstanding series of first mortgage bonds. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.
Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be made directly to the holders of indebtedness that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.
The obligations of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans to make payments under the Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to the FERC for approval with respect to the terms of such sale. No such filing with the FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability Agreement, the jurisdictional portions of the Availability Agreement would be submitted to the FERC for approval.
Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement and, therefore, no payments under the Availability Agreement have ever been required. If Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their Availability Agreement obligations exceed their Unit Power Sales Agreement obligations.
The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors.
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Service Companies
Entergy Services, a limited liability company wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the Utility operating companies, but also provides services to Entergy Wholesale Commodities. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas
Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson Unit 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.
Entergy Texas purchases from Entergy Louisiana pursuant to a life-of-unit purchased power agreement a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend’s nuclear and environmental liabilities that is identical to the share of the plant’s output purchased by Entergy Texas under the purchased power agreement. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements.
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
On October 1, 2015, the businesses formerly conducted by Entergy Louisiana (Old Entergy Louisiana) and Entergy Gulf States Louisiana (Old Entergy Gulf States Louisiana) were combined into a single public utility. In order to effect the business combination, under the Texas Business Organizations Code (TXBOC), Old Entergy Louisiana allocated substantially all of its assets to a new subsidiary, Entergy Louisiana Power, LLC, a Texas limited liability company (New Entergy Louisiana), and New Entergy Louisiana assumed the liabilities of Old Entergy Louisiana, in a transaction regarded as a merger under the TXBOC. Under the TXBOC, Old Entergy Gulf States Louisiana allocated substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States Louisiana assumed the liabilities of Old Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. New Entergy Gulf States Louisiana then merged into New Entergy Louisiana with New Entergy Louisiana surviving the merger. Thereupon, Old Entergy Louisiana changed its name from “Entergy Louisiana, LLC” to “EL Investment Company, LLC” and New Entergy Louisiana changed its name from “Entergy Louisiana Power, LLC” to “Entergy Louisiana, LLC” (Entergy Louisiana). With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Old Entergy Louisiana and Old Entergy Gulf States Louisiana.
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Entergy New Orleans Internal Restructuring
In November 2017, pursuant to the agreement in principle, Entergy New Orleans, Inc. undertook a multi-step restructuring, including the following:
•Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.
•Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans, Inc. allocated substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power assumed substantially all of the liabilities of Entergy New Orleans, Inc. in a transaction regarded as a merger under the TXBOC. Entergy New Orleans, Inc. remained in existence and held the membership interests in Entergy New Orleans Power.
•Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The restructuring was accounted for as a transaction between entities under common control.
Entergy Arkansas Internal Restructuring
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Mississippi Internal Restructuring
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
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•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
Entergy Wholesale Commodities
Entergy Wholesale Commodities includes the ownership, operation, and decommissioning of nuclear power plants, located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities revenues are primarily derived from sales of energy and generation capacity from these plants. Entergy Wholesale Commodities also provides operations and management services, including decommissioning-related services, to nuclear power plants owned by non-affiliated entities in the United States. Entergy Wholesale Commodities also includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers.
See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
Property
Nuclear Generating Stations
Entergy Wholesale Commodities includes the ownership of the following nuclear power plants:
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Power Plant | | Market | | In Service Year | | Acquired | | Location | | Capacity - Reactor Type | | License Expiration Date |
Indian Point 3 (a) | | NYISO | | 1976 | | Nov. 2000 | | Buchanan, NY | | 1,041 MW - Pressurized Water | | 2025 (a) |
Indian Point 2 (a) | | NYISO | | 1974 | | Sept. 2001 | | Buchanan, NY | | 1,028 MW - Pressurized Water | | 2024 (a) |
Palisades (b) | | MISO | | 1971 | | Apr. 2007 | | Covert, MI | | 811 MW - Pressurized Water | | 2031 (b) |
(a)Power operations ceased at the Indian Point 2 plant in April 2020. The fuel was permanently removed from the reactor vessel and placed in the spent fuel pool in May 2020. The Indian Point 3 plant is expected to cease operations on April 30, 2021. Entergy and Holtec jointly filed a license transfer application with the NRC in November 2019, requesting approval for the transfer of the Indian Point plants, along with their nuclear decommissioning trusts and decommissioning liabilities, from Entergy to Holtec. The NRC approved the license transfer application on November 23, 2020.
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(b)The Palisades plant is expected to cease operations on May 31, 2022. There is a contract to sell the plant to Holtec subject to NRC and other regulatory approvals.
See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the operation and planned shutdown and sale of each of the remaining Entergy Wholesale Commodities nuclear power plants.
Entergy Wholesale Commodities also includes the ownership of two non-operating nuclear facilities, Big Rock Point in Michigan and Indian Point 1 in New York that were acquired when Entergy purchased the Palisades and Indian Point 2 nuclear plants, respectively. These facilities are in various stages of the decommissioning process. Both Big Rock Point and Indian Point 1 are under contract to be sold with their respective plants.
Non-nuclear Generating Stations
Entergy Wholesale Commodities includes the ownership, or interests in joint ventures that own, the following non-nuclear power plants:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Plant | | Location | | Ownership | | Net Owned Capacity (a) | | Type |
Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
RS Cogen; 425 MW (c) | | Lake Charles, LA | | 50% | | 213 MW | | Gas/Steam |
Nelson Unit 6; 550 MW | | Westlake, LA | | 11% | | 60 MW(b) | | Coal |
(a)“Net Owned Capacity” refers to the nameplate rating on the generating unit.
(b)The owned MW capacity is the portion of the plant capacity owned by Entergy Wholesale Commodities. For a complete listing of Entergy’s jointly-owned generating stations, refer to “Jointly-Owned Generating Stations” in Note 1 to the financial statements.
(c)Indirectly owned through an interest in an unconsolidated joint venture. In December 2020, Entergy’s wholly-owned subsidiary with a direct interest in RS Cogen, LLC entered into a membership interest purchase agreement with a subsidiary of the other 50% equity partner to sell its 50% membership interest in the joint venture to the equity partner. The targeted closing date for the transaction is October 2022.
Independent System Operators
The Indian Point plants fall under the authority of the New York Independent System Operator (NYISO). The Palisades plant falls under the authority of the MISO. The primary purpose of NYISO and MISO is to direct the operations of the major generation and transmission facilities in their respective regions; ensure grid reliability; administer and monitor wholesale electricity markets; and plan for their respective region’s energy needs.
Energy and Capacity Sales
As a wholesale generator, Entergy Wholesale Commodities’ core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and also sells energy in the day ahead or spot markets. Entergy Wholesale Commodities also sells unforced capacity, which allows load-serving entities to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Entergy Wholesale Commodities’ forward physical power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Entergy Wholesale Commodities to deliver MWh of energy, make capacity available, or both.See “Market and Credit Risk Sensitive Instruments” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for additional information regarding these contracts.
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As part of the purchase of the Palisades plant in 2007, Entergy executed a 15-year PPA with the seller, Consumers Energy, for 100% of the plant’s output, excluding any future uprates. Under the purchased power agreement, Consumers Energy receives the value of any new environmental credits for the first ten years of the agreement. Palisades and Consumers Energy will share on a 50/50 basis the value of any new environmental credits for years 11 through 15 of the agreement. The environmental credits are defined as benefits from a change in law that causes capability of the plant as of the purchase date to become a tradable attribute (e.g., emission credit, renewable energy credit, environmental credit, “green” credit, etc.) or otherwise to have a market value. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022 and transfer to Holtec thereafter.
Customers
Entergy Wholesale Commodities’ customers for the sale of both energy and capacity from its nuclear plants include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. These customers include Consumers Energy, the company from which Entergy purchased the Palisades plant, and NYISO and MISO. Substantially all the credit exposure associated with the planned energy output under contract for Entergy Wholesale Commodities nuclear plants is with counterparties or their guarantors that have public investment grade credit ratings.
Competition
The NYISO market is highly competitive. Entergy Wholesale Commodities has numerous competitors in New York including generation companies affiliated with regulated utilities, other independent power producers, municipal and co-operative generators, owners of co-generation plants and wholesale power marketers. Entergy Wholesale Commodities is an independent power producer, which means it generates power for sale to third parties at day ahead or spot market prices to the extent that the power is not sold under a fixed price contract. Municipal and co-operative generators also generate power but use most of it to deliver power to their municipal or co-operative power customers. Owners of co-generation plants produce power primarily for their own consumption. Wholesale power marketers do not own generation; rather they buy power from generators or other market participants and resell it to retail providers or other market participants. Competition in the New York power market is affected by, among other factors, the amount of generation and transmission capacity in these markets. MISO does not have a centralized clearing capacity market, but load serving entities do meet most of their capacity needs through bilateral contracts and self-supply with a smaller portion coming through voluntary MISO auctions. Almost all of Palisades’ current output is contracted to Consumers Energy through May 2022. Entergy Wholesale Commodities does not expect to be materially affected by competition in the MISO market in the near term.
Seasonality
Entergy Wholesale Commodities’ revenues and operating income are subject to fluctuations during the year due to seasonal factors, weather conditions, and contract pricing. When outdoor and cooling water temperatures are low, generally during colder months, Entergy Wholesale Commodities nuclear power plants operate more efficiently, and consequently, generate more electricity. Many of Entergy Wholesale Commodities’ contracts provide for shaped pricing over the course of the year. As a result of these factors, Entergy Wholesale Commodities’ revenues are typically higher in the first and third quarters than in the second and fourth quarters.
Fuel Supply
Nuclear Fuel
See “Fuel Supply - Nuclear Fuel” in the Utility portion of Part I, Item 1 for a discussion of the nuclear fuel cycle and markets. Entergy Nuclear Fuels Company, a wholly-owned subsidiary, is responsible for contracts to acquire nuclear materials, except for fuel fabrication, for Entergy Wholesale Commodities nuclear power plants,
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while Entergy Nuclear Operations, Inc. acts as the agent for the purchase of nuclear fuel assembly fabrication services. All contracts for the disposal of spent nuclear fuel are between the DOE and each of the nuclear power plant owners. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment has been adjusted to reflect reduced overall requirements related to the planned permanent shutdowns of the Indian Point 3 and Palisades plants. Fuel procurement for the Entergy Wholesale Commodities segment was primarily limited to the requirements of the Palisades plant’s final refueling in 2020.
Other Business Activities
Entergy Nuclear Power Marketing, LLC (ENPM) was formed in 2005 to centralize the power marketing function for Entergy Wholesale Commodities nuclear plants. Upon its formation, ENPM entered into long-term power purchase agreements with the Entergy Wholesale Commodities subsidiaries that own nuclear power plants (generating subsidiaries). As part of a series of agreements, ENPM agreed to assume and/or otherwise service the existing power purchase agreements that were in effect between the generating subsidiaries and their customers. ENPM’s functions include origination of new energy and capacity transactions and generation scheduling.
Services provided by either Entergy Nuclear, Inc. or other Entergy Wholesale Commodities subsidiaries include engineering, operations and maintenance, fuel procurement, management and supervision, technical support and training, administrative support, and other managerial or technical services required to operate, maintain, and decommission nuclear electric power facilities.
TLG Services, a subsidiary in the Entergy Wholesale Commodities segment, offers decommissioning, engineering, and related services to nuclear power plant owners.
Entergy provides plant operation support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. In 2010 an Entergy subsidiary signed an agreement to extend the management support services to Cooper Nuclear Station by 15 years, through January 2029.
Regulation of Entergy’s Business
Federal Power Act
The Federal Power Act provides the FERC the authority to regulate:
•the transmission and wholesale sale of electric energy in interstate commerce;
•the reliability of the high voltage interstate transmission system through reliability standards;
•sale or acquisition of certain assets;
•securities issuances;
•the licensing of certain hydroelectric projects;
•certain other activities, including accounting policies and practices of electric and gas utilities; and
•changes in control of FERC jurisdictional entities or rate schedules.
The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over the rates charged by Entergy Arkansas and Entergy Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the Utility operating companies. In addition, the FERC regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC regulation of the MISO RTO includes regulation of the design and implementation of the wholesale markets administered by the MISO RTO, as well as the rates, terms, and conditions of open access transmission service over the member systems and the allocation of costs associated with transmission upgrades.
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Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 70 MW of capacity.
State Regulation
Utility
Entergy Arkansas is subject to regulation by the APSC as to the following:
•utility service;
•utility service areas;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery rider;
•terms and conditions of service;
•service standards;
•the acquisition, sale, or lease of any public utility plant or property constituting an operating unit or system;
•certificates of convenience and necessity and certificates of environmental compatibility and public need, as applicable, for generating and transmission facilities;
•avoided cost payments to Qualifying Facilities;
•net energy metering;
•integrated resource planning;
•utility mergers and acquisitions and other changes of control; and
•the issuance and sale of certain securities.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory Authority only if it fails to treat its retail customers in Tennessee in the same manner as its retail customers in Arkansas. Additionally, Entergy Arkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to retail ratemaking or other regulatory jurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment clause and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•certification of certain transmission projects;
•certification of capacity acquisitions, both for owned capacity and purchase power contracts;
•procurement process to acquire over 50 MW;
•audits of the environmental adjustment charge, avoided cost payment to Qualifying Facilities, and energy efficiency rider;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control.
Entergy Mississippi is subject to regulation by the MPSC as to the following:
•utility service;
•utility service areas;
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•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery mechanism;
•terms and conditions of service;
•service standards;
•certification of generating facilities and certain transmission projects;
•avoided cost payments to Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers, acquisitions, and other changes of control.
Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.
Entergy New Orleans is subject to regulation by the City Council as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment charge and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•audit of the environmental adjustment charge;
•certification of the construction or extension of any new plant, equipment, property, or facility that comprises more than 2% of the utility’s rate base;
•integrated resource planning;
•net energy metering;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other changes of control.
To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to the following:
•retail rates and charges, including depreciation rates, and terms and conditions of service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;
•fuel recovery, including reconciliations (audits) of the fuel adjustment charges;
•service standards;
•certification of certain transmission and generation projects;
•utility service areas, including extensions into new areas;
•avoided cost payments to Qualifying Facilities;
•net energy metering; and
•utility mergers, sales/acquisitions/leases of plants over $10 million, sales of greater than 50% voting stock of utilities, and transfers of controlling interest in or operation of utilities.
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Regulation of the Nuclear Power Industry
Atomic Energy Act of 1954 and Energy Reorganization Act of 1974
Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC. Entergy subsidiaries in the Entergy Wholesale Commodities segment are subject to the NRC’s jurisdiction as the owners and operators of Indian Point Energy Center, Palisades, and Big Rock Point.
Nuclear Waste Policy Act of 1982
Spent Nuclear Fuel
Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Entergy’s nuclear owner/licensee subsidiaries have been charged fees for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2020 of $192.0 million for the one-time fee. Entergy accepted assignment of the Pilgrim, FitzPatrick, Indian Point 3, Indian Point 1 and Indian Point 2, Vermont Yankee, Palisades, and Big Rock Point spent fuel disposal contracts with the DOE held by their previous owners. The FitzPatrick spent fuel disposal contract was assigned to Exelon as part of the sale of the plant, completed in March 2017. The Vermont Yankee spent fuel disposal contract was assigned to NorthStar as part of the sale of the plant in January 2019. The Pilgrim spent fuel disposal contract was transferred to Holtec as part of the sale of Entergy Nuclear Generation Company in August 2019. The owners of these plants previous to Entergy have paid or retained liability for the fees for all generation prior to the purchase dates of those plants. The fees payable to the DOE may be adjusted in the future to assure full recovery. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.6 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).
The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing (the DOE filed the license application in June 2008) and, after the license is granted by the NRC, proceed with the repository construction and commencement of receipt of spent fuel. Because the DOE has not begun accepting spent fuel, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts. The DOE continues to delay meeting its obligation. Specific steps were taken to discontinue the Yucca Mountain project, including a motion to the NRC to withdraw the license application with prejudice and the establishment of a commission to develop recommendations for alternative spent fuel storage solutions. In August 2013 the U.S. Court of Appeals for the D.C. Circuit ordered the NRC to continue with the Yucca Mountain license review, but only to the extent of funds previously appropriated by Congress for that purpose and not yet used. Although the NRC completed the safety evaluation report for the license review in 2015, the previously appropriated funds are not sufficient to complete the review, including required hearings. The government has taken no effective action to date related to the recommendations of the appointed spent fuel study commission. Accordingly, large uncertainty remains regarding the time frame under
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which the DOE will begin to accept spent fuel from Entergy’s facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at Entergy’s nuclear sites.
Following the defunding of the Yucca Mountain spent fuel repository program, the National Association of Regulatory Utility Commissioners and others sued the government seeking cessation of collection of the one mill per net kWh generated and sold after April 7, 1983 fee. In November 2013 the D.C. Circuit Court of Appeals ordered the DOE to submit a proposal to Congress to reset the fee to zero until the DOE complies with the Nuclear Waste Policy Act or Congress enacts an alternative waste disposal plan. In January 2014 the DOE submitted the proposal to Congress under protest, and also filed a petition for rehearing with the D.C. Circuit. The petition for rehearing was denied. The zero spent fuel fee went into effect prospectively in May 2014.
As a result of the DOE’s failure to begin disposal of spent nuclear fuel in 1998 pursuant to the Nuclear Waste Policy Act of 1982 and the spent fuel disposal contracts, Entergy’s nuclear owner/licensee subsidiaries have incurred and will continue to incur damages. These subsidiaries have been, and continue to be, involved in litigation to recover the damages caused by the DOE’s delay in performance. See Note 8 to the financial statements for discussion of final judgments recorded by Entergy in 2018, 2019, and 2020 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE. Through 2020, Entergy’s subsidiaries won and collected on judgments against the government totaling approximately $800 million.
Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at Palisades in 1993, at ANO in 1996, at River Bend in 2005, at Grand Gulf in 2006, at Indian Point in 2008, and at Waterford 3 in 2011. These facilities will be expanded as needed.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Louisiana, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, Waterford 3, and Grand Gulf, respectively. In addition, Entergy Louisiana and Entergy Texas are entitled to recover from customers through electric rates the estimated decommissioning costs for the portion of River Bend subject to retail rate regulation. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.
In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In October 2020, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and ANO 2 decommissioning trusts were adequately funded without further collections, and in December 2020, the APSC ordered zero collections for ANO 1 and ANO 2 decommissioning.
In July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend to address previously identified funding shortfalls. This LPSC decision contemplated that the level of decommissioning collections could be revisited should the NRC grant license extensions for both Waterford 3 and River Bend. In July 2019, following the NRC approval of license extensions for Waterford 3 and River Bend, Entergy Louisiana made a filing with the LPSC seeking to adjust decommissioning and depreciation rates for those plants, including one proposed scenario that would adjust Louisiana-jurisdictional decommissioning collections to zero for both plants (including an offsetting increase in depreciation rates). Because of the ongoing public health emergency arising from the COVID-19 pandemic and accompanying economic uncertainty, Entergy Louisiana determined that the relief sought in the filing was no longer appropriate, and in November 2020, filed an unopposed motion to dismiss the proceeding. Following that filing, in a December 2020 order, the LPSC dismissed the proceeding without prejudice.
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In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2018 the PUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning fund was adequate following license renewal.
In September 2016 the NRC issued a 20-year operating license renewal for Grand Gulf. In a 2017 filing at the FERC, System Energy stated that with the renewed operating license, Grand Gulf’s decommissioning trust was sufficiently funded, and proposed, among other things, to cease decommissioning collections for Grand Gulf effective October 1, 2017. The FERC accepted a settlement including the proposed decommissioning revenue requirement by letter order in August 2018.
Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.
In January 2019, Entergy sold 100% of the membership interest in Entergy Nuclear Vermont Yankee to a subsidiary of NorthStar. As a result of the sale, NorthStar assumed ownership of Vermont Yankee and its decommissioning and site restoration trusts, together with complete responsibility for the facility’s decommissioning and site restoration. See Note 9 to the financial statements for further discussion of Vermont Yankee decommissioning costs and see “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the NorthStar transaction.
In August 2019, Entergy sold 100% of the equity interests in Entergy Nuclear Generation Company, LLC to a subsidiary of Holtec International. As a result of the sale, Holtec assumed ownership of Pilgrim and its decommissioning trust, together with complete responsibility for the facility’s decommissioning and site restoration. See Note 14 to the financial statements for further discussion of the sale.
For the Indian Point 3 and FitzPatrick plants purchased in 2000 from NYPA, NYPA retained the decommissioning trust funds and the decommissioning liabilities with the right to require the Entergy subsidiaries to assume each of the decommissioning liabilities provided that it assigns the corresponding decommissioning trust, up to a specified level, to the Entergy subsidiaries. In August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy, which was completed in January 2017. In March 2017, Entergy sold the FitzPatrick plant to Exelon, and as part of the transaction, the FitzPatrick decommissioning trust fund, along with the decommissioning obligation for that plant, was transferred to Exelon. The FitzPatrick spent fuel disposal contract was assigned to Exelon as part of the transaction. See Note 14 to the financial statements for discussion of the FitzPatrick sale.
In March 2020 filings with the NRC were made reporting on decommissioning funding for all of Entergy subsidiaries’ nuclear plants. Those reports showed that decommissioning funding for each of the nuclear plants met the NRC’s financial assurance requirements.
Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 16 to the financial statements.
Price-Anderson Act
The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect the public in the event of a nuclear power plant accident. The costs of this insurance
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are borne by the nuclear power industry. Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025. The Price-Anderson Act limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $137.6 million per reactor (with 97 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, System Energy, or an Entergy Wholesale Commodities company is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units is also purchased. The Price-Anderson Act and insurance applicable to the nuclear programs of Entergy are discussed in more detail in Note 8 to the financial statements.
NRC Reactor Oversight Process
The NRC’s Reactor Oversight Process is a program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response. The NRC evaluates plant performance by analyzing two distinct inputs: inspection findings resulting from the NRC’s inspection program and performance indicators reported by the licensee. The evaluations result in the placement of each plant in one of the NRC’s Reactor Oversight Process Action Matrix columns: “licensee response column,” or Column 1, “regulatory response column,” or Column 2, “degraded cornerstone column,” or Column 3, and “multiple/repetitive degraded cornerstone column,” or Column 4. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject to progressively increasing levels of inspection by the NRC with, in general, progressively increasing levels of associated costs. The nuclear generating plants owned and operated by Entergy’s Utility and Entergy Wholesale Commodities businesses are currently in Column 1, except for Grand Gulf, which is currently in Column 2.
In November 2020 the NRC placed Grand Gulf in Column 2 based on the incidence of three unplanned plant scrams during the second and third quarters of 2020.Two of the scram events related to new turbine control system components that failed, and a third related to a feedwater valve positioner that failed, all of which had been replaced in a refueling outage that ended in May 2020. The NRC plans to conduct a supplemental inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 2. As a consequence of two additional Grand Gulf scrams during the fourth quarter 2020, System Energy expects Grand Gulf to be placed into NRC Column 3 based on plant performance indicators for the four quarters ended December 31, 2020. This will involve an additional supplemental NRC inspection of Grand Gulf in accordance with its inspection procedures for nuclear plants in Column 3.
Environmental Regulation
Entergy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy’s businesses are in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted below. Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely estimated. Except to the extent discussed below, at this time compliance with federal, state, and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Entergy’s businesses and is not expected to have a material effect on their competitive position, results of operations, cash flows, or financial position.
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Clean Air Act and Subsequent Amendments
The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a lesser extent, certain operations at nuclear and other facilities. Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements. These programs include:
•New source review and preconstruction permits for new sources of criteria air pollutants, greenhouse gases, and significant modifications to existing facilities;
•Acid rain program for control of sulfur dioxide (SO2) and nitrogen oxides (NOx);
•Nonattainment area programs for control of criteria air pollutants, which could include fee assessments for air pollutant emission sources under Section 185 of the Clean Air Act if attainment is not reached in a timely manner;
•Hazardous air pollutant emissions reduction programs;
•Interstate Air Transport;
•Operating permit programs and enforcement of these and other Clean Air Act programs;
•Regional Haze programs; and
•New and existing source standards for greenhouse gas and other air emissions.
New Source Review (NSR)
Preconstruction permits are required for new facilities and for existing facilities that undergo a modification that results in a significant net emissions increase and is not classified as routine repair, maintenance, or replacement. Units that undergo certain non-routine modifications must obtain a permit modification and may be required to install additional air pollution control technologies. In December 2020 the EPA amended the NSR regulations to clarify when a physical change or change in the method of operation will constitute such a modification. Entergy has an established process for identifying modifications requiring additional permitting approval and is monitoring the regulations and associated guidance provided by the states and the federal government with regard to the determination of routine repair, maintenance, and replacement. Several years ago, however, the EPA implemented an enforcement initiative, aimed primarily at coal plants, to identify modifications that it does not consider routine for which the unit did not obtain a modified permit. Various courts and the EPA have been inconsistent in their judgments regarding modifications that are considered routine and on other legal issues that affect this program.
In February 2011, Entergy received a request from the EPA for several categories of information concerning capital and maintenance projects at the White Bluff and Independence facilities, both located in Arkansas, in order to determine compliance with the Clean Air Act, including NSR requirements and air permits issued by the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ). In August 2011, Entergy’s Nelson facility, located in Louisiana, received a similar request for information from the EPA. In September 2015 an additional request for similar information was received for the White Bluff facility. Entergy responded to all requests. None of these EPA requests for information alleged that the facilities were in violation of law.
In January and February 2018, Entergy Arkansas, Entergy Mississippi, Entergy Power, and other co-owners received 60-day notice of intent to sue letters from the Sierra Club and the National Parks Conservation Association concerning allegations of violations of new source review and permitting provisions of the Clean Air Act at the Independence and White Bluff coal-burning units, respectively. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims as well as other issues facing Entergy Arkansas’s fossil generation plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, is subject to approval by the U.S. District Court for the Eastern District of Arkansas. In October 2019 the District Court requested supplemental briefing on several issues to be resolved prior to addressing the motion to approve the
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settlement; that briefing was completed in May 2020. For further information about the settlement, see “Regional Haze” discussed below.
National Ambient Air Quality Standards
The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide, and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is classified as “marginal,” “moderate,” “serious,” or “severe.” When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.
Ozone Nonattainment
Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area that is not in attainment with the applicable NAAQS for ozone. The ozone nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Both Lewis Creek and the Montgomery County Power Station hold all necessary permits for construction and operation and comply with applicable air quality program regulations. Measures enacted to return the area to ozone attainment could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the ozone NAAQS.
Potential SO2Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. In Entergy’s utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana are designated as nonattainment. In August 2017 the EPA issued a letter indicating that East Baton Rouge and St. Charles parishes would be designated by December 31, 2020, as monitors were installed to determine compliance. In December 2020 the EPA designated East Baton Rouge, St. Charles, St. James, and West Baton Rouge parishes in Louisiana as attainment/unclassifiable, and, in Texas, Jefferson County as attainment/unclassifiable and Orange County as unclassifiable. Challenges to these final designations must be filed within 60 days of publication in the Federal Register. Entergy continues to monitor this situation.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2020 the EPA finalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. The final appropriate and necessary finding does not revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. Entergy will continue to monitor this situation.
Cross-State Air Pollution
In March 2005 the EPA finalized the Clean Air Interstate Rule (CAIR), which was intended to reduce SO2 and NOx emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule required a combination of capital investment to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy.
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Based on several court challenges, CAIR and its subsequent versions, now known as the Cross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions. In September 2016 the EPA finalized the CSAPR Update Rule to address interstate transport for the 2008 ozone NAAQS. Starting in 2017 the final rule requires reductions in summer nitrogen oxides (NOx) emissions. Several states, including Arkansas and Texas, filed a challenge to the Update Rule. In September 2019 the D.C. Circuit upheld the EPA’s underlying approach to the Update Rule, but determined that it was inconsistent with the Clean Air Act because it failed to include deadlines consistent with downwind states’ deadlines for attainment. The court remanded the rule to the EPA for further consideration, but did not vacate so the rule remains in effect pending the EPA’s further review. In October 2020 the EPA issued its proposal intended to address the D.C. Circuit’s remand. The draft rule proposes to finalize interstate transport obligations for 21 states. For nine states, including Arkansas, Mississippi, and Texas, the EPA proposes that additional emission reductions are not necessary. For 12 states, however, including Louisiana, the EPA proposes additional emission reductions through proposed reductions in the number of NOx emission allowances allocated to each state. Entergy, through its various trade associations, filed comments on the proposal and will continue to monitor the rulemaking and its potential impact on its facilities in Louisiana. If the October 2020 proposal is finalized, ozone season NOx emissions may become more expensive in Louisiana.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could result in a requirement to install SO2 and NOx pollution control technology as Best Available Retrofit Control Technology (BART) to continue operating certain of Entergy’s fossil generation units. The rule leaves certain CAVR determinations to the states.
In Arkansas, the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ) prepared a state implementation plan (SIP) for Arkansas facilities to implement its obligations under the CAVR. In April 2012 the EPA finalized a decision addressing the Arkansas Regional Haze SIP, in which it disapproved a large portion of the Arkansas plan, including the emission limits for NOx and SO2 at White Bluff. In April 2015 the EPA published a proposed federal implementation plan (FIP) for Arkansas, taking comment on requiring installation of scrubbers and low NOx burners to continue operating both units at the White Bluff plant and both units at the Independence plant and NOx controls to continue operating the Lake Catherine plant. Entergy filed comments by the deadline in August 2015. Among other comments, including opposition to the EPA’s proposed controls on the Independence units, Entergy proposed to meet more stringent SO2 and NOx limits at both White Bluff and Independence within three years of the effective date of the final FIP and to cease the use of coal at the White Bluff units at a later date.
In September 2016 the EPA published the final Arkansas Regional Haze FIP. In most respects, the EPA finalized its original proposal but shortened the time for compliance for installation of the NOx controls. The FIP required an emission limitation consistent with SO2 scrubbers at both White Bluff and Independence by October 2021 and NOx controls by April 2018. The EPA declined to adopt Entergy’s proposals related to ceasing coal use as an alternative to SO2 scrubbers for White Bluff SO2 BART. In November 2016, Entergy and other interested parties, including the State of Arkansas, filed petitions for administrative reconsideration and stay at the EPA as well as petitions for judicial review in the U.S. Court of Appeals for the Eighth Circuit. The Eighth Circuit granted the stay pending settlement discussions and pending the State’s development of a SIP that, if approved by the EPA, would replace the FIP. The state had proposed its replacement SIP in two parts: Part I considers NOx requirements, and Part II considers SO2 requirements. The EPA approved the Part I NOx SIP in January 2018. The Part I SIP requires that Entergy address NOx impacts on visibility via compliance with the Cross-State Air Pollution Rule ozone-season emission trading program. Arkansas has finalized a Part II SIP which has been approved by the EPA but is currently pending a state court appeal. That appeal has been stayed pending the outcome of a federal court case, which may resolve many of the issues on appeal. The final Part II SIP requires that Entergy achieve SO2 emission reductions via the use of low-sulfur coal at both White Bluff and Independence within three years. The
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Part II SIP also requires that Entergy cease to use coal at White Bluff by December 31, 2028 and notes the current planning assumption that Entergy’s Independence units will cease to use coal by December 31, 2030.
In January and February 2018, Entergy Arkansas, Entergy Mississippi, Entergy Power, and other co-owners received 60-day notice of intent to sue letters from the Sierra Club and the National Parks Conservation Association concerning allegations of violations of new source review and permitting provisions of the Clean Air Act at the Independence and White Bluff coal-burning units, respectively. In November 2018, following extensive negotiations, Entergy Arkansas, Entergy Mississippi, and Entergy Power entered a proposed settlement resolving those claims and reducing the risk that Entergy Arkansas, as operator of Independence and White Bluff, might be compelled under the Clean Air Act’s regional haze program to install costly emissions control technologies. Consistent with the terms of the settlement and in many cases also the Part II SIP, Entergy Arkansas, along with co-owners, will begin using only low-sulfur coal at Independence and White Bluff by mid-2021; cease to use coal at White Bluff and Independence by the end of 2028 and 2030, respectively; cease operation of the remaining gas unit at Lake Catherine by the end of 2027; reserve the option to develop new generating sources at each plant site; and commit to install or propose to regulators at least 800 MWs of renewable generation by the end of 2027, with at least half installed or proposed by the end of 2022 (which includes two existing Entergy Arkansas projects) and with all qualifying co-owner projects counting toward satisfaction of the obligation. Under the settlement, the Sierra Club and the National Parks Conservation Association also waive certain potential existing claims under federal and state environmental law with respect to specified generating plants. The settlement, which formally resolves a complaint filed by the Sierra Club and the National Parks Conservation Association, is subject to approval by the U.S. District Court for the Eastern District of Arkansas. The EPA, which is allowed to comment on such a settlement agreement, has stated that it has no objections to the settlement. In November 2020 the court denied motions by the Arkansas Attorney General and the Arkansas Affordable Energy Coalition to intervene and to stay the proceedings. The proposed intervenors did not appeal the ruling. Still pending before the court is a motion by the plaintiffs to approve the settlement, in support of which Entergy made a filing. The Arkansas Attorney General also filed an application before the APSC in December 2018 seeking an investigation into the effects of the settlement. The Arkansas Affordable Energy Coalition filed to support the Arkansas Attorney General’s application, and Entergy Arkansas filed a motion to dismiss it. The application remains pending before the APSC. In October 2019 the District Court requested supplemental briefing on several issues prior to addressing the motion to approve the settlement; that briefing concluded in May 2020.
In Louisiana, Entergy has worked with the Louisiana Department of Environmental Quality (LDEQ) and the EPA to revise the Louisiana SIP for regional haze, which had been disapproved in part in 2012. The LDEQ submitted a revised SIP in February 2017. In May 2017 the EPA proposed to approve a majority of the revisions. In September 2017 the EPA issued a proposed SIP approval for the Nelson plant, requiring an emission limitation consistent with the use of low-sulfur coal, with a compliance date of January 22, 2021. The EPA issued final approval in December 2017. The EPA approval was appealed to the U.S. Court of Appeals for the Fifth Circuit. In October 2019 the Fifth Circuit affirmed the EPA’s SIP approval. A petition for rehearing filed by plaintiffs was denied by the Fifth Circuit. Plaintiffs did not petition for further review by the Supreme Court.
The second planning period (2018-2028) for the regional haze program requires states to examine sources for impacts on visibility and to prepare SIPs by 2021. Entergy received information collection requests from Arkansas and Louisiana requesting an evaluation of technical and economic feasibility of various NOx and SO2 control technologies for Independence, Nelson 6, and Ninemile. Responses to the information requests have been submitted to the respective state agencies.
New and Existing Source Performance Standards for Greenhouse Gas Emissions
In July 2019 the EPA released the Affordable Clean Energy Rule (ACE), which applies only to existing coal-fired electric generating units. The ACE determines that heat rate improvements are the best system of emission reductions and lists six candidate technologies for consideration by states at each coal unit. The rule and associated rulemakings by the EPA replace the Obama administration’s Clean Power Plan, which established
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national emissions performance rates for existing fossil-fuel fired steam electric generating units and combustion turbines. The ACE rule provides states discretion in determining how the best system for emission reductions applies to individual units, including through the consideration of technical feasibility and the remaining useful life of the facility. The ADEQ and the LDEQ have issued information collection requests to Entergy facilities to help the states collect the information needed to determine the best system of emission reductions for each facility. Entergy responded to the requests and will continue to monitor litigation challenging the rule. In January 2021 the U.S. Court of Appeals for the D.C. Circuit vacated ACE. The court held that ACE relied on an incorrect interpretation of the Clean Air Act that the statute expressly forecloses emission reduction approaches, such as emissions trading and generating shifting, that cannot be applied at and to the individual source. The court remanded ACE to the EPA for further consideration and also vacated the repeal of the Clean Power Plan. The vacatur will not be effective until the court issues its mandate which is being held until after disposition of any petitions for rehearing. Entergy is currently reviewing the court’s opinion.
In 2018 the EPA proposed a revision to the new source performance standard on greenhouse gas emissions that primarily impacts new coal units and, therefore, should not impact Entergy. In January 2021 the EPA finalized a pollutant-specific contribution finding for greenhouse gas emissions from new, modified, and reconstructed electric generating units. The rule establishes a three percent threshold for determining when a pollutant significantly contributes to air pollution and reaffirms the EPA’s position that the Clean Air Act Section 111(b) requires the EPA to make pollutant-specific significant contribution findings before promulgation of a new source performance standard. The EPA did not, however, finalize the new source performance standard on greenhouse gas emissions and intends to address the 2018 proposal in a future action.
Potential Legislative, Regulatory, and Judicial Developments
In addition to the specific instances described above, there are a number of legislative and regulatory initiatives concerning air emissions, as well as other media, that are under consideration at the federal, state, and local level. Because of the nature of Entergy’s business, the imposition of any of these initiatives could affect Entergy’s operations. Entergy continues to monitor these initiatives and activities in order to analyze their potential operational and cost implications. These initiatives include:
•designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;
•introduction of bills in Congress and development of regulations by the EPA proposing further limits on NOx, SO2, mercury, and carbon dioxide and other air emissions. New legislation or regulations applicable to stationary sources could take the form of market-based cap-and-trade programs, direct requirements for the installation of air emission controls onto air emission sources, or other or combined regulatory programs;
•efforts in Congress or at the EPA to establish a federal carbon dioxide emission tax, control structure, or unit performance standards;
•revisions to the estimates of the Social Cost of Carbon and its use for regulatory impact analysis of federal laws and regulations;
•implementation of the Regional Greenhouse Gas Initiative by several states in the northeastern United States and similar actions in other regions of the United States;
•efforts on the local, state, and federal level to codify renewable portfolio standards, clean energy standards, or a similar mechanism requiring utilities to produce or purchase a certain percentage of their power from defined renewable energy sources or energy sources with lower emissions;
•efforts to develop more stringent state water quality standards, effluent limitations for Entergy’s industry sector, stormwater runoff control regulations, and cooling water intake structure requirements;
•efforts to restrict the previously-approved continued use of oil-filled equipment containing certain levels of polychlorinated biphenyls (PCBs);
•efforts by certain external groups to encourage reporting and disclosure of environmental, social, and governance risk;
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•the listing of additional species as threatened or endangered, the protection of critical habitat for these species, and developments in the legal protection of eagles and migratory birds;
•the regulation of the management, disposal, and beneficial reuse of coal combustion residuals; and
•the regulation of the management and disposal and recycling of equipment associated with renewable and clean energy sources such as used solar panels, wind turbine blades, hydrogen usage, or battery storage.
Entergy continues to support national legislation that would increase planning certainty for electric utilities while addressing carbon dioxide emissions in an economy-wide, responsible, and flexible manner. By virtue of its proportionally large investment in low-emitting generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020. In 2020, Entergy succeeded in achieving its initial climate commitment to reduce carbon dioxide cumulative emissions by 20% from 2000 levels. Total carbon dioxide emissions representing Entergy’s ownership share of power plants and controllable power purchases in the United States were approximately 39.1 million tons in 2020 and 40.7 million tons in 2019. Since its original commitment in 2001, Entergy’s cumulative emissions are approximately 7.6% below its 2020 goal.
Entergy voluntarily conducted a climate scenario analysis and published a comprehensive report in March 2019. The report follows the framework and recommendations of the Task Force on Climate-related Disclosures, describing climate-related governance, strategy, risk management, and metrics and targets. Scenario analyses resulted in Entergy developing and publishing a new goal of reducing the Utility’s emission rate by 50 percent from 2000 levels by 2030. In September 2020, Entergy committed to achieving net-zero carbon emissions by 2050, while continuing its commitment to grid reliability and affordability for customers. In December 2020, Entergy published a report regarding this long-term commitment that describes its approach and technology point-of-view. Technology research and development, innovation, and advancement are critical to Entergy’s ability to meet this climate commitment.
Entergy participates in the M.J. Bradley & Associates’ Annual Benchmarking Air Emissions Report, an annual analysis of the 100 largest U.S. electric power producers. The report is available on the M.J. Bradley website. Entergy’s annual greenhouse gas emissions inventory is also third-party verified, and that certification is made available on the American Carbon Registry website. Entergy participates annually in the Dow Jones Sustainability Index and in 2020 was listed on the North American Index. Entergy has been listed on the World or North American Index, or both, for nineteen consecutive years. Entergy also participated in the 2020 CDP and CDP Water evaluations, receiving a ‘B’ for both responses.
Clean Water Act
The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act) provide the statutory basis for the National Pollutant Discharge Elimination System permit program, section 402, and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The Clean Water Act requires virtually all discharges of pollutants to waters of the United States to be permitted. Section 316(b) of the Clean Water Act regulates cooling water intake structures, section 401 of the Clean Water Act requires a water quality certification from the state in support of certain federal actions and approvals, and section 404 regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.
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Steam Electric Effluent Guidelines
The 2015 Steam Electric Effluent Limitations Guidelines (ELG) rule required, among other things, that there be no discharge of bottom ash transport water. In October 2020 the EPA issued its final rule revision on bottom ash transport water allowing the discharge of up to 10% system volume for certain purge waters, including storm events and non-routine operations. The final rule requires compliance as soon as possible beginning October 31, 2021, but no later than December 31, 2025. Several challenges to the final rule have been filed. Additionally, the Fifth Circuit Court of Appeals previously vacated and remanded the provisions of the rule related to legacy wastewater and leachate, which the EPA plans to address in a separate rulemaking. Despite the final rule and pending challenges, Entergy is implementing projects at its White Bluff and Independence plants to convert to zero-discharge systems to comply with the ELG rule and the coal combustion residuals restrictions on impoundments. Additionally, the Nelson Unit 6 facility is implementing operational and maintenance measures to minimize the potential for discharge of bottom ash transport water from the existing bottom ash handling system at the site, and is reviewing the effectiveness of these changes for compliance with the requirements of the October 2020 final rule.
Federal Jurisdiction of Waters of the United States
In February 2019 the EPA published its proposed revised definition of Waters of the United States, which proposes to narrow the scope of Clean Water Act jurisdiction, as compared to a 2015 definition which had been stayed by several federal courts. The final rule was released in January 2020 and effective in June 2020. In October 2019 the EPA repealed the 2015 rule and re-codified the pre-existing regulations. That rule was effective late December 2019. Numerous challenges have been filed against both rules.
Groundwater at Certain Nuclear Sites
The NRC requires nuclear power plants to monitor and report regularly the presence of radioactive material in the environment. Entergy joined other nuclear utilities and the Nuclear Energy Institute in 2006 to develop a voluntary groundwater monitoring and protection program. This initiative began after detection of very low levels of radioactive material, primarily tritium, in groundwater at several plants in the United States. Tritium is a radioactive form of hydrogen that occurs naturally and is also a byproduct of nuclear plant operations. In addition to tritium, other radionuclides have been found in site groundwater at nuclear plants.
As part of the groundwater monitoring and protection program, Entergy has: (1) performed reviews of plant groundwater characteristics (hydrology) and historical records of past events on site that may have potentially impacted groundwater; (2) implemented fleet procedures on how to handle events that could impact groundwater; and (3) installed groundwater monitoring wells and began periodic sampling. The program also includes protocols for notifying local officials if contamination is found. To date, radionuclides such as tritium have been detected at Arkansas Nuclear One, Indian Point, Palisades, Grand Gulf, and River Bend. Each of these sites has installed groundwater monitoring wells and implemented a program for testing groundwater at the sites for the presence of tritium and other radionuclides. Based on current information, the concentrations and locations of radionuclides detected at these plants pose no threat to public health or safety, but each site continues to evaluate the results from its groundwater monitoring program.
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint, and several liability on responsible parties. Many states have adopted programs similar to CERCLA. Entergy subsidiaries in the Utility and Entergy Wholesale Commodities businesses have sent waste materials to various
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disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been or will be sold to decommissioning companies. In addition, environmental laws now regulate certain of Entergy’s operating procedures and maintenance practices that historically were not subject to regulation. Some disposal sites used by Entergy subsidiaries have been the subject of governmental action under CERCLA or similar state programs, resulting in site clean-up activities. Entergy subsidiaries have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs. The affected Entergy subsidiaries have established provisions for the liabilities for such environmental clean-up and restoration activities. Details of potentially material CERCLA and similar state program liabilities are discussed in the “Other Environmental Matters” section below.
Coal Combustion Residuals
In June 2010 the EPA issued a proposed rule on coal combustion residuals (CCRs) that contained two primary regulatory options: (1) regulating CCRs destined for disposal in landfills or received (including stored) in surface impoundments as so-called “special wastes” under the hazardous waste program of Resource Conservation and Recovery Act (RCRA) Subtitle C; or (2) regulating CCRs destined for disposal in landfills or surface impoundments as non-hazardous wastes under Subtitle D of RCRA. Under both options, CCRs that are beneficially reused in certain processes would remain excluded from hazardous waste regulation. In April 2015 the EPA published the final CCR rule with the material being regulated under the second scenario presented above - as non-hazardous wastes regulated under RCRA Subtitle D.
The final regulations create new compliance requirements including modified storage, new notification and reporting practices, product disposal considerations, and CCR unit closure criteria. Entergy believes that on-site disposal options will be available at its facilities, to the extent needed for CCR that cannot be transferred for beneficial reuse. As of December 31, 2020, Entergy has recorded asset retirement obligations related to CCR management of $20.1 million.
In December 2016 the Water Infrastructure Improvements for the Nation Act (WIIN Act) was signed into law, which authorizes states to regulate coal ash rather than leaving primary enforcement to citizen suit actions. States may submit to the EPA proposals for a permit program.
Pursuant to the EPA Rule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area, but has not indicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and detection monitoring will continue as the rule requires. In late-2017, Entergy determined that certain in-ground wastewater treatment system recycle ponds at its White Bluff and Independence facilities require management under the new EPA regulations. Consequently, in order to move away from using the recycle ponds, White Bluff and Independence each have installed a new permanent bottom ash handling system that does not fall under the CCR rule. As of November 2020, both sites are operating the new system and no longer are sending waste to the recycle ponds. Each site has commenced closure of one of its two recycle ponds, with the remaining pond being held in reserve during initial operation of the new bottom ash handling system. Closure of the remaining recycle pond at each site will commence as soon as possible, but no later than April 11, 2021, which is the deadline under the finalized CCR rule to commence closure of any unlined recycle ponds. Any potential requirements for corrective action or operational changes under the new CCR rule continue to be assessed. Notably, ongoing litigation has resulted in the EPA’s continuing review of the rule. Consequently, the nature and cost of additional corrective action requirements may depend, in part, on the outcome of the EPA’s review.
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Other Environmental Matters
Entergy Louisiana and Entergy Texas
Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, currently is involved in the second phase of the remedial investigation of the Lake Charles Service Center site, located in Lake Charles, Louisiana. A manufactured gas plant (MGP) is believed to have operated at this site from approximately 1916 to 1931. Coal tar, a by-product of the distillation process employed at MGPs, apparently was routed to a portion of the property for disposal. The same area also has been used as a landfill. In 1999, Entergy Gulf States, Inc. signed a second administrative consent order with the EPA to perform a removal action at the site. Removal actions addressed contaminated source material, soil, and sediment and included capping certain soil on and off-site. In 2002 approximately 7,400 tons of contaminated soil and debris were excavated and disposed of from an area within the service center. In 2003 a cap was constructed over the remedial area to prevent the migration of contamination to the surface. In August 2005 an administrative order was issued by the EPA requiring that a 10-year groundwater study be conducted at this site. The groundwater monitoring study commenced in January 2006. The EPA released the second Five Year Review in 2015. In that review, the EPA indicated that the remediation technique was insufficient and that Entergy would need to utilize other remediation technologies on the site. In July 2015, Entergy submitted a Focused Feasibility Study to the EPA outlining the potential remedies and suggesting installation of the new remedial method, a waterloo barrier. The estimated cost for this remedy is approximately $2 million, to be allocated between Entergy Louisiana and Entergy Texas. In early 2017 the EPA indicated that the waterloo barrier may not be necessary and requested revisions to the Focused Feasibility Study. The EPA released the third Five Year Review in late-2019 confirming that a new remedial method is not necessary but requiring continuation of the current groundwater monitoring. The site’s remedy includes monitored natural attenuation of groundwater, and institutional controls to restrict groundwater and land use. The EPA has determined that no additional actions are needed for the remedy to be protective over the long-term, and the remedy is protective of human health and the environment.
Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas
The Texas Commission on Environmental Quality (TCEQ) notified Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas that the TCEQ believes those entities are potentially responsible parties (PRPs) concerning contamination existing at the San Angelo Electric Service Company (SESCO) facility in San Angelo, Texas. The facility operated as a transformer repair and scrapping facility from the 1930s until 2003. Both soil and groundwater contamination existed at the site. Entergy subsidiaries sent transformers to this facility. Entergy Arkansas, Entergy Louisiana, and Entergy Texas responded to an information request from the TCEQ. Entergy Louisiana and Entergy Texas joined a group of PRPs responding to site conditions in cooperation with the State of Texas, creating cost allocation models based on review of SESCO documents and employee interviews, and investigating contribution actions against other PRPs. Entergy Louisiana and Entergy Texas have agreed to contribute to the remediation of contaminated soil and groundwater at the site in a measure proportionate to those companies’ involvement at the site. Current estimates, although variable depending on ultimate remediation design and performance, indicate that Entergy’s total share of remediation costs likely will be approximately $1.5 million to $2 million. Groundwater monitoring wells at the site were plugged and abandoned in December 2019 following receipt of a certificate of completion issued by the TCEQ. Site decommissioning activities are complete and final disposition of the property will be determined at a later time.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas
The EPA notified Entergy that the EPA believes Entergy is a PRP concerning PCB contamination at the F.J. Doyle Salvage facility in Leonard, Texas. The facility operated as a scrap salvage business during the 1970s to the 1990s. In May 2018 the EPA investigated the site surface and sub-surface soils and, in November 2018 the EPA conducted a removal action, including disposal of PCB contaminated soils. Entergy responded to the EPA’s information requests in May and July 2019. In November 2020 the EPA sent Entergy and other PRPs a demand
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letter seeking reimbursement for response costs totaling $4 million expended at the site. The demand letter is being evaluated and liability and PRP allocation of response costs are yet to be determined.
Entergy Texas
In December 2016 a transformer inside the Hartburg, Texas Substation had an internal fault resulting in a release of approximately 15,000 gallons of non-PCB mineral oil. Cleanup ensued immediately; however, rain caused much of the oil to spread across the substation yard and into a nearby wetland. The TCEQ and the National Response Center were immediately notified, and the TCEQ responded to the site approximately two hours after the cleanup was initiated. The remediation liability is estimated at $2.2 million; however, this number could fluctuate depending on the remediation extent and wetland mitigation requirements. In July 2017, Entergy entered into the Voluntary Cleanup Program with the TCEQ. In November 2017, additional soil sampling was completed in the wetland area and, in February 2018, a site summary report of findings was submitted to the TCEQ. The TCEQ responded in June 2018 and requested an ecological exclusion criteria checklist/Tier II screening-level ecological risk assessment, and additional site assessment, additional soil samples, groundwater samples, and some additional diagrams and maps. In October 2018, Entergy submitted the requested information to the TCEQ. In January 2019 the TCEQ responded with another request for information. In March 2019, Entergy submitted the requested information to the TCEQ. In August 2019 the TCEQ responded with a request for additional information including an Affected Property Assessment Report (APAR) and water well survey. The TCEQ has agreed that the necessity of the water well survey is dependent on the results of the groundwater resampling that will occur. Groundwater sampling was completed in December 2019 and results were submitted to the TCEQ for review. Based on the groundwater sampling results, the TCEQ confirmed in February 2020 that a water well survey is not necessary and requested the APAR and an Ecological Risk Assessment by August 2020. Due to COVID-19 delays, the TCEQ extended the APAR and Ecological Risk Assessment submittal dates to December 2020, which Entergy timely met.
Litigation
Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but certain states in which Entergy operates have proven to be unusually litigious environments. Judges and juries in Louisiana, Mississippi, and Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. The litigation environment in these states poses a significant business risk to Entergy.
Asbestos Litigation(Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)
See Note 8 to the financial statements for a discussion of this litigation.
Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
See Note 8 to the financial statements for a discussion of these proceedings.
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Human Capital
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2020, Entergy subsidiaries employed 13,400 people.
| | | | | |
Utility: | |
Entergy Arkansas | 1,244 | |
Entergy Louisiana | 1,654 | |
Entergy Mississippi | 750 | |
Entergy New Orleans | 303 | |
Entergy Texas | 658 | |
System Energy | — | |
Entergy Operations | 3,529 | |
Entergy Services | 3,859 | |
Entergy Nuclear Operations | 1,356 | |
Other subsidiaries | 47 | |
Total Entergy | 13,400 | |
Approximately 3,900 employees are represented by the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the International Brotherhood of Teamsters, the United Government Security Officers of America, and the International Union, Security, Police, and Fire Professionals of America.
Below is the breakdown of Entergy’s employees by gender and race/ethnicity:
| | | | | | | | | | | |
Gender (%) | 2020 | | 2019 |
Female | 21 | | 20 |
Male | 79 | | 80 |
| 100 | | 100 |
| | | | | | | | | | | |
Race/Ethnicity (%) | 2020 | | 2019 |
White | 78 | | 79 |
Black/African American | 15 | | 15 |
Hispanic/Latino | 3 | | 2 |
Asian | 2 | | 2 |
Other | 2 | | 2 |
| 100 | | 100 |
Entergy’s Approach to Human Resources
Entergy’s people and culture enable its success; that is why acquiring, retaining, and developing talent are important components of Entergy’s human resources strategy. Entergy focuses on an approach that includes, among other things, governance and oversight; safety; organizational health, including diversity, inclusion and belonging; and talent management.
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Governance and Oversight
Ensuring that workplace processes support the desired culture and strategy begins with the Board of Directors and the Office of the Chief Executive. The Personnel Committee establishes priorities and reviews performance on a range of topics. It oversees Entergy’s incentive plan design and administers its executive compensation plans to incentivize the behaviors and outcomes that support achievement of Entergy’s corporate objectives. Annually, it reviews executive performance, development and succession plans to align a high performing executive team with Entergy’s priorities. The Personnel Committee also oversees Entergy’s performance through regular briefings on a wide variety of human resources topics including Entergy’s safety culture and performance; organizational health; and diversity, inclusion, and belonging initiatives and performance.
Other committees of the Board oversee other key aspects of Entergy’s culture. For example, the Audit Committee reviews reports on ethics and compliance training and performance, as well as regular reports on calls made to Entergy’s ethics line and related investigations. To maximize the sharing of information and facilitate the participation of all Board members in these discussions, the Board schedules its regular committee meetings in a manner such that all directors can attend.
The Office of the Chief Executive, which includes the Senior Vice President and Chief Human Resources Officer, ensures annual business plans are designed to support Entergy’s talent objectives, reviews workforce-related metrics, and regularly discusses the development, succession planning, and performance of their direct reports and other company officers.
Safety
Entergy’s safety objective is: Everyone Safe. All Day. Every Day. While the COVID-19 pandemic and historical hurricane season presented significant challenges, Entergy’s safety strategy and commitment to excellence showed results in 2020. Entergy employees achieved a total recordable incident rate of 0.40 in 2020 compared to 0.56 in 2019 and 0.48 in 2018. The recordable incident rate equals the number of recordable incidents per 100 full-time equivalents. Recordable incidents include fatalities, lost-time accidents, restricted-duty accidents, and medical attentions and is not inclusive of potential work-related COVID-19 cases. This marked improvement in total recordable incident rate placed Entergy in top-decile in safety performance when benchmarked amongst peers within the Edison Electric Institute.
Organizational Health, including Diversity, Inclusion and Belonging
Entergy believes that organizational health fosters an engaged and productive culture that positions Entergy to deliver sustainable value to its stakeholders. Entergy measures its progress through an organizational health survey coordinated by an external third party. Since initially administering the survey in 2014, Entergy improved from an initial score of 49 (fourth quartile) to a score in 2020 of 72 (near top quartile). In addition to significantly improved scores, initial employee participation of 66 percent in 2014 rose to and remains at 90 percent in 2018-2020.
Entergy believes that a culture focused on diversity, inclusion, and belonging drives foundational engagement. Entergy is committed to developing and retaining a workforce that reflects the rich diversity of the communities it serves. In 2019, Entergy embarked on a three-year phased approach to enhance inclusion for individuals and teams. Among other actions, the primary focus of its 2020 actions was taking a stand against social injustice, reinforcing expectations, training and leading by example, starting at the top of the organization and cascading through management ranks.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Talent Management
Entergy’s focus on talent management is organized in three areas: developing and attracting a diverse pool of talent, equipping its leaders to develop the organization, and building premier utility capability through employee performance management and succession programs. Entergy believes that developing a diverse pool of local talent equipped with the skills needed, today and in the future, and reflecting the communities Entergy serves will give it a long-term competitive advantage. The focus of Entergy’s leadership development programs is to equip managers with the skills needed to effectively develop their teams and improve the leader-employee relationship. Entergy’s talent development infrastructure, which includes a combination of business function-specific and enterprise-wide learning and development programs, is designed to ensure Entergy has qualified staff with the skills, experiences, and behaviors needed to perform today and prepare for the future. Entergy strives to achieve its strategic priorities by aligning and enhancing team and individual performance with business objectives, effectively deploying talent through succession planning, and managing workforce transitions.
Availability of SEC filings and other information on Entergy’s website
Entergy electronically files reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies, and amendments to such reports. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. Copies of the reports that Entergy files with the SEC can be obtained at the SEC’s website.
Entergy uses its website, http://www.entergy.com, as a routine channel for distribution of important information, including news releases, analyst presentations and financial information. Filings made with the SEC are posted and available without charge on Entergy’s website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These filings include annual and quarterly reports on Forms 10-K and 10-Q (including related filings in Inline XBRL format) and current reports on Form 8-K; proxy statements; and any amendments to those reports or statements. All such postings and filings are available on Entergy’s Investor Relations website free of charge. Entergy is providing the address to its internet site solely for the information of investors and does not intend the address to be an active link. The contents of the website are not incorporated into this report.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
RISK FACTORS
See “RISK FACTOR SUMMARY” in Part I Item 1 for a summary of Entergy’s and the Registrant Subsidiaries’ risk factors.
Investors should review carefully the following risk factors and the other information in this Form 10-K. The risks that Entergy faces are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect Entergy’s financial condition, results of operations, and liquidity. See “FORWARD-LOOKING INFORMATION.”
Utility Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The impacts of the COVID-19 pandemic and responsive measures taken on Entergy’s and its Utility operating companies’ business, results of operations, and financial condition are highly uncertain and cannot be predicted.
In December 2019 a novel strain of coronavirus was reported to have surfaced in Wuhan, China. Since then, COVID-19 has spread throughout most countries in the world, including the United States. Public health officials in the United States have both recommended and mandated wearing of masks, precautions to mitigate the spread of COVID-19, including prohibitions on congregating in heavily-populated areas, mandated closure or limitations on the functions of non-essential business, and shelter-in-place orders or similar measures, including throughout Entergy’s service areas. While some of these mitigation measures have been lifted, it is unclear how long certain forms of mitigation measures will remain in place, whether they will be reinstated in the future, and how they will ultimately impact the general economy, Entergy’s customers, and its operations.
Entergy and its Utility operating companies have experienced a decline in commercial and industrial sales and an increase in arrearages and bad debt expense due to non-payment by customers, and expect such reduced levels of sales and increased arrearages and bad debt expense to continue, the extent and duration of which management cannot predict. The Utility operating companies temporarily suspended disconnecting customers for non-payment of bills, and the suspension remains in place at Entergy Arkansas, has been re-instituted at Entergy New Orleans, and could be re-instituted at the other Utility operating companies should their regulators mandate. While they are working with regulators to ensure ultimate recovery for those and other COVID-19 related costs, the amount, method, and timing of such recovery is unknown. Entergy and its Registrant Subsidiaries also could experience, and in some cases have experienced, among other challenges, supply chain, vendor, and contractor disruptions; delays in completion of capital or other construction projects, maintenance, and other operations activities, including prolonged or delayed outages; delays in regulatory proceedings; workforce availability, health or safety issues; increased storm recovery costs; increased cybersecurity risks as a result of many employees telecommuting; increased late or uncollectible customer payments; volatility in the credit or capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available credit facilities); or other adverse impacts on their ability to execute on business strategies and initiatives.
A sustained or further economic decline could adversely impact Entergy’s and the Utility operating companies’ liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, or increased bad debt expense. The Utility operating companies also may experience regulatory outcomes that require them to postpone planned investment and otherwise reduce costs due to the impact of the COVID-19 pandemic on their customers. In addition, if the COVID-19 pandemic continues to create disruptions or turmoil in the credit or financial markets, or adversely impacts Entergy’s credit metrics or ratings, such developments could adversely affect its ability to access capital on favorable terms and continue to meet its
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liquidity needs, or cause a decrease in the value of its defined benefit pension trust funds, as well as its nuclear decommissioning trust funds, all of which are highly uncertain and cannot be predicted.
Entergy cannot predict the extent or duration of the outbreak, the impact of new variants of COVID-19, the timing, availability, distribution or effectiveness of a vaccine, anti-viral or other treatments for COVID-19, governmental responsive measures, or the extent of the effects or ultimate impacts on the global, national or local economy, the capital markets, or its customers, suppliers, operations, financial condition, results of operations, or cash flows.
The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that can be lengthy and subject to appeal, potentially resulting in delays in effecting rate changes, lengthy litigation and uncertainty as to ultimate results.
The Utility operating companies are regulated on a cost-of-service and rate of return basis and are subject to statutes and regulatory commission rules and procedures. The rates that the Utility operating companies and System Energy charge reflect their capital expenditures, operations and maintenance costs, allowed rates of return, financing costs, and related costs of service. These rates significantly influence the financial condition, results of operations, and liquidity of Entergy and each of the Utility operating companies and System Energy. These rates are determined in regulatory proceedings and are subject to periodic regulatory review and adjustment, including adjustment upon the initiative of a regulator or affected stakeholders.
In addition, regulators may initiate proceedings to investigate the prudence of costs in the Utility operating companies’ and System Energy’s base rates and examine, among other things, the reasonableness or prudence of the companies’ operation and maintenance practices, level of expenditures (including storm costs and costs associated with capital projects), allowed rates of return and rate base, proposed resource acquisitions, and previously incurred capital expenditures that the operating companies seek to place in rates. The regulators may disallow costs subject to their jurisdiction found not to have been prudently incurred or found not to have been incurred in compliance with applicable tariffs, creating some risk to the ultimate recovery of those costs. Regulatory proceedings relating to rates and other matters typically involve multiple parties seeking to limit or reduce rates. Traditional base rate proceedings, as opposed to formula rate plans, generally have long timelines, are primarily based on historical costs, and may or may not be limited in scope or duration by statute. The length of these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates, such that the Utility operating companies may not fully recover all costs during the rate effective period and the Utility operating companies may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings.
The Utility operating companies have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including the operation of their assets and infrastructure or the quality of their service. Criticism or adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view the applicable operating company in a favorable light and could potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements.
The base rates of Entergy Texas are established largely in traditional base rate case proceedings.Between base rate proceedings, Entergy Texas has available rate riders to recover the revenue requirements associated with certain incremental costs.These riders include a distribution cost recovery factor rider mechanism for the recovery of distribution-related capital investment and certain non-fuel MISO charges, a transmission cost recovery factor rider mechanism for the recovery of transmission-related capital investments, a generation cost recovery rider mechanism for the recovery of generation-related capital investments, and a fixed fuel factor mechanism for the recovery of MISO fuel and energy-related costs.Entergy Texas also is required to make a filing every three years,
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at a minimum, reconciling its fuel and purchased power costs and fuel factor revenues.In the course of this reconciliation, the PUCT determines whether eligible fuel and fuel-related expenses and revenues are necessary and reasonable, and makes a prudence finding for each of the fuel-related contracts for the reconciliation period.Entergy Texas also is required to file full base rate case proceedings every four years and within eighteen months of utilizing its generation cost recovery rider for investments above $200 million.
Between base rate cases, Entergy Arkansas and Entergy Mississippi are able to adjust base rates annually through formula rate plans that utilize a forward test year (Entergy Arkansas) or forward-looking features (Entergy Mississippi).In response to Entergy Arkansas’s application for a general change in rates in 2015, the APSC approved the formula rate plan tariff proposed by Entergy Arkansas including its use of a projected year test period and an initial five-year term.The initial five-year term expires in 2021. Entergy Arkansas has requested APSC approval of the extension of the formula rate plan tariff for an additional five years through 2026.If Entergy Arkansas’s formula rate plan were terminated or not extended beyond the initial term, Entergy Arkansas could file an application for a general change in rates that may include a request for continued regulation under a formula rate review mechanism.If Entergy Mississippi’s formula rate plan is terminated, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan.Entergy Arkansas and Entergy Mississippi recover fuel and purchased energy and certain non-fuel costs through other APSC-approved and MPSC-approved tariffs, respectively.
Entergy Louisiana historically sets electric base rates annually through a formula rate plan using an historic test year.The form of the formula rate plan, on a combined basis, was approved in connection with the business combination of Entergy Louisiana and Entergy Gulf States Louisiana and largely followed the formula rate plans that were approved by the LPSC in connection with the full electric base rate cases filed by those companies in February 2013.The formula rate plan was most recently extended through the test year 2019; certain modifications were made in that extension, including a decrease to the allowed return on equity and the addition of a transmission cost recovery mechanism.The formula rate plan continues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities and purchase power agreements approved by the LPSC and as noted, for certain transmission investment, among other items.MISO fuel and energy-related costs are recoverable in Entergy Louisiana’s fuel adjustment clause.Entergy Louisiana has a pending request to extend its formula rate plan 2016with certain modifications, including implementation of a distribution investment recovery mechanism and use of end of period rate base.In the event that the electric formula rate plan is not renewed or extended, Entergy Louisiana would revert to the more traditional rate case environment.
Entergy New Orleans previously operated under a formula rate plan that ended with the 2011 test year.Based on a settlement agreement approved by the City Council, with limited exceptions, the base rates of Entergy New Orleans were frozen until rates were implemented in connection with the base rate case filed by Entergy New Orleans in 2018.In November 2019 the City Council issued a resolution resolving the rate case, with rates to become effective retroactive to August 2019.The resolution allows Entergy New Orleans to implement a three-year formula rate plan, beginning with the 2019 test year as adjusted for forward-looking known and measurable changes.In November 2020 the City Council issued a resolution approving a settlement of the 2018 rate case.As part of this settlement, Entergy New Orleans agreed to postpone the filing showing of its first test year formula rate plan to 2021 and, in return, to be provided an additional test year for the three-year cycle.See Note 2 to the financial statements for further discussion.
The rates of System Energy are established by the FERC, and the costs allowed to be charged pursuant to these rates are, in turn, passed through to the participating Utility operating companies through the Unit Power Sales Agreement, which has monthly billings that reflect the current operating costs of, and investment in, Grand Gulf. Retail regulators and other parties may seek to initiate proceedings at FERC to investigate the prudence of costs included in the rates charged under the Unit Power Sales Agreement and examine, among other things, the
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Entergy Mississippi’sCorporation, Utility operating companies, and System Energy
reasonableness or prudence of the operation and maintenance practices, level of expenditures, allowed rates of return and rate base, and previously incurred capital expenditures. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a separate request for FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings nor can it predict whether any outcome could have a material effect on Entergy’s or System Energy’s results of operations, financial condition or liquidity. See Note 2 to the financial statements for further discussion of the proceedings. System Energy has received FERC acceptance for billing protocols to provide retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
The Utility operating companies and System Energy, and the energy industry as a whole, have experienced a period of rising costs and investments, and an upward trend in spending, especially with respect to infrastructure investments, which is likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms. For information regarding rate case proceedings and formula rate plans applicable to the Utility operating companies, see Note 2 to the financial statements.
Changes to state or federal legislation or regulation affecting electric generation, electric and natural gas transmission, distribution, and related activities could adversely affect Entergy and the Utility operating companies’ financial position, results of operations, or cash flows and their utility businesses.
If legislative and regulatory structures evolve in a manner that erodes the Utility operating companies’ exclusive rights to serve their regulated customers, they could lose customers and sales and their results of operations, financial position, or cash flows could be materially affected. Additionally, technological advances in energy efficiency and distributed energy resources are reducing the costs of these technologies and together with ongoing state and federal subsidies, the increasing penetration of these technologies could result in reduced sales by the Utility operating companies. Such loss of sales could put upward pressure on rates, resulting in adverse regulatory actions to mitigate such effects on rates. Entergy and the Utility operating companies cannot predict if or when they may be subject to changes in legislation or regulation, or the extent and timing of reductions of the cost of distributed energy resources, nor can they predict the impact of these changes on their results of operations, financial position, or cash flows.
The Utility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings.
The Utility operating companies recover their fuel, purchased power, and associated costs from their customers through rate mechanisms subject to periodic regulatory review and adjustment. Because regulatory review can result in the disallowance of incurred costs found not to have been prudently incurred, including the cost of replacement power purchased when generators experience outages or when planned outages are extended, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs, particularly when there are substantial or sudden increases in such costs. Regulators also may initiate proceedings to investigate the continued usage or the adequacy and operation of the fuel and purchased power recovery clauses of the Utility operating companies and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.
The Utility operating companies’ cash flows can be negatively affected by the time delays between when gas, power, or other commodities are purchased and the ultimate recovery from customers of the costs in rates. On occasion, when the level of incurred costs for fuel and purchased power rises very dramatically, some of the Utility operating companies may agree to defer recovery of a portion of that period’s fuel and purchased power costs for recovery at a later date, which could increase the near-term working capital and borrowing requirements of those companies. For a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power costs recovery, see Note 2 to the financial statements.
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Entergy Corporation, Utility operating companies, and System Energy
There remains uncertainty regarding the effect of the termination of the System Agreement on the Utility operating companies.
The Utility operating companies historically engaged in the coordinated planning, construction, and operation of generating resources and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that had been approved by the FERC. The System Agreement terminated in its entirety on August 31, 2016.
There remains uncertainty regarding the long-term effect of the termination of the System Agreement on the Utility operating companies because of the significant effect of the agreement on the generation and transmission functions of the Utility operating companies and the significant period of time (over 30 years) that it had been in existence. In the absence of the System Agreement, there remains uncertainty around the effectiveness of governance processes and the potential absence of federal authority to resolve certain issues among the Utility operating companies and their retail regulators.
In addition, although the System Agreement terminated in its entirety in August 2016, there are a few outstanding System Agreement proceedings at the FERC and at the D.C. Circuit that may require future adjustments, including challenges to the level and timing of payments made by Entergy Arkansas under the System Agreement. The outcome and timing of these FERC proceedings and resulting recovery and impact on rates cannot be predicted at this time.
For further information regarding the regulatory proceedings relating to the System Agreement, see Note 2 to the financial statements.
The Utility operating companies are subject to economic risks associated with participation in the MISO markets and the allocation of transmission upgrade costs. The operation of the Utility operating companies’ transmission system pursuant to the MISO RTO tariff and their participation in the MISO RTO’s wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
On December 19, 2013, the Utility operating companies integrated into the MISO RTO. MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. The Utility operating companies are subject to economic risks associated with participation in the MISO markets. MISO tariff rules and system conditions, including transmission congestion, could affect the Utility operating companies’ ability to sell capacity, energy, and/or ancillary services in certain regions and/or the economic value of such sales, or the cost of serving the Utility operating companies’ respective loads, and MISO market rules may change in ways that cause additional risk.
The Utility operating companies participate in the MISO regional transmission planning process and are subject to risks associated with planning decisions that MISO makes in the exercise of control over the planning of the Utility operating companies’ transmission assets that are under MISO’s functional control. The Utility operating companies pay transmission rates that reflect the cost of transmission projects that the Utility operating companies do not own, which could increase cash or financing needs. In addition to the cash and financing-related risks arising from the potential additional cost allocation to the Utility operating companies from transmission projects of others, there is a risk that the Utility operating companies’ business and financial position could be harmed as a result of lost investment opportunities and other effects that flow from an increased number of competitive projects being approved and constructed that are interconnected with their transmission systems. Further, the terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets, the
Part I Item 1A & 1B
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allocation of transmission upgrade costs, the MISO-wide allowed base rate of return on equity, and any required MISO-related charges and credits are subject to regulation by the FERC. The operation of the Utility operating companies’ transmission system pursuant to the MISO tariff and their participation in the MISO wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements. In addition, orders from each of the Utility operating companies’ respective retail regulators generally require that the Utility operating companies make periodic filings, or generally allow the retail regulator to direct the making of such filings, setting forth the results of analysis of the costs and benefits realized from MISO membership as well as the projected costs and benefits of continued membership in MISO and/or requesting approval of their continued membership in MISO. These filings have been submitted periodically by each of the Utility operating companies as required by their respective retail regulators, and the outcome of the resulting proceedings may affect the Utility operating companies’ continued membership in MISO.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather (including from Hurricane Laura, Hurricane Delta, and Hurricane Zeta), or the impact on customer bills of permitted storm cost recovery, could have material effects on Entergy and its Utility operating companies.
Entergy’s and its Utility operating companies’ results of operations, liquidity, and financial condition can be materially affected by the destructive effects of severe weather. Severe weather can also result in significant outages for the customers of the Utility operating companies and, therefore, reduced revenues for the Utility operating companies during the period of the outages. A delay or failure in recovering amounts for storm restoration costs incurred or revenues lost as a result of severe weather could have a material effect on Entergy and those Utility operating companies affected by severe weather. In addition, the recovery of major storm restoration costs from customers could effectively limit our ability to make planned capital or other investments due to the impact of such storm cost recovery on customer bills.
In August and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of the Utility’s service territories in Louisiana, including New Orleans, Texas, and to a lesser extent, in Arkansas and Mississippi. The storms resulted in widespread power outages, significant damage to distribution and transmission infrastructure, and the loss of sales during the outages. Additionally, as a result of Hurricane Laura’s extensive damage to the grid infrastructure serving the impacted area, large portions of the underlying transmission system required nearly a complete rebuild. Total restoration costs for the repair and/or replacement of the electrical system damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta are currently estimated to be approximately $2.4 billion. Because Entergy has not gone through the regulatory process regarding these storm costs, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Nuclear Operating, Shutdown, and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)
Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities must consistently operate their nuclear power plants at high capacity factors in order to be successful, and lower capacity factors could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Nuclear capacity factors significantly affect the results of operations of certain Utility operating companies, System Energy, and Entergy Wholesale Commodities. Nuclear plant operations involve substantial fixed operating
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costs. Consequently, to be successful, a plant owner must consistently operate its nuclear power plants at high capacity factors, consistent with safety requirements. For the Utility operating companies that own nuclear plants, lower capacity factors can increase production costs by requiring the affected companies to generate additional energy, sometimes at higher costs, from their owned or contractually controlled facilities or purchase additional energy in the spot or forward markets in order to satisfy their supply needs. For the Entergy Wholesale Commodities nuclear plants, lower capacity factors directly affect revenues and cash flow from operations. Entergy Wholesale Commodities’ forward sales are comprised of various hedge products, many of which have some degree of operational-contingent price risk. Certain unit-contingent contracts guarantee specified minimum capacity factors. In the event plants with these contracts were operating below the guaranteed capacity factors, Entergy would be subject to price risk for the undelivered power. Further, Entergy Wholesale Commodities’ nuclear forward sales contracts can also be on a firm LD basis, which subjects Entergy to increasing price risk as capacity factors decrease. Many of these firm hedge products have damages risk.
Certain of the Utility operating companies and System Energy periodically shut down their nuclear power plants to replenish fuel. Plant maintenance and upgrades are often scheduled during such refueling outages. If refueling outages last longer than anticipated or if unplanned outages arise, Entergy’s and their results of operations, financial condition, and liquidity could be materially affected.
Outages at nuclear power plants to replenish fuel require the plant to be “turned off.” Refueling outages generally are planned to occur once every 18 to 24 months. Plant maintenance and upgrades are often scheduled during such planned outages, which typically extends the planned outage duration. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease, and maintenance costs may increase.
Certain of the Utility operating companies and System Energy face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication). These risks could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Based upon currently planned fuel cycles, Entergy’s nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable prices through 2020 and beyond. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. While there are a number of possible alternate suppliers that may be accessed to mitigate any supplier performance failure, the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S. Market prices for nuclear fuel have been extremely volatile from time to time in the past and may be subject to increased volatility due to the imposition of tariffs, domestic purchase requirements or limitations on importation of uranium or uranium products from foreign countries, or shifting trade arrangements between countries. Although Entergy’s nuclear fuel contract portfolio provides a degree of hedging against market risks for several years, costs for nuclear fuel in the future cannot be predicted with certainty due to normal inherent market uncertainties, and price changes could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance and reliability of conversion, enrichment, and fabrication services providers. These service providers are fewer in number than uranium suppliers. For conversion and enrichment services, Entergy diversifies its supply by supplier and country and may take special measures to ensure a reliable supply of enriched uranium for fabrication into nuclear fuel. For fabrication services, each plant is dependent upon the performance of the fabricator of that plant’s nuclear fuel; therefore, Entergy relies upon additional monitoring, inspection, and oversight of the fabrication process to assure reliability and quality of its nuclear fuel. Certain of the suppliers and service providers are located in or dependent upon countries, such as Russia, in which international sanctions or tariffs could further restrict the ability of such
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suppliers to continue to supply fuel or provide such services at acceptable prices or at all. The inability of such suppliers or service providers to perform such obligations could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business face the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants, which could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Under the Atomic Energy Act and Energy Reorganization Act, the NRC regulates the operation of nuclear power plants. The NRC may modify, suspend, or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations, or the terms of the licenses for nuclear facilities. Interested parties may also intervene which could result in prolonged proceedings. A change in the Atomic Energy Act, other applicable statutes, or the applicable regulations or licenses, or the NRC’s interpretation thereof, may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially affect the results of operations, liquidity, or financial condition of Entergy (through Entergy Wholesale Commodities), its Utility operating companies, or System Energy. A change in the classification of a plant owned by one of these companies under the NRC’s Reactor Oversight Process, which is the NRC’s program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response, also could cause the owner of the plant to incur material additional costs as a result of the increased oversight activity and potential response costs associated with the change in classification.For additional information concerning the current classification of the plants owned by Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business, see “Regulation of Entergy’s Business- Regulation of the Nuclear Power Industry - NRC Reactor Oversight Process” in Part I, Item 1.
Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate actions to modify, suspend, or revoke licenses, shut down a nuclear facility, or impose civil penalties. As a result, if an incident were to occur at any nuclear generating unit, whether an Entergy nuclear generating unit or not, it could materially affect the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, System Energy, or Entergy Wholesale Commodities.
Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities are exposed to risks and costs related to operating and maintaining their nuclear power plants, and their failure to maintain operational efficiency at their nuclear power plants could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
The nuclear generating units owned by certain of the Utility operating companies, System Energy,and the Entergy Wholesale Commodities business began commercial operations in the 1970s-1980s. Older equipment may require more capital expenditures to keep each of these nuclear power plants operating safely and efficiently. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages, or any unanticipated capital expenditures, could result in increased costs, some of which costs may not be fully recoverable by the Utility operating companies and System Energy in regulatory proceedings should there be a determination of imprudence. Operations at any of the nuclear generating units owned and operated by Entergy’s subsidiaries could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. A decision may be made to close a unit rather than incur the expense of restarting it or returning the unit to full capacity. For the Utility operating companies and System Energy, this could result in certain costs being stranded and potentially not fully recoverable in regulatory proceedings. For Entergy Wholesale Commodities, this could result in lost revenue and increased fuel and purchased power expense to meet
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supply commitments and penalties for failure to perform under their contracts with customers. In addition, the operation and maintenance of Entergy’s nuclear facilities require the commitment of substantial human resources that can result in increased costs.
The nuclear industry continues to address susceptibility to the effects of stress corrosion cracking and other corrosion mechanisms on certain materials within plant systems. The issue is applicable at all nuclear units to varying degrees and is managed in accordance with industry standard practices and guidelines that include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.
Moreover, Entergy is becoming more dependent on fewer suppliers for key parts of Entergy’s nuclear power plants that may need to be replaced or refurbished, and in some cases, parts are no longer available and have to be reverse-engineered for replacement. In addition, certain major parts have long lead-times to manufacture if an unplanned replacement is needed. This dependence on a reduced number of suppliers and long lead-times on certain major parts for unplanned replacements could result in delays in obtaining qualified replacement parts and, therefore, greater expense for Entergy.
The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities nuclear power plants, as well as the costs of and their ability to fully decommission their nuclear power plants, could be significantly affected by the timing of the opening of a spent nuclear fuel disposal facility, as well as interim storage and transportation requirements.
Certain of the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities nuclear plants incur costs for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the disposal of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, or any interim storage facility, and the timing of such facility opening, will significantly affect the costs associated with on-site storage of spent nuclear fuel. For example, while the DOE is required by law to proceed with the licensing of Yucca Mountain and, after the license is granted by the NRC, to construct the repository and commence the receipt of spent fuel, the NRC licensing of the Yucca Mountain repository is effectively at a standstill. These actions are prolonging the time before spent fuel is removed from Entergy’s plant sites. Because the DOE has not accomplished its objectives, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts, and Entergy has sued the DOE for such breach. Furthermore, Entergy is uncertain as to when the DOE will commence acceptance of spent fuel from its facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at the companies’ nuclear sites and maintenance costs on existing storage facilities, including aging management of fuel storage casks, may increase. The costs of on-site storage are also affected by regulatory requirements for such storage. In addition, the availability of a repository or other off-site storage facility for spent nuclear fuel may affect the ability to fully decommission the nuclear units and the costs relating to decommissioning. For further information regarding spent fuel storage, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs – Spent Fuel Disposal” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 8 to the financial statements.
Certain of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities nuclear plant owners may be required to pay substantial retrospective premiums imposed under the Price-Anderson Act in the event of a nuclear incident, and losses not covered by insurance could have a material effect on Entergy’s and their results of operations, financial condition, or liquidity.
Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere. The Price-Anderson Act limits each reactor owner’s public liability (off-site) for a single nuclear incident to the payment of retrospective premiums into a secondary insurance pool, which is referred to as Secondary Financial Protection, up to approximately $137.6 million per reactor. With 97 reactors currently
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
participating, this translates to a total public liability cap of approximately $14 billion per incident. The limit is subject to change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As required by the Price-Anderson Act, the Utility operating companies, System Energy, and Entergy Wholesale Commodities carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers, which is $450 million for each operating site. Claims for any nuclear incident exceeding that amount are covered under Secondary Financial Protection. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the primary insurance coverage, each owner of a nuclear plant reactor, including Entergy’s Utility operating companies, System Energy, and the Entergy Wholesale Commodities plant owners, regardless of fault or proximity to the incident, will be required to pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary insurance level, up to a maximum of approximately $137.6 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.101 billion). The retrospective premium payment is currently limited to approximately $21 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $137.6 million cap.
NEIL is a utility industry mutual insurance company, owned by its members, including the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities plants. All member plants could be subject to an annual assessment (retrospective premium of up to 10 times current annual premium for all policies) should the NEIL surplus (reserve) be significantly depleted due toinsured losses. As of December 31, 2020, the maximum annual assessment amounts total $104 million for the Utility plants. Retrospective premium insurance available through NEIL’s reinsurance treaty can cover the potential assessments and the Entergy Wholesale Commodities plants currently maintain the retrospective premium insurance to cover those potential assessments.
As an owner of nuclear power plants, Entergy participates in industry self-insurance programs and could be liable to fund claims should a plant owned by a different company experience a major event. Any resulting liability from a nuclear accident may exceed the applicable primary insurance coverage and require contribution of additional funds through the industry-wide program that could significantly affect the results of operations, financial condition, or liquidity of Entergy, certain of the Utility operating companies, System Energy, or the Entergy Wholesale Commodities subsidiaries.
The decommissioning trust fund assets for the nuclear power plants owned by the Utility operating companies, System Energy, and the Entergy Wholesale Commodities nuclear plant owners may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts, if one or more of Entergy’s nuclear power plants is retired earlier than the anticipated shutdown date, if the plants cost more to decommission than estimated, or if current regulatory requirements change, which then could require significant additional funding.
Owners of nuclear generating plants have an obligation to decommission those plants. Certain of the Utility operating companies, System Energy, and owners of the Entergy Wholesale Commodities nuclear power plants maintain decommissioning trust funds for this purpose. Certain of the Utility operating companies collect funds from their customers, which are deposited into the trusts covering the units operated for or on behalf of those companies. Those rate collections, as adjusted from time to time by rate regulators, are generally based upon operating license lives and trust fund balances as well as estimated trust fund earnings and decommissioning costs. Assets in these trust funds are subject to market fluctuations, will yield uncertain returns that may fall below projected return rates, and may result in losses resulting from the recognition of impairments of the value of certain securities held in these trust funds.
Under NRC regulations, nuclear plant owners are permitted to project the NRC-required decommissioning amount, based on an NRC formula or a site-specific estimate, and the amount that will be available in each nuclear power plant’s decommissioning trusts combined with any other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used. If the projected amount of each individual plant’s decommissioning trusts exceeds the NRC-required decommissioning amount, then its NRC license termination decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs required to decommission these nuclear power plants, or funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources or commitments would be required. Furthermore, depending upon the level of funding available in the trust funds, the NRC may not permit the trust funds to be used to pay for related costs such as the management of spent nuclear fuel that are not included in the NRC’s formula. The NRC may also require a plan for the provision of separate funding for spent fuel management costs. In addition to NRC requirements, there are other decommissioning-related obligations for certain of the Entergy Wholesale Commodities nuclear power plants, which management believes it will be able to satisfy.
Further, federal or state regulatory changes, including mandated increases in decommissioning funding or changes in the methods or standards for decommissioning operations, may also increase the funding requirements of, or accelerate the timing for funding of, the obligations related to the decommissioning of the Utility operating companies, System Energy, or Entergy Wholesale Commodities nuclear power plants or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. Such changes also could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. As a result, under any of these circumstances, Entergy’s results of operations, liquidity, and financial condition could be materially affected.
An early plant shutdown (either generally or relative to current expectations), poor investment results, or higher than anticipated decommissioning costs (including as a result of changing regulatory requirements) could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that the Utility operating companies, System Energy, or the Entergy Wholesale Commodities nuclear plant owners may be required to provide significant additional funds or credit support to satisfy regulatory requirements for decommissioning, which, with respect to the Utility operating companies, may not be recoverable from customers in a timely fashion or at all.
For further information regarding nuclear decommissioning costs, management’s decision to exit the merchant power business, the impairment charges that resulted from such decision, and the planned sales of Palisades and Indian Point Energy Center (which, in each case, will include the transfer of the associated decommissioning trusts), see the “Critical Accounting Estimates- Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy, the “Entergy Wholesale Commodities Exit from the Merchant Power Business” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries, and Notes 9 and 14 to the financial statements.
New or existing safety concerns regarding operating nuclear power plants and nuclear fuel could lead to restrictions upon the operation and decommissioning of Entergy’s nuclear power plants.
New and existing concerns are being expressed in public forums about the safety of nuclear generating units and nuclear fuel. These concerns have led to, and may continue to lead to, various proposals to Federal regulators and governing bodies in some localities where Entergy’s subsidiaries own nuclear generating units for legislative and regulatory changes that might lead to the shutdown of nuclear units, additional requirements or restrictions related to spent nuclear fuel on-site storage and eventual disposal, or other adverse effects on owning, operating, and decommissioning nuclear generating units. Entergy vigorously responds to these concerns and proposals. If any of the existing proposals, or any proposals that may arise in the future with respect to legislative and regulatory changes, become effective, they could have a material effect on Entergy’s results of operations and financial condition.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
(Entergy Corporation)
Entergy Wholesale Commodities nuclear power plants are exposed to price risk.
Entergy and its subsidiaries do not have a regulator-authorized rate of return on their capital investments in non-utility businesses. As a result, the sale of capacity and energy from the Entergy Wholesale Commodities nuclear power plants, unless otherwise contracted, is subject to the fluctuation of market power prices. In order to reduce future price risk to desired levels, Entergy Wholesale Commodities utilizes contracts that are unit-contingent and Firm LD and various products such as forward sales, options, and collars. As of December 31, 2020, Entergy Wholesale Commodities’ nuclear power generation plants had sold forward 98% in 2021 and 99% in 2022 of its generation portfolio’s planned energy output, reflecting the planned shutdown and sale of the remaining Entergy Wholesale Commodities nuclear power plants by mid-2022.
Market conditions such as product cost, market liquidity, and other portfolio considerations influence the product and contractual mix. The obligations under unit-contingent agreements depend on a generating asset that is operating; if the generation asset is not operating, the seller generally is not liable for damages. For some unit-contingent obligations, however, there is also a guarantee of availability that provides for the payment to the power purchaser of contract damages, if incurred, in the event the unit owner fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. Firm LD sales transactions may be exposed to substantial operational price risk, a portion of which may be capped through the use of risk management products, to the extent that the plants do not run as expected and market prices exceed contract prices.
Market prices may fluctuate substantially, sometimes over relatively short periods of time, and at other times experience sustained increases or decreases. Demand for electricity and its fuel stock can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply, prices might be depressed. Also, from time to time there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, credit requirements, bidding rules, and other mechanisms to address volatility and other issues in these markets.
The effects of sustained low natural gas prices and power market structure challenges have resulted in lower market prices for electricity in the power regions where the Entergy Wholesale Commodities nuclear power plants are located. In addition, currently the market design under which the plants operate does not adequately compensate merchant nuclear plants for their environmental and fuel diversity benefits in the region. These conditions were primary factors leading to Entergy’s decision to shut down (or sell) Entergy Wholesale Commodities’ nuclear power plants before the end of their operating licenses.
The price that different counterparties offer for various products including forward sales is influenced both by market conditions as well as the contract terms such as damage provisions, credit support requirements, and the number of available counterparties interested in contracting for the desired forward period. Depending on differences between market factors at the time of contracting versus current conditions, Entergy Wholesale Commodities’ contract portfolio may have average contract prices above or below current market prices, including at the expiration of the contracts, which may significantly affect Entergy Wholesale Commodities’ results of operations, financial condition, or liquidity. New hedges are generally layered into on a rolling forward basis, which tends to drive hedge over-performance to market in a falling price environment, and hedge underperformance to market in a rising price environment; however, hedge timing, product choice, and hedging costs will also affect these results. See the “Market and Credit Risk Sensitive Instruments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries. Since Entergy Wholesale Commodities has announced the closure (or sale) of its nuclear plants, Entergy Wholesale Commodities may enter into fewer forward sales contracts for output from such plants.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The Entergy Wholesale Commodities business is subject to substantial governmental regulation and may be adversely affected by legislative, regulatory, or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
The Entergy Wholesale Commodities business is subject to extensive regulation under federal, state, and local laws. Compliance with the requirements under these various regulatory regimes may cause the Entergy Wholesale Commodities business to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines, and/or civil or criminal liability.
Public utilities under the Federal Power Act are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Each of the owners of the Entergy Wholesale Commodities nuclear power plants that generates electricity, as well as Entergy Nuclear Power Marketing, LLC, is a “public utility” under the Federal Power Act by virtue of making wholesale sales of electric energy and/or owning wholesale electric transmission facilities. The FERC has granted these generating and power marketing companies the authority to sell electricity at market-based rates. The FERC’s orders that grant the Entergy Wholesale Commodities’ generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that the Entergy Wholesale Commodities business can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, the Entergy Wholesale Commodities’ market-based sales are subject to certain market behavior rules, and if any of its generating and power marketing companies were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority and potential penalties of up to $1.29 million per day per violation. If the Entergy Wholesale Commodities’ generating or power marketing companies were to lose their market-based rate authority, such companies would be required to obtain the FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates the Entergy Wholesale Commodities business charges for power from its facilities.
The Entergy Wholesale Commodities business is also affected by legislative and regulatory changes, as well as changes to market design, market rules, tariffs, cost allocations, and bidding rules imposed by the existing Independent System Operators. The Independent System Operators that oversee most of the wholesale power markets may impose, and in the future may continue to impose, mitigation, including price limitations, offer caps and other mechanisms, to address some of the volatility and the potential exercise of market power in these markets. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of the Entergy Wholesale Commodities business’ generation facilities that sell energy and capacity into the wholesale power markets. For further information regarding federal, state, and local laws and regulation applicable to the Entergy Wholesale Commodities business, see the “Regulation of Entergy’s Business” section in Part I, Item 1.
The regulatory environment applicable to the electric power industry is subject to changes as a result of restructuring initiatives at both the state and federal levels. Entergy cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on the Entergy Wholesale Commodities business. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism, have raised claims that the competitive marketplace is not working because energy prices in wholesale markets exceed the marginal cost of operating nuclear power plants, and have made proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process, which could require material changes to business planning models. If competitive restructuring of the electric power markets is reversed, modified, discontinued, or delayed, the Entergy Wholesale Commodities business’ results of operations, financial condition, and liquidity could be materially affected.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The power plants owned by the Entergy Wholesale Commodities business are subject to impairment charges in certain circumstances, which could have a material effect on Entergy’s results of operations, financial condition, or liquidity.
Entergy reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from the operations of such assets. Projected net cash flows depend on the expected operating life of the assets, the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy and capacity over the remaining life of the assets. In particular, the remaining assets of the Entergy Wholesale Commodities business are subject to further impairment in connection with the closure and sale of its nuclear power plants. Moreover, prior to the closure and sale of these plants, the failure of the Entergy Wholesale Commodities business to achieve forecasted operating results and cash flows, an unfavorable change in forecasted operating results or cash flows, a reduction in the expected remaining useful life of a unit, or a decline in observable industry market multiples could all result in potential additional impairment charges for the affected assets.
If Entergy concludes that any of its nuclear power plants is unlikely to operate through its planned shutdown date, which conclusion would be based on a variety of factors, such a conclusion could result in a further impairment of part or all of the carrying value of the plant. Any impairment charge taken by Entergy with respect to its long-lived assets, including the remaining power plants owned by the Entergy Wholesale Commodities business, would likely be material in the quarter that the charge is taken and could otherwise have a material effect on Entergy’s results of operations, financial condition, or liquidity. For further information regarding evaluating long-lived assets for impairment, see the “Critical Accounting Estimates - Impairment of Long-lived Assets” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries and for further discussion of the impairment charges, see Note 14 to the financial statements.
General Business
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Entergy and the Utility operating companies depend on access to the capital markets and, at times, may face potential liquidity constraints, which could make it more difficult to handle future contingencies such as natural disasters or substantial increases in gas and fuel prices. Disruptions in the capital and credit markets may adversely affect Entergy’s and its subsidiaries’ ability to meet liquidity needs, access capital and operate and grow their businesses, and the cost of capital.
Entergy’s business is capital intensive and dependent upon its ability to access capital at reasonable rates and other terms. At times there are also spikes in the price for natural gas and other commodities that increase the liquidity requirements of the Utility operating companies and Entergy Wholesale Commodities. In addition, Entergy’s and the Utility operating companies’ liquidity needs could significantly increase in the event of a hurricane or other weather-related or unforeseen disaster similar to that experienced in Entergy’s service territory with Hurricane Katrina and Hurricane Rita in 2005, Hurricane Gustav and Hurricane Ike in 2008, Hurricane Isaac in 2012, and Hurricane Laura, Hurricane Delta, and Hurricane Zeta in 2020. The occurrence of one or more contingencies, including a delay in regulatory recovery of fuel or purchased power costs or storm restoration costs, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, changes in regulation or governmental policy (including tax and trade policy), or other unknown events, could cause the financing needs of Entergy and its subsidiaries to increase. In addition, accessing the debt capital markets more frequently in these situations may result in an increase in leverage. Material leverage increases could negatively affect the credit ratings of Entergy and the Utility operating companies, which in turn could negatively affect access to the capital markets.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The inability to raise capital on favorable terms, particularly during times of high interest rates, and uncertainty or reduced liquidity in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses. Access to capital markets could be restricted and/or borrowing costs could be increased due to certain sources of debt and equity capital being unwilling to invest in companies that experience extreme weather events, that rely on fossil fuels or offerings to fund fossil fuel projects, or due to risks related to climate change. Events beyond Entergy’s control may create uncertainty that could increase its cost of capital or impair its ability to access the capital markets, including the ability to draw on its bank credit facilities. Entergy and its subsidiaries are unable to predict the degree of success they will have in renewing or replacing their credit facilities as they come up for renewal. Moreover, the size, terms, and covenants of any new credit facilities may not be comparable to, and may be more restrictive than, existing facilities. If Entergy and its subsidiaries are unable to access the credit and capital markets on terms that are reasonable, they may have to delay raising capital, issue shorter-term securities and/or bear an unfavorable cost of capital, which, in turn, could impact their ability to grow their businesses, decrease earnings, significantly reduce financial flexibility and/or limit Entergy Corporation’s ability to sustain its current common stock dividend level.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
A downgrade in Entergy Corporation’s or its subsidiaries’ credit ratings could negatively affect Entergy Corporation’s and its subsidiaries’ ability to access capital and/or could require Entergy Corporation or its subsidiaries to post collateral, accelerate certain payments, or repay certain indebtedness.
There are a number of factors that rating agencies evaluate to arrive at credit ratings for each of Entergy Corporation and the Registrant Subsidiaries, including each Registrant’s regulatory framework, ability to recover costs and earn returns, diversification and financial strength and liquidity. If one or more rating agencies downgrade Entergy Corporation’s, any of the Utility operating companies’, or System Energy’s ratings, particularly below investment grade, borrowing costs would increase, the potential pool of investors and funding sources would likely decrease, and cash or letter of credit collateral demands may be triggered by the terms of a number of commodity contracts, leases, and other agreements.
Most of Entergy Corporation’s and its subsidiaries’ suppliers and counterparties require sufficient creditworthiness to enter into transactions. If Entergy Corporation’s or its subsidiaries’ ratings decline, particularly below investment grade, or if certain counterparties believe Entergy Corporation or the Utility operating companies are losing creditworthiness and demand adequate assurance under fuel, gas, and purchased power contracts, the counterparties may require posting of collateral in cash or letters of credit, prepayment for fuel, gas or purchased power or accelerated payment, or counterparties may decline business with Entergy Corporation or its subsidiaries. At December 31, 2020 based on power prices at that time, Entergy had liquidity exposure of $62 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $6 million of posted cash collateral. In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as of December 31, 2020, Entergy would have been required to provide approximately $30 million of additional cash or letters of credit under some of the agreements. As of December 31, 2020, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $22 million for a $1 per MMBtu increase in gas prices in both the short- and long-term markets.
Recent U.S. tax legislation may materially adversely affect Entergy’s financial condition, results of operations, and cash flows.
The Tax Cuts and Jobs Act of 2017 and CARES Act of 2020 significantly changed the U.S. Internal Revenue Code, including taxation of U.S. corporations, by, among other things, reducing the federal corporate income tax rate, limiting interest deductions, and altering the expensing of capital expenditures. The interpretive
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
guidance issued by the IRS and state tax authorities may be inconsistent with Entergy’s own interpretation and the legislation could be subject to amendments, which could lessen or increase certain impacts of the legislation.
As further described in Note 3 to the financial statements, as a result of amortization of accumulated deferred income taxes and payment of such amounts to customers in 2019, Entergy’s net regulatory liability for income taxes balance is $1.6 billion as of December 31, 2020. Depending on the outcome of IRS examinations or tax positions and elections that Entergy may make, Entergy and the Registrant Subsidiaries may be required to record additional charges or credits to income tax expense. Further, there may be other material effects resulting from the legislation that have not been identified.
See Note 3 to the financial statements for discussion of the effects of the Tax Cuts and Jobs Act on 2018, 2019 and 2020 results of operations and financial condition, the provisions of the Tax Cuts and Jobs Act, and the uncertainties associated with accounting for the Tax Cuts and Jobs Act, and Note 2 to the financial statements for discussion of the regulatory proceedings that have considered the effects of the Tax Cuts and Jobs Act.
Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s, the Utility operating companies’, and System Energy’s results of operations, financial condition, and liquidity.
Entergy and its subsidiaries make judgments regarding the potential tax effects of various transactions and results of operations to estimate their obligations to taxing authorities. These tax obligations include income, franchise, real estate, sales and use, and employment-related taxes. These judgments include provisions for potential adverse outcomes regarding tax positions that have been taken. Entergy and its subsidiaries also estimate their ability to utilize tax benefits, including those in the form of carryforwards for which the benefits have already been reflected in the financial statements. Changes in federal, state, or local tax laws, adverse tax audit results or adverse tax rulings on positions taken by Entergy and its subsidiaries could negatively affect Entergy’s, the Utility operating companies’, and System Energy’s results of operations, financial condition, and liquidity. For further information regarding Entergy’s income taxes, see Note 3 to the financial statements.
Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to complete strategic transactions, is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies, which could materially affect their future prospects, results of operations, and benefits that they anticipate from such transactions.
Entergy and its subsidiaries’ future prospects and results of operations significantly depend on their ability to successfully implement their business strategies, which are subject to business, regulatory, economic, and other risks and uncertainties, many of which are beyond their control. As a result, Entergy and its subsidiaries may be unable to fully achieve the anticipated results of such strategies.
Additionally, Entergy and its subsidiaries have pursued and may continue to pursue strategic transactions including merger, acquisition, divestiture, joint venture, restructuring, or other strategic transactions. For example, Entergy has entered into an agreement to sell its equity interests in the subsidiary that owns the Palisades Nuclear Plant and the decommissioned Big Rock Point Nuclear Power Plant and an agreement to sell the equity interests of Indian Point 1, Indian Point 2, and Indian Point 3, in each case after each of the plants has been shut down and defueled. Also, a significant portion of Entergy’s utility business over the next several years includes the construction and/or purchase of a variety of generating units. These transactions and plans are or may become subject to regulatory approval and other material conditions or contingencies. The failure to complete these transactions or plans or any future strategic transaction successfully or on a timely basis could have an adverse effect on Entergy’s or its subsidiaries’ financial condition or results of operations and the market’s perception of Entergy’s ability to execute its strategy. Further, these transactions, and any completed or future strategic transactions, involve substantial risks, including the following:
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
•acquired businesses or assets may not produce revenues, earnings, or cash flow at anticipated levels;
•acquired businesses or assets could have environmental, permitting, or other problems for which contractual protections prove inadequate;
•Entergy and/or its subsidiaries may assume liabilities that were not disclosed to them, that exceed their estimates, or for which their rights to indemnification from the seller are limited;
•Entergy may experience issues integrating businesses into its internal controls over financial reporting;
•the disposition of a business, including Entergy’s planned exit from the merchant power business, could divert management’s attention from other business concerns;
•Entergy and/or its subsidiaries may be unable to obtain the necessary regulatory or governmental approvals to close a transaction, such approvals may be granted subject to terms that are unacceptable, or Entergy or its subsidiaries otherwise may be unable to achieve anticipated regulatory treatment of any such transaction or acquired business or assets; and
•Entergy or its subsidiaries otherwise may be unable to achieve the full strategic and financial benefits that they anticipate from the transaction, or such benefits may be delayed or may not occur at all.
Entergy and its subsidiaries may not be successful in managing these or any other significant risks that they may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material effect on their business, financial condition or results of operations.
The completion of capital projects, including the construction of power generation facilities, and other capital improvements involve substantial risks. Should such efforts be unsuccessful, the financial condition, results of operations, or liquidity of Entergy and the Utility operating companies could be materially affected.
Entergy’s and the Utility operating companies’ ability to complete capital projects, including the construction of power generation facilities, or make other capital improvements, in a timely manner and within budget is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise, escalating costs for materials, labor, and environmental compliance, and reliance on suppliers for timely and satisfactory performance. Delays in obtaining permits, shortages in materials and qualified labor, levels of public support or opposition, suppliers and contractors not performing as expected or required under their contracts and/or experiencing financial problems that inhibit their ability to fulfill their obligations under contracts, changes in the scope and timing of projects, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in law or regulation, including environmental compliance requirements, and other events beyond the control of the Utility operating companies or the Entergy Wholesale Commodities business may occur that may materially affect the schedule, cost, and performance of these projects. If these projects or other capital improvements are significantly delayed or become subject to cost overruns or cancellation, Entergy and the Utility operating companies could incur additional costs and termination payments, or face increased risk of potential write-off of the investment in the project. In addition, the Utility operating companies could be exposed to higher costs and market volatility, which could affect cash flow and cost recovery, should their respective regulators decline to approve the construction of the project or new generation needed to meet the reliability needs of customers at the lowest reasonable cost.
For further information regarding capital expenditure plans and other uses of capital in connection with capital projects, including the potential construction and/or purchase of additional generation supply sources within the Utility operating companies’ service territory, and as to the Entergy Wholesale Commodities business, see the “Capital Expenditure Plans and Other Uses of Capital” section of Management’s Financial Discussion and Analysis for Entergy and each of the Registrant Subsidiaries.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Failure to attract, retain and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
We rely on a large and changing workforce of team members, including employees, contractors and temporary staffing. Certain events, such as an aging workforce, mismatching of skill sets, failing to appropriately anticipate future workforce needs, or the unavailability of contract resources may lead to operating challenges and increased costs. The challenges include lack of resources, loss of knowledge base, and the time required for skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, and safety costs, may increase. Failure to hire and adequately train replacement employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate the business, especially considering the workforce needs associated with nuclear generation facilities and new skills required to operate a modernized, technology-enabled power grid. If Entergy and its subsidiaries are unable to successfully attract, retain, and manage an appropriately qualified workforce, their results of operations, financial position, and cash flows could be negatively affected.
The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs to fulfill their obligations related to environmental and other matters.
The businesses in which the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business operate are subject to extensive environmental regulation by local, state, and federal authorities. These laws and regulations affect the manner in which the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business conduct their operations and make capital expenditures. These laws and regulations also affect how the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business manage air emissions, discharges to water, wetlands impacts, solid and hazardous waste storage and disposal, cooling and service water intake, the protection of threatened and endangered species, certain migratory birds and eagles, hazardous materials transportation, and similar matters. Federal, state, and local authorities continually revise these laws and regulations, and the laws and regulations are subject to judicial interpretation and to the permitting and enforcement discretion vested in the implementing agencies. Developing and implementing plans for facility compliance with these requirements can lead to capital, personnel, and operation and maintenance expenditures. Violations of these requirements can subject the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. In addition, the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business potentially are subject to liability under these laws for the costs of remediation of environmental contamination of property now or formerly owned or operated by the Utility operating companies, System Energy, and Entergy Wholesale Commodities and of property contaminated by hazardous substances they generate. The Utility operating companies currently are involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future. The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business have incurred and expect to incur significant costs related to environmental compliance.
Emissions of nitrogen and sulfur oxides, mercury, particulates, greenhouse gases, and other regulated air emissions from generating plants potentially are subject to increased regulation, controls, and mitigation expenses. In addition, existing air regulations and programs promulgated by the EPA often are challenged legally, or are revised or withdrawn by the EPA, sometimes resulting in large-scale changes to anticipated regulatory regimes and the resulting need to shift course, both operationally and economically, depending on the nature of the changes. Risks relating to global climate change, initiatives to compel greenhouse gas emission reductions, and water availability issues are discussed below.
Entergy and its subsidiaries may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if Entergy and its subsidiaries fail to obtain, maintain, or comply with any such approval, the operation of its facilities could be
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
stopped or become subject to additional costs. For further information regarding environmental regulation and environmental matters, see the “Regulation of Entergy’s Business– Environmental Regulation” section of Part I, Item 1.
The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs related to reliability standards.
Entergy’s business is subject to extensive and mandatory reliability standards. Such standards, which are established by the NERC, the SERC, and other regional enforcement entities, are approved by the FERC and frequently are reviewed, amended, and supplemented. Failure to comply with such standards could result in the imposition of fines or civil penalties, and potential exposure to third party claims for alleged violations of such standards. The standards, as well as the laws and regulations that govern them, are subject to judicial interpretation and to the enforcement discretion vested in the implementing agencies. In addition to exposure to civil penalties and fines, the Utility operating companies have incurred and expect to incur significant costs related to compliance with new and existing reliability standards, including costs associated with the Utility operating companies’ transmission system and generation assets. In addition, the retail regulators of the Utility operating companies possess the jurisdiction, and in some cases have exercised such jurisdiction, to impose standards governing the reliable operation of the Utility operating companies’ distribution systems, including penalties if these standards are not met. The changes to the reliability standards applicable to the electric power industry are ongoing, and Entergy cannot predict the ultimate effect that the reliability standards will have on its Utility and Entergy Wholesale Commodities businesses.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas usage and otherwise materially affect the Utility operating companies’ results of operations and system reliability.
Temperatures above normal levels in the summer tend to increase electric cooling demand and revenues, and temperatures below normal levels in the winter tend to increase electric and gas heating demand and revenues. As a corollary, mild temperatures in either season tend to decrease energy usage and resulting revenues. Higher consumption levels coupled with seasonal pricing differentials typically cause the Utility operating companies to report higher revenues in the third quarter of the fiscal year than in the other quarters. Extreme weather conditions including hurricanes or tropical storms, flooding events, or ice storms may stress the Utility operating companies’ generation facilities and transmission and distribution systems, resulting in increased maintenance and capital costs (and potential increased financing needs), limits on their ability to meet peak customer demand, increased regulatory oversight, and reduced customer satisfaction. These extreme conditions could have a material effect on the Utility operating companies’ financial condition, results of operations, and liquidity.
Entergy’s electricity sales volumes are affected by a number of factors including weather and economic conditions, trends in energy efficiency, new technologies, and self-generation alternatives, including the willingness and ability of large industrial customers to develop co-generation facilities that greatly reduce their grid demand. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and rarely have a long-lasting effect on Entergy’s operating results. Others, such as the organic turnover of appliances and their replacement with more efficient ones, adoption of newer technologies including smart thermostats, new building codes, distributed energy resources, energy storage, demand side management, and rooftop solar are having a more permanent effect by reducing sales growth rates from historical norms. As a result of these emerging efficiencies and technologies, the Utility operating companies may lose customers or experience lower average use per customer in the residential and commercial classes, and continuing advances have the potential to further limit sales growth in the future. The Utility operating companies also may face competition from other companies offering products and services to Entergy’s customers. Electricity sales to industrial
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
customers, in particular, benefit from steady economic growth and favorable commodity markets; however, industrial sales are sensitive to changes in conditions in the markets in which its customers operate. Negative changes in any of these or other factors, particularly sustained economic downturns or sluggishness, have the potential to result in slower sales growth or sales declines and increased bad debt expense, which could materially affect Entergy’s and the Utility operating companies’ results of operations, financial condition, and liquidity.
The effects of climate change, environmental and regulatory obligations intended to compel greenhouse gas emission reductions or increase clean or renewable energy requirements or to place a price on greenhouse gas emissions, or achieving voluntary climate commitments could materially affect the financial condition, results of operations, and liquidity of Entergy, the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business.
In an effort to address climate change concerns, some federal, state, and local authorities are calling for additional laws and regulations aimed at known or suspected causes of climate change. For example, in response to the United States Supreme Court’s 2007 decision holding that the EPA has authority to regulate emissions of CO2 and other “greenhouse gases” under the Clean Air Act, the EPA, various environmental interest groups, and other organizations focused considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. Since that ruling, the EPA has promulgated regulations controlling greenhouse gas emissions from certain vehicles, and from new, existing, and significantly modified stationary sources of emissions, including electric generating units. As examples of state action, in the Northeast, the Regional Greenhouse Gas Initiative establishes a cap on CO2 emissions from electric power plants and requires generators to purchase emission permits to cover their CO2 emissions, and a similar program has been developed in California. In Louisiana, the Office of the Governor announced the creation of a Climate Initiatives Task Force and issued an executive order that established a path to net-zero emissions by 2050 while the City Council of New Orleans passed a renewable and clean portfolio standard that sets a goal of net-zero emissions by 2040 and absolute zero emissions by 2050. The impact that continued changes in the governmental response to climate change risk will have on existing and pending environmental laws and regulations related to greenhouse gas emissions is currently unclear.
Developing and implementing plans for compliance with greenhouse gas emissions reduction, clean/renewable energy requirements, or for achieving voluntary climate commitments can lead to additional capital, personnel, and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects. The operations of low or non-emitting generating units (such as nuclear units) at lower than expected capacity factors could require increased generation from higher emitting units, thus increasing the company’s greenhouse gas emission rate. Moreover, long-term planning to meet environmental requirements can be negatively impacted and costs may increase to the extent laws and regulations change prior to full implementation. These requirements could, in turn, lead to changes in the planning or operations of balancing authorities or organized markets in areas where the Utility operating companies, System Energy, or Entergy Wholesale Commodities do business. Violations of such requirements may subject Entergy Wholesale Commodities and the Utility operating companies to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. To the extent Entergy believes any of these costs are recoverable in rates, however, additional material rate increases for customers could be resisted by Entergy’s regulators and, in extreme cases, Entergy’s regulators might attempt to deny or defer timely recovery of these costs. Future changes in regulation or policies governing the emission of CO2 and other greenhouse gases or mix of generation sources could (i) result in significant additional costs to Entergy’s utility operating companies, their suppliers or customers, (ii) make some of Entergy’s electric generating units uneconomical to maintain or operate, (iii) result in the early retirement of generation facilities and stranded costs if Entergy’s utility operating companies are unable to fully recover the costs and investment in generation and (iv) could increase the difficulty that Entergy and its utility operating companies have with obtaining or maintaining required environmental regulatory approvals, each of which could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries. In addition, lawsuits have occurred or are reasonably expected against emitters of greenhouse gases alleging that these
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
companies are liable for personal injuries and property damage caused by climate change. These lawsuits may seek injunctive relief, monetary compensation, and punitive damages.
In addition to the regulatory and financial risks associated with climate change discussed above, potential physical risks from climate change include an increase in sea level, wind and storm surge damages, wildfires, wetland and barrier island erosion, risks of flooding and changes in weather conditions, (such as increases in precipitation, drought, or changes in average temperatures), and potential increased impacts of extreme weather conditions or storms. Entergy subsidiaries own assets in, and serve, communities that are at risk from sea level rise, changes in weather conditions, storms, and loss of the protection offered by coastal wetlands. A significant portion of the nation’s oil and gas infrastructure is located in these areas and susceptible to storm damage that could be aggravated by the physical impacts of climate change, which could give rise to fuel supply interruptions and price spikes. Entergy and its subsidiaries also face the risk that climate change could impact the availability and quality of water supply necessary for operations.
These and other physical changes could result in changes in customer demand, increased costs associated with repairing and maintaining generation facilities and transmission and distribution systems resulting in increased maintenance and capital costs (and potential increased financing needs), limits on the Entergy System’s ability to meet peak customer demand, more frequent and longer lasting outages, increased regulatory oversight, and lower customer satisfaction. Also, to the extent that climate change adversely impacts the economic health of a region or results in energy conservation or demand side management programs, it may adversely impact customer demand and revenues. Such physical or operational risks could have a material effect on Entergy’s, Entergy Wholesale Commodities’, System Energy’s, and the Utility operating companies’ financial condition, results of operations, and liquidity.
In September 2020, Entergy voluntarily committed to achieving net zero carbon emissions by 2050. Technology research and development, innovation, and advancement are critical to Entergy’s ability to achieve this commitment. Moreover, Entergy cannot predict the ultimate impact of achieving this objective, or the various implementation aspects, on its system reliability, or its results of operations, financial condition or liquidity.
Continued and future availability and quality of water for cooling, process, and sanitary uses could materially affect the financial condition, results of operations, and liquidity of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business.
Water is a vital natural resource that is also critical to the Utility operating companies’, System Energy’s, and Entergy Wholesale Commodities’ business operations. Entergy’s facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Entergy’s Utility operating companies also own and/or operate hydroelectric facilities. Accordingly, water availability and quality are critical to Entergy’s business operations. Impacts to water availability or quality could negatively impact both operations and revenues.
Entergy secures water through various mechanisms (ground water wells, surface waters intakes, municipal supply, etc.) and operates under the provisions and conditions set forth by the provider and/or regulatory authorities. Entergy also obtains and operates in substantial compliance with water discharge permits issued under various provisions of the Clean Water Act and/or state water pollution control provisions. Regulations and authorizations for both water intake and use and for waste discharge can become more stringent in times of water shortages, low flows in rivers, low lake levels, low groundwater aquifer volumes, and similar conditions. The increased use of water by industry, agriculture, and the population at large, population growth, and the potential impacts of climate change on water resources may cause water use restrictions that affect Entergy and its subsidiaries.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices, which could materially affect Entergy’s and its subsidiaries’ results of operations, financial condition, and liquidity.
To manage near-term financial exposure related to commodity price fluctuations, Entergy and its subsidiaries, including the Utility operating companies and the Entergy Wholesale Commodities business, may enter into contracts to hedge portions of their purchase and sale commitments, fuel requirements, and inventories of natural gas, uranium and its conversion and enrichment, coal, refined products, and other commodities, within established risk management guidelines. As part of this strategy, Entergy and its subsidiaries may utilize fixed- and variable-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. However, Entergy and its subsidiaries normally cover only a portion of the exposure of their assets and positions to market price volatility, and the coverage will vary over time. In addition, Entergy also elects to leave certain volumes during certain years unhedged. To the extent Entergy and its subsidiaries have unhedged positions, fluctuating commodity prices can materially affect Entergy’s and its subsidiaries’ results of operations and financial position.
Although Entergy and its subsidiaries devote a considerable effort to these risk management strategies, they cannot eliminate all the risks associated with these activities. As a result of these and other factors, Entergy and its subsidiaries cannot predict with precision the impact that risk management decisions may have on their business, results of operations, or financial position.
Entergy’s over-the-counter financial derivatives are subject to rules implementing the Dodd-Frank Wall Street Reform and Consumer Protection Act that are designed to promote transparency, mitigate systemic risk, and protect against market abuse. Entergy cannot predict the impact any proposed or not fully-implemented final rules will have on its ability to hedge its commodity price risk or on over-the-counter derivatives markets as a whole, but such rules and regulations could have a material effect on Entergy's risk exposure, as well as reduce market liquidity and further increase the cost of hedging activities.
Entergy has guaranteed or indemnified the performance of a portion of the obligations relating to hedging and risk management activities. Reductions in Entergy’s or its subsidiaries’ credit quality or changes in the market prices of energy commodities could increase the cash or letter of credit collateral required to be posted in connection with hedging and risk management activities, which could materially affect Entergy’s or its subsidiaries’ liquidity and financial position.
The Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties may not meet their obligations, which may materially affect the Utility operating companies and Entergy Wholesale Commodities.
The hedging and risk management practices of the Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties that owe Entergy and its subsidiaries money, energy, or other commodities will not perform their obligations. Currently, some hedging agreements contain provisions that require the counterparties to provide credit support to secure all or part of their obligations to Entergy or its subsidiaries. If the counterparties to these arrangements fail to perform, Entergy or its subsidiaries may enforce and recover the proceeds from the credit support provided and acquire alternative hedging arrangements, which credit support may not always be adequate to cover the related obligations. In such event, Entergy and its subsidiaries might incur losses in addition to amounts, if any, already paid to the counterparties. In addition, the credit commitments of Entergy’s lenders under its bank facilities may not be honored for a variety of reasons, including unexpected periods of financial distress affecting such lenders, which could materially affect the adequacy of its liquidity sources.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.
The performance of the capital markets affects the values of the assets held in trust under Entergy’s pension and postretirement benefit plans. A decline in the market value of the assets may increase the funding requirements relating to Entergy’s benefit plan liabilities and also result in higher benefit costs. As the value of the assets decreases, the “expected return on assets” component of benefit costs decreases, resulting in higher benefits costs. Additionally, asset losses are incorporated into benefit costs over time, thus increasing benefits costs. Volatility in the capital markets has affected the market value of these assets, which may affect Entergy’s planned levels of contributions in the future. Additionally, changes in interest rates affect the liabilities under Entergy’s pension and postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding and recognition of higher liability carrying costs. The funding requirements of the obligations related to the pension benefit plans can also increase as a result of changes in, among other factors, retirement rates, life expectancy assumptions, or Federal regulations. For further information regarding Entergy’s pension and other postretirement benefit plans, refer to the “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” section of Management’s Financial Discussion and Analysis for Entergy and each of its Registrant Subsidiaries and Note 11 to the financial statements.
The litigation environment in the states in which certain Entergy subsidiaries operate poses a significant risk to those businesses.
Entergy and its subsidiaries are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, asbestos, hazardous material and ratepayer matters, and injuries and damages issues, among other matters. The states in which the Utility operating companies operate have proven to be unusually litigious environments. Judges and juries in these states have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. Entergy and its subsidiaries use legal and appropriate means to contest litigation threatened or filed against them, but the litigation environment in these states poses a significant business risk.
Terrorist attacks, cyber attacks, system failures or data breaches of Entergy’s and its subsidiaries’ or our suppliers’ technology systems may adversely affect Entergy’s results of operations.
Entergy and its subsidiaries operate in a business that requires evolving information technology systems that include sophisticated data collection, processing systems, software, network infrastructure, and other technologies that are becoming more complex and may be subject to mandatory and prescriptive reliability and security standards. The functionality of Entergy’s technology systems depends on its own and its suppliers’ and their contractors’ technology. Suppliers’ and their contractors’ technology systems to which Entergy is connected directly or indirectly support a variety of business processes and activities to store sensitive data, including (i) intellectual property, (ii) proprietary business information, (iii) personally identifiable information of customers and employees, and (iv) data with respect to invoicing and the collection of payments, accounting, procurement, and supply chain activities. Any significant failure or malfunction of such information technology systems could result in loss of data or disruptions of operations.
There have been attacks and threats of attacks on energy infrastructure by cyber actors, including those associated with foreign governments. As an operator of critical infrastructure, Entergy and its subsidiaries face heightened risk of an act or threat of terrorism, cyber attacks, and data breaches, whether as a direct or indirect act against one of Entergy’s generation, transmission or distribution facilities, operations centers, infrastructure, or information technology systems used to manage, monitor, and transport power to customers and perform day-to-day business functions. An actual act could affect Entergy’s ability to operate, including its ability to operate the information technology systems and network infrastructure on which it relies to conduct business.
Given the rapid technological advancements of existing and emerging threats, Entergy’s technology systems remain inherently vulnerable despite implementations and enhancements of the multiple layers of security
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
and controls. If Entergy’s or its subsidiaries’ technology systems were compromised and unable to detect or recover in a timely fashion to a normal state of operations, Entergy or its subsidiaries could be unable to perform critical business functions that are essential to the company’s well-being and could result in a loss of its confidential, sensitive, and proprietary information, including personal information of its customers, employees, suppliers, and others in Entergy’s care.
Any such attacks, failures or data breaches could have a material effect on Entergy’s and the Utility operating companies’ business, financial condition, results of operations or reputation. Although we purchase insurance coverage for cyber-attacks or data breaches, such insurance may not be adequate to cover all losses that might arise in connection with these events. Such events may also expose Entergy to an increased risk of litigation (and associated damages and fines).
(Entergy New Orleans)
The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidity.
Gas rates charged to retail gas customers are comprised primarily of purchased gas cost charges, which provide no return or profit to Entergy New Orleans, and distribution charges, which provide a return or profit to the utility. Distribution charges recover fixed costs on a volumetric basis and, thus, are affected by the amount of gas sold to customers. When purchased gas cost charges increase due to higher gas procurement costs, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy New Orleans, which could adversely affect results of operations. Purchased gas cost charges, which comprise most of a customer’s bill and may be adjusted monthly, represent gas commodity costs that Entergy New Orleans recovers from its customers. Entergy New Orleans’s cash flows can be affected by differences between the time period when gas is purchased and the time when ultimate recovery from customers occurs.
(System Energy)
System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings.
System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. Charges under the Unit Power Sales Agreement are paid by the Utility operating companies as consideration for their respective entitlements to receive capacity and energy. The useful economic life of Grand Gulf is finite and is limited by the terms of its operating license, which expires in November 2044. System Energy’s financial condition depends both on the receipt of payments from the Utility operating companies under the Unit Power Sales Agreement and on the continued commercial operation of Grand Gulf. The Unit Power Sales Agreement is currently the subject of several litigation proceedings at the FERC, including a challenge with respect to System Energy’s uncertain tax positions, sale leaseback arrangement, authorized return on equity and capital structure, and a request in a separate proceeding for FERC to initiate a broader investigation of rates under the Unit Power Sales Agreement. The LPSC has also authorized the filing of a prudence complaint at the FERC relating to Grand Gulf operations. Entergy cannot predict the outcome of any of these proceedings nor can it predict whether any outcome could have a material effect on Entergy’s or System Energy’s results of operations, financial condition or liquidity. See Note 2 to the financial statements for further discussion of the proceedings. The Utility operating companies have agreed to implement certain protocols for providing retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
For information regarding the Unit Power Sales Agreement, the sale and leaseback transactions and certain other agreements relating to the Entergy System companies’ support of System Energy, see Notes 5 and 8 to the
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
financial statements and the “Utility - System Energy and Related Agreements” section of Part I, Item 1.
(Entergy Corporation)
As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock.
Entergy Corporation is a holding company with no material revenue generating operations of its own or material assets other than the stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Entergy Corporation’s ability to satisfy its financial obligations, including the payment of interest and principal on its outstanding debt, and to pay dividends on its common stock depends on the payment to it of dividends or distributions by its subsidiaries. The subsidiaries of Entergy Corporation are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make distributions to Entergy Corporation. The ability of such subsidiaries to make payments of dividends or distributions to Entergy Corporation depends on their results of operations and cash flows and other items affecting retained earnings, and on any applicable legal, regulatory, or contractual limitations on subsidiaries’ ability to pay such dividends or distributions. Prior to providing funds to Entergy Corporation, such subsidiaries have financial and regulatory obligations that must be satisfied, including among others, debt service and, in the case of Entergy Utility Holding Company and Entergy Texas, dividends and distributions on preferred securities. Any distributions from the Registrant Subsidiaries other than Entergy Texas and System Energy are paid directly to Entergy Utility Holding Company and are therefore subject to prior payment of distributions on its preferred securities.
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
The COVID-19 Pandemic
See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the COVID-19 pandemic.
February 2021 Winter Storms
See the “February 2021 Winter Storms” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the February 2021 winter storms. Entergy Arkansas’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $10 million. Natural gas purchases for Entergy Arkansas for February 1st through 25th, 2021 are approximately $105 million compared to natural gas purchases for February 2020 of $10 million.
Results of Operations
2020 Compared to 2019
Net Income
Net income decreased $17.7 million primarily due to lower volume/weather, a formula rate plan provision recorded in 2020 to reflect the 2019 historical year netting adjustment, and higher depreciation and amortization expenses, partially offset by higher retail electric price and lower other operation and maintenance expenses. See Note 2 to the financial statements for discussion of the 2019 historical year netting adjustment.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2020 to 2019:
| | | | | |
| Amount |
| (In Millions) |
2019 operating revenues | $2,259.6 | |
Fuel, rider, and other revenues that do not significantly affect net income | (278.5) | |
Volume/weather | (72.2) | |
Retail electric price | 57.4 | |
Return of unprotected excess accumulated deferred income taxes to customers | 118.2 | |
2020 operating revenues | $2,084.5 | |
Entergy Arkansas’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.
The volume/weather variance is primarily due to a decrease of 1,069 GWh, or 5%, in billed electricity usage, including decreased commercial and industrial usage as a result of the COVID-19 pandemic, and the effect of less favorable weather on residential and commercial sales, partially offset by an increase in residential usage as a
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
result of the COVID-19 pandemic. See “The COVID-19 Pandemic” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the COVID-19 pandemic.
The retail electric price variance is primarily due to the $56.5 million annual formula rate plan increase related to the 2020 projected test year included in the 2019 formula rate plan filing effective with the first billing cycle of January 2020. See Note 2 to the financial statements for further discussion of the formula rate plan filing.
The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through a tax adjustment rider beginning in April 2018. In 2020, $8.1 million was returned to customers as compared to $126.3 million in 2019. There is no effect on net income as the reduction in operating revenues in each period was offset by a reduction in income tax expense. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
Other Income Statement Variances
Nuclear refueling outage expenses decreased primarily due to the amortization of lower costs associated with the most recent outages as compared to previous outages.
Other operation and maintenance expenses decreased primarily due to:
•a decrease of $18.3 million in nuclear generation expenses primarily due to lower nuclear labor costs, including contract labor, in part as a result of the COVID-19 pandemic;
•a decrease of $13.2 million in non-nuclear generation expenses primarily due to lower long-term service agreement expenses;
•an $11.2 million write-off in 2019 of specific costs related to the potential construction of scrubbers at the White Bluff plant. See Note 2 to the financial statements for discussion of the write-off;
•higher nuclear insurance refunds of $7.8 million;
•a decrease of $5.9 million primarily due to contract costs in 2019 related to initiatives to explore new customer products and services; and
•a decrease of $5.8 million in energy efficiency costs.
The decrease was partially offset by the effects of recording in 2019 a final judgment to resolve claims in the ANO damages case against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $11.9 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expense. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Other income increased primarily due to changes in decommissioning trust fund investment activity.
Other regulatory credits - net for 2020 includes a provision of $43.5 million to reflect the 2019 historical year netting adjustment included in the APSC’s December 2020 order in the 2020 formula rate plan proceeding. See Note 2 to the financial statements for discussion of the 2020 formula rate plan proceeding.
The effective income tax rates were 16.3% for 2020 and (21.6%) for 2019. The difference in the effective income tax rate versus the federal statutory rate of 21% for 2019 was primarily due to the amortization of excess accumulated deferred income taxes. See Notes 2 and 3 to the financial statements for a discussion of the effects and regulatory activity regarding the Tax Cuts and Jobs Act. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 21% to the effective income tax rates.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2019 Compared to 2018
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 21, 2020, for discussion of results of operations for 2019 compared to 2018.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2020, 2019, and 2018 were as follows:
| | | | | | | | | | | | | | | | | | |
| 2020 | | 2019 | | 2018 | |
| (In Thousands) |
Cash and cash equivalents at beginning of period | $3,519 | | | $119 | | | $6,216 | | |
| | | | | | |
Net cash provided by (used in): | | | | | | |
Operating activities | 659,818 | | | 677,766 | | | 211,825 | | |
Investing activities | (795,709) | | | (676,293) | | | (688,727) | | |
Financing activities | 324,500 | | | 1,927 | | | 470,805 | | |
Net increase (decrease) in cash and cash equivalents | 188,609 | | | 3,400 | | | (6,097) | | |
| | | | | | |
Cash and cash equivalents at end of period | $192,128 | | | $3,519 | | | $119 | | |
2020 Compared to 2019
Operating Activities
Net cash flow provided by operating activities decreased $17.9 million in 2020 primarily due to:
•the timing of recovery of fuel and purchased power costs;
•lower collections of receivables from customers, in part due to the COVID-19 pandemic; and
•the timing of payments to vendors.
The decrease was partially offset by:
•a decrease in the return of unprotected excess accumulated deferred income taxes to customers in 2020 as compared to 2019. See Note 2 to the financial statements for further discussion of regulatory activity regarding the Tax Cuts and Jobs Act;
•$25 million in proceeds received from the DOE in 2020 resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
•a decrease of $15.8 million in pension contributions in 2020. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Investing Activities
Net cash flow used in investing activities increased $119.4 million in 2020 primarily due to:
•an increase of $79.5 million in storm spending;
•an increase of $47.3 million in non-nuclear generation construction expenditures primarily due to increased spending on various projects in 2020;
•an increase of $39.4 million in nuclear construction expenditures primarily as a result of work performed in 2020 on various ANO 2 outage projects;
•an increase of $38.5 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and service deliveries, and the timing of cash payments during the nuclear fuel cycle; and
•an increase of $30.3 million in distribution construction expenditures primarily due to investment in the reliability and infrastructure of Entergy Arkansas’s distribution system, including increased spending on advanced metering infrastructure.
The increase was partially offset by:
•a decrease of $56 million in transmission construction expenditures primarily due to a lower scope of work performed in 2020 as compared to 2019; and
•$55 million in proceeds received from the DOE in 2020 resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.
Financing Activities
Net cash flow provided by financing activities increased $322.6 million in 2020 primarily due to:
•issuances of $100 million of 4.0% Series mortgage bonds in March 2020 and $675 million of 2.65% Series mortgage bonds in September 2020;
•money pool activity;
•a decrease of $41.6 million in net long-term repayments in 2020 on the Entergy Arkansas nuclear fuel company variable interest entity credit facility; and
•a decrease of $20 million in common equity distributions in 2020 in order to maintain Entergy Arkansas’s capital structure.
The increase was partially offset by:
•the issuance of $350 million of 4.20% Series mortgage bonds in March 2019;
•the repayment in October 2020 of $200 million of 4.90% Series mortgage bonds due December 2052; and
•the repayment in October 2020 of $125 million of 4.75% Series mortgage bonds due June 2063.
Decreases in Entergy Arkansas’s payable to the money pool are a use of cash flow, and Entergy Arkansas’s payable to the money pool decreased by $21.6 million in 2020 compared to decreasing by $161.1 million in 2019. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
See Note 5 to the financial statements for further details of long-term debt.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2019 Compared to 2018
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Arkansas’s Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 21, 2020, for discussion of operating, investing, and financing cash flow activities for 2019 compared to 2018.
Capital Structure
Entergy Arkansas’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio is primarily due to the net issuances of long-term debt in 2020.
| | | | | | | | | | | |
| December 31, 2020 | | December 31, 2019 |
Debt to capital | 54.8 | % | | 53.0 | % |
Effect of excluding the securitization bonds | — | % | | — | % |
Debt to capital, excluding securitization bonds (a) | 54.8 | % | | 53.0 | % |
Effect of subtracting cash | (1.2 | %) | | — | % |
Net debt to net capital, excluding securitization bonds (a) | 53.6 | % | | 53.0 | % |
(a)Calculation excludes the securitization bonds, which are non-recourse to Entergy Arkansas.
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because the securitization bonds, which have been repaid as of December 31, 2020, were non-recourse to Entergy Arkansas, as more fully described in Note 5 to the financial statements. Entergy Arkansas also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because net debt indicates Entergy Arkansas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Arkansas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing distributions, Entergy Arkansas may receive equity contributions to maintain its capital structure.
Uses of Capital
Entergy Arkansas requires capital resources for:
•construction and other capital investments;
•debt maturities or retirements;
•working capital purposes, including the financing of fuel and purchased power costs; and
•distribution and interest payments.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| 2021 | | 2022 | | 2023 |
| (In Millions) |
Planned construction and capital investment: | | | | | |
Generation | $340 | | | $355 | | | $430 | |
Transmission | 40 | | | 45 | | | 190 | |
Distribution | 95 | | | 255 | | | 420 | |
Utility Support | 105 | | | 80 | | | 75 | |
Total | $580 | | | $735 | | | $1,115 | |
Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2021 | | 2022-2023 | | 2024-2025 | | After 2025 | | Total |
| (In Millions) |
Long-term debt (a) | $611 | | | $543 | | | $581 | | | $4,713 | | | $6,448 | |
Operating leases (b) | $14 | | | $21 | | | $15 | | | $11 | | | $61 | |
Finance leases (b) | $3 | | | $5 | | | $3 | | | $2 | | | $13 | |
Purchase obligations (c) | $452 | | | $618 | | | $509 | | | $3,882 | | | $5,461 | |
(a)Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.
(b)Lease obligations are discussed in Note 10 to the financial statements.
(c)Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Arkansas, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which are discussed in Note 8 to the financial statements.
In addition to the contractual obligations given above, Entergy Arkansas currently expects to contribute approximately $66.6 million to its qualified pension plans and approximately $517 thousand to its other postretirement health care and life insurance plans in 2021, although the 2021 required pension contributions will be known with more certainty when the January 1, 2021 valuations are completed, which is expected by April 1, 2021. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations, Entergy Arkansas has $252 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Arkansas includes specific investments in renewables such as the Searcy Solar Facility, Walnut Bend Solar Facility, and West Memphis Solar Facility; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including advanced meters and related investments; resource planning, including potential generation and renewables projects; system improvements; investments in ANO 1 and 2; software and security; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt maturities in Note 5 to the financial statements.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Arkansas pays distributions from its earnings at a percentage determined monthly.
Renewables
Searcy Solar Facility
In March 2019, Entergy Arkansas announced that it signed an agreement for the purchase of an approximately 100 MW solar energy facility that will be sited on approximately 800 acres in White County near Searcy, Arkansas. The purchase is contingent upon, among other things, obtaining necessary approvals from applicable federal and state regulatory and permitting agencies. The project is being constructed by a subsidiary of NextEra Energy Resources. Entergy Arkansas will purchase the facility upon mechanical completion and after the other purchase contingencies have been met. Closing is expected to occur by the end of 2021. In May 2019, Entergy Arkansas filed a petition with the APSC seeking a finding that the transaction is in the public interest and requesting all necessary approvals. In September 2019 other parties filed testimony largely supporting the resource acquisition but disputing Entergy Arkansas’s proposed method of cost recovery. Entergy Arkansas filed its rebuttal testimony in October 2019. In February 2020, Entergy Arkansas, the Attorney General, and the APSC general staff filed a partial settlement agreement asking the APSC to approve, based on the record in the proceeding, all issues except certain issues that are submitted to the APSC for determination. In April 2020 the APSC issued an order approving Entergy Arkansas’s acquisition of the Searcy Solar facility as being in the public interest, but declined to approve Entergy Arkansas’s preferred cost recovery rider mechanism, finding instead, based on the particular facts and circumstances presented, that the formula rate plan rider was a sufficient recovery mechanism for this resource.
Walnut Bend Solar Facility
In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 100 MW Walnut Bend Solar Facility is in the public interest. Entergy Arkansas requested a decision by the APSC by June 15, 2021 and primarily requests cost recovery through the formula rate plan rider. A procedural schedule was established with a hearing scheduled in April 2021. Closing is expected to occur in 2022.
West Memphis Solar Facility
In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 180 MW West Memphis Solar Facility is in the public interest. Entergy Arkansas requested a decision by the APSC by September 7, 2021 and primarily requests cost recovery through the formula rate plan rider. Closing is expected to occur in 2023.
Sources of Capital
Entergy Arkansas’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Entergy Arkansas may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest rates are favorable.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
All debt and common and preferred membership interest issuances by Entergy Arkansas require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in Entergy Arkansas’s bond indentures and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Arkansas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| | | | | | | | | | | | | | | | | | | | |
2020 | | 2019 | | 2018 | | 2017 |
(In Thousands) |
$3,110 | | ($21,634) | | ($182,738) | | ($166,137) |
See Note 4 to the financial statements for a description of the money pool.
Entergy Arkansas has a credit facility in the amount of $150 million scheduled to expire in September 2024. Entergy Arkansas also has a $25 million credit facility scheduled to expire in April 2021. The $150 million credit facility includes fronting commitments for the issuance of letters of credit against $5 million of the borrowing capacity of the facility. As of December 31, 2020, there were no cash borrowings and no letters of credit outstanding under the credit facilities. In addition, Entergy Arkansas is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2020, a $1 million letter of credit was outstanding under Entergy Arkansas’s uncommitted letter of credit facility. See Note 4 to the financial statements for further discussion of the credit facilities.
The Entergy Arkansas nuclear fuel company variable interest entity has a credit facility in the amount of $80 million scheduled to expire in September 2022. As of December 31, 2020, $12.2 million in loans were outstanding under the credit facility for the Entergy Arkansas nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of the nuclear fuel company variable interest entity credit facility.
Entergy Arkansas obtained authorization from the FERC through July 2022 for short-term borrowings not to exceed an aggregate amount of $250 million at any time outstanding and borrowings by its nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of Entergy Arkansas’s short-term borrowing limits. The long-term securities issuances of Entergy Arkansas are limited to amounts authorized by the FERC. The APSC has concurrent jurisdiction over Entergy Arkansas’s first mortgage bond/secured issuances. Entergy Arkansas has obtained long-term financing authorization from the FERC that extends through July 2022. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2022.
State and Local Rate Regulation and Fuel-Cost Recovery
Retail Rates
2018 Formula Rate Plan Filing
In July 2018, Entergy Arkansas filed with the APSC its 2018 formula rate plan filing to set its formula rate for the 2019 calendar year. The filing showed Entergy Arkansas’s projected earned return on common equity for the 2016 calendar yeartwelve months ended December 31, 2019 test period to be below the formula rate plan bandwidth. Additionally, the filing included the first netting adjustment under the current formula rate plan for the historical test year 2017, reflecting the change in formula rate plan revenues associated with actual 2017 results when compared to the allowed rate of return on equity. The filing showedincluded a $32.6projected $73.4 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity torevenue deficiency for 2019 and a $95.6 million revenue deficiency for the specified point2017 historical test year, for a total revenue requirement of adjustment$169 million for this filing. By operation of 9.96%, within the formula rate plan, bandwidth. In June 2016Entergy Arkansas’s recovery of the MPSC approved Entergy Mississippi’s joint stipulation with the Mississippi Public Utilities Staff. The joint stipulation provided for a total revenue increase of $23.7 million. The revenue increase includes a $19.4 million increase through the formula rate plan, resulting in a return on common equity point of adjustment of 10.07%. The revenue increase also includes $4.3 million in incremental ad valorem tax expenses to be collected through an updated ad valorem tax adjustment rider. The revenue increase and ad valorem tax adjustment rider were effective with the July 2016 bills.
In March 2017, Entergy Mississippi submitted its formula rate plan 2017 test year filing and 2016 look-back filing showing Entergy Mississippi’s earned return for the historical 2016 calendar year and projected earned return for the 2017 calendar year to be within the formula rate plan bandwidth, resulting in no change in rates. In June 2017, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a stipulation that confirmed that Entergy
requirement is
Entergy Mississippi, Inc.Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Mississippi’s earned returns for bothsubject to a four percent annual revenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the 2016 look-back filingconstraint, the resulting increase was limited to four percent of total revenue, which originally was $65.4 million but was increased to $66.7 million based upon the APSC staff’s updated calculation of 2018 revenue. In October 2018, Entergy Arkansas and 2017 test year were within the respectiveparties to the proceeding filed joint motions to approve a partial settlement agreement as to certain factual issues and agreed to brief contested legal issues. In November 2018 the APSC held a hearing and was briefed on a contested legal issue. In December 2018 the APSC issued a decision related to the initial legal brief, approved the partial settlement agreement and $66.7 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan, bandwidths. with updated rates going into effect for the first billing cycle of January 2019.
2019 Formula Rate Plan Filing
In June 2017July 2019, Entergy Arkansas filed with the MPSCAPSC its 2019 formula rate plan filing to set its formula rate for the 2020 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2020 and a netting adjustment for the historical year 2018. The total proposed formula rate plan rider revenue change designed to produce a target rate of return on common equity of 9.75% is $15.3 million, which is based upon a deficiency of approximately $61.9 million for the 2020 projected year, netted with a credit of approximately $46.6 million in the 2018 historical year netting adjustment. During 2018 Entergy Arkansas experienced higher-than expected sales volume, and actual costs were lower than forecasted. These changes, coupled with a reduced income tax rate resulting from the Tax Cuts and Jobs Act, resulted in the credit for the historical year netting adjustment. In the fourth quarter 2018, Entergy Arkansas recorded a provision of $35.1 million that reflected the estimate of the historical year netting adjustment that was expected to be included in the 2019 filing. In 2019, Entergy Arkansas recorded additional provisions totaling $11.5 million to reflect the updated estimate of the historical year netting adjustment included in the 2019 filing. In October 2019 other parties in the proceeding filed their errors and objections requesting certain adjustments to Entergy Arkansas’s filing that would reduce or eliminate Entergy Arkansas’s proposed revenue change. Entergy Arkansas filed its response addressing the requested adjustments in October 2019. In its response, Entergy Arkansas accepted certain of the adjustments recommended by the General Staff of the APSC that would reduce the proposed formula rate plan rider revenue change to $14 million. Entergy Arkansas disputed the remaining adjustments proposed by the parties. In October 2019, Entergy Arkansas filed a unanimous settlement agreement with the other parties in the proceeding seeking APSC approval of a revised total formula rate plan rider revenue change of $10.1 million. In its July 2019 formula rate plan filing, Entergy Arkansas proposed to recover an $11.2 million regulatory asset, amortized over five years, associated with specific costs related to the potential construction of scrubbers at the White Bluff plant. Although Entergy Arkansas does not concede that the regulatory asset lacks merit, for purposes of reaching a settlement on the total formula rate plan rider amount, Entergy Arkansas agreed not to include the White Bluff scrubber regulatory asset cost in the 2019 formula rate plan filing or future filings. Entergy Arkansas recorded a write-off in 2019 of the $11.2 million White Bluff scrubber regulatory asset. In December 2019 the APSC approved the stipulation, which resultedsettlement as being in nothe public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2020.
2020 Formula Rate Plan Filing
In July 2020, Entergy Arkansas filed with the APSC its 2020 formula rate plan filing to set its formula rate for the 2021 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2021, as amended through subsequent filings in the proceeding, and a netting adjustment for the historical year 2019. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2021 projected year is 8.22% resulting in a revenue deficiency of $64.3 million. The earned rate of return on common equity for the 2019 historical year was 9.07% resulting in a $23.9 million netting adjustment. The total proposed revenue change in rates.
Fuelfor the 2021 projected year and Purchased Power Cost Recovery
2019 historical year netting adjustment was $88.2 million. By operation of the formula rate plan, Entergy Mississippi’s rate schedules include an energy costArkansas’s recovery rider thatof the revenue requirement is adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi’s fuel cost recoveries are subject to a four percent annual audits conducted pursuantrevenue constraint. Because Entergy Arkansas’s revenue requirement in this filing exceeded the constraint, the resulting increase was limited to $74.3 million. In October 2020 other parties in the authority of the MPSC.
Entergy Mississippi had a deferred fuel over-recovery balance of $58.3 million as of May 31, 2015, along with an under-recovery balance of $12.3 million under the power management rider. Pursuant to those tariffs, in July 2015, Entergy Mississippiproceeding filed for interim adjustments under both the energy cost recovery rider and the power management rider to flow through to customers the approximately $46 million net over-recovery over a six-month period. In August 2015, the MPSC approved the interim adjustments effective with September 2015 bills. In November 2015, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included a projected over-recovery balance of $48 million projected through January 31, 2016. In January 2016 the MPSC approved the redetermined annual factor effective February 1, 2016. The MPSC further ordered, however, that due to the significant change in natural gas price forecasts since Entergy Mississippi’s filing in November 2015 Entergy Mississippi should file a revised fuel factor with the MPSC no later than February 1, 2016. Pursuant to that order, Entergy Mississippi submitted a revised fuel factor. Additionally, because Entergy Mississippi’s projected over-recovery balance for the period ending January 31, 2016 was $68 million, in February 2016, Entergy Mississippi filed for another interim adjustment to the energy cost factor effective April 2016 to flow through to customers the projected over-recovery balance over a six-month period. That interim adjustment was approved by the MPSC in February 2016 effective for April 2016 bills.
In November 2016, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an over-recovery of less than $2 million as of September 30, 2016. In January 2017 the MPSC approved the annual factor effective with February 2017 bills. Also in January 2017 the MPSC certified to the Mississippi Legislature the audit reports of its independent auditors for the fuel year ending September 30, 2016. In its order, the MPSC expressly reserved the right to review and determine the recoverability of any and all purchased power expenditures made during fiscal year 2016. The MPSC hired independent auditors to conduct an annual operations audit and a financial audit. The independent auditors issued their audit reports in December 2017. The audit reports included several recommendations for action by Entergy Mississippi but did not recommend any cost disallowances. In January 2018 the MPSC certified the audit reports to the Mississippi Legislature. In November 2017 the Public Utilities Staff separately engaged a consultant to review the outage at the Grand Gulf Nuclear Station that began in 2016. The review is currently in progress.
In November 2017, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an under-recovery of approximately $61.5 million as of September 30, 2017. Entergy Mississippi proposed a two-tiered energy cost factor designed to promote overall rate stability throughout 2018 particularly during the summer months. In January 2018 the MPSC approved the proposed energy cost factors effective for February 2018 bills.
Mississippi Attorney General Complaint
The Mississippi attorney general filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution. The complaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand. Entergy believes the complaint is unfounded. In December 2008 the defendant Entergy companies removed the Attorney General’s lawsuit to U.S. District Court in Jackson, Mississippi. The Mississippi attorney general moved to remand the matter to state court. In August 2012 the District
errors
Entergy Mississippi, Inc.Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Court issued an opinion denying the Attorney General’s motion for remand, finding that the District Court has subject matter jurisdiction under the Class Action Fairness Act.
The defendantand objections recommending certain adjustments, and Entergy companies answered the complaint andArkansas filed a counterclaim for relief based upon the Mississippi Public Utilities Act and the Federal Power Act. In May 2009 the defendant Entergy companies filed a motion for judgment on the pleadings asserting grounds of federal preemption, the exclusive jurisdictionresponsive testimony disputing these adjustments. As part of the MPSC, and factual errors informula rate plan tariff the Attorney General’s complaint.calculation for the revenue constraint was updated based on actual revenues which had the effect of reducing the initially-proposed $74.3 million revenue requirement increase to $72.6 million. In September 2012October 2020, Entergy Arkansas filed with the District Court heard oral argument on Entergy’s motion for judgment onAPSC a unanimous settlement agreement reached with the pleadings.
In January 2014 the U.S. Supreme Court issuedother parties that resolved all but one issue. As a decision in which it held that cases brought by attorneys general as the sole plaintiff to enforce state laws were not considered “mass actions” under the Class Action Fairness Act, so as to establish federal subject matter jurisdiction. One day later the Attorney General renewed his motion to remand the Entergy case back to state court, citing the U.S. Supreme Court’s decision. The defendant Entergy companies responded to that motion reiterating the additional grounds asserted for federal question jurisdiction, and the District Court held oral argument on the renewed motion to remand in February 2014. In April 2015 the District Court entered an order denying the renewed motion to remand, holding that the District Court has federal question subject matter jurisdiction. The Attorney General appealed to the U.S. Fifth Circuit Court of Appeals the denialresult of the motionsettlement agreement, Entergy Arkansas’s requested revenue increase was $68.4 million, including a $44.5 million increase for the projected 2021 year and a $23.9 million netting adjustment. The remaining issue litigated concerned the methodology used to remand.calculate the netting adjustment within the formula rate plan. In July 2015December 2020 the Fifth CircuitAPSC issued an order denyingrejecting the appeal, andnetting adjustment method used by Entergy Arkansas. Applying the Attorney General subsequentlyapproach ordered by the APSC changed the netting adjustment for the 2019 historical year from a $23.9 million deficiency to $43.5 million excess. Overall, the decision reduced Entergy Arkansas’s revenue adjustment for 2021 to $1 million. In December 2020, Entergy Arkansas filed a petition for rehearing of the requestAPSC’s decision, and in January 2021 the APSC granted further consideration of Entergy Arkansas’s petition. Based on the progress of the proceeding to date, in December 2020, Entergy Arkansas recorded a regulatory liability of $43.5 million to reflect the netting adjustment for interlocutory appeal,2019, as included in the APSC’s December 2020 order, which waswould be returned to customers in 2021. Also with the formula rate plan filing, Entergy Arkansas is requesting an extension of the formula rate plan rider for a second five-year term. Decisions by the APSC on the netting adjustment rehearing and the extension are expected in March 2021.
Internal Restructuring
In November 2017, Entergy Arkansas filed an application with the APSC seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy Arkansas to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. In July 2018, Entergy Arkansas filed a settlement, reached by all parties in the APSC proceeding, resolving all issues. The APSC approved the settlement agreement and restructuring in August 2018. Pursuant to the settlement agreement, Entergy Arkansas will credit retail customers $39.6 million over six years, beginning in 2019. Entergy Arkansas also denied. received the required FERC and NRC approvals.
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 20152018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the District Court orderedassets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Production Cost Allocation Rider
The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section in Note 2 to the financial statements.
Energy Cost Recovery Rider
Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly customer bills. The rider utilizes the prior calendar-year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over- or under-recovery, including carrying charges, of the energy costs for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs.
In January 2014, Entergy Arkansas filed a motion with the APSC relating to its upcoming energy cost rate redetermination filing that was made in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude from the redetermination of its 2014 energy cost rate $65.9 million of incremental fuel and replacement energy costs incurred in 2013 as a result of the ANO stator incident. Entergy Arkansas requested that the APSC authorize Entergy Arkansas to retain that amount in its deferred fuel balance, with recovery to be reviewed in a later period after more information was available regarding various claims associated with the ANO stator incident. In February 2014 the APSC approved Entergy Arkansas’s request to retain that amount in its deferred fuel balance. In July 2017, Entergy Arkansas filed for a change in rates pursuant to its formula rate plan rider. In that proceeding, the APSC approved a settlement agreement agreed upon by the parties, submitincluding a provision that requires Entergy Arkansas to initiate a regulatory proceeding for the purpose of recovering funds currently withheld from rates and related to the court undisputedstator incident, including the $65.9 million of deferred fuel and disputed facts that are materialpurchased energy costs previously noted, subject to certain timelines and conditions set forth in the settlement agreement. See the “ANO Damage, Outage, and NRC Reviews” section in Note 8 to the financial statements for further discussion of the ANO stator incident.
In March 2017, Entergy defendants’ motionArkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01164 per kWh to $0.01547 per kWh. The APSC staff filed testimony in March 2017 recommending that the redetermined rate be implemented with the first billing cycle of April 2017 under the normal operation of the tariff. Accordingly, the redetermined rate went into effect on March 31, 2017 pursuant to the tariff. In July 2017 the Arkansas Attorney General requested additional information to support certain of the costs included in Entergy Arkansas’s 2017 energy cost rate redetermination.
In March 2018, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase in the rate from $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Arkansas’s annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of the redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for judgment onsuspension were questions pertaining to how Entergy Arkansas forecasted sales and potential implications of the pleadings, as well as supplemental briefsTax Act. Entergy Arkansas replied to the Attorney General’s filing and stated that, to the extent there are questions pertaining to its load forecasting or the operation of the energy cost recovery rider, those issues exceed the scope of the instant rate redetermination. Entergy Arkansas also stated that potential effects of the Tax Act are appropriately considered in the APSC’s separate proceeding regarding potential implications of the same. Those filings were madetax law. The APSC general staff filed a reply to the Attorney General’s filing and agreed that Entergy Arkansas’s filing complied with the terms of the energy cost recovery rider. The redetermined rate became effective with the first billing cycle of April 2018. Subsequently in January 2016.April 2018 the APSC issued an order declining to suspend Entergy Arkansas’s energy cost recovery rider rate and declining to require further investigation at that time of the issues suggested by the Attorney General in the
In September 2016Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
proceeding. Following a period of discovery, the Attorney General filed a mandamus petitionsupplemental response in October 2018 raising new issues with Entergy Arkansas’s March 2018 rate redetermination and asserting that $45.7 million of the U.S. Fifth Circuit Courtincrease should be collected subject to refund pending further investigation. Entergy Arkansas filed to dismiss the Attorney General’s supplemental response, the APSC general staff filed a motion to strike the Attorney General’s filing, and the Attorney General filed a supplemental response disputing Entergy Arkansas and the APSC staff’s filing. Applicable APSC rules and processes authorize its general staff to initiate periodic audits of AppealsEntergy Arkansas’s energy cost recovery rider. In late-2018 the APSC general staff notified Entergy Arkansas it has initiated an audit of the 2017 fuel costs. The time in which the audit will be complete is uncertain at this time.
In March 2019, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01882 per kWh to $0.01462 per kWh and became effective with the first billing cycle in April 2019. In March 2019 the Arkansas Attorney General asked the Fifth Circuitfiled a response to order the chief judge to reassign this case to another judge. In September 2016 the District Court denied the Entergy companies’Arkansas’s annual adjustment and included with its filing a motion for judgment oninvestigation of alleged overcharges to customers in connection with the pleadings. TheFERC’s October 2018 order in the opportunity sales proceeding. Entergy companiesArkansas filed a motion seekingits response to amend the District Court’s order denying the Entergy companies’ motion for judgment on the pleadings and allowing an interlocutory appeal. In October 2016 the Fifth Circuit granted the Attorney General’s motion for writin April 2019 in which Entergy Arkansas stated its intent to initiate a proceeding to address recovery issues related to the October 2018 FERC order. In May 2019, Entergy Arkansas initiated the opportunity sales recovery proceeding, discussed below, and requested that the APSC establish that proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of mandamusthe FERC October 2018 order and directedrelated FERC orders in the chief judgeopportunity sales proceeding. In June 2019 the APSC granted Entergy Arkansas’s request and also denied the Attorney General’s motion in the energy cost recovery proceeding seeking an investigation into Entergy Arkansas’s annual energy cost recovery rider adjustment and referred the evaluation of such matters to assign the caseopportunity sales recovery proceeding.
In March 2020, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a new judge.decrease from $0.01462 per kWh to $0.01052 per kWh. The case was reassignedredetermined rate became effective with the first billing cycle in October 2016. April 2020 through the normal operation of the tariff.
Opportunity Sales Proceeding
In January 2017June 2009 the District CourtLPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocated the energy generated by Entergy System resources; (b) imprudently denied the Entergy companies’ motionSystem and its ultimate consumers the benefits of low-cost Entergy System generating capacity; and (c) violated the provision of the System Agreement that prohibited sales to amendthird parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challenged sales made beginning in 2002 and requested refunds. In July 2009 the Utility operating companies filed a response to the complaint arguing among other things that the System Agreement contemplates that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company. The FERC subsequently ordered a hearing in the proceeding.
After a hearing, the ALJ issued an initial decision in December 2010. The ALJ found that the System Agreement allowed for Entergy Arkansas to make the sales to third parties but concluded that the sales should be accounted for in the same manner as joint account sales. The ALJ concluded that “shareholders” should make refunds of the damages to the Utility operating companies, along with interest. Entergy disagreed with several aspects of the ALJ’s initial decision and in January 2011 filed with the FERC exceptions to the decision.
The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith. The FERC found, however, that the System Agreement does not provide authority for an individual Utility operating company to allocate the energy associated
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
with such opportunity sales as part of its load but provides a different allocation authority. The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement. The FERC in its decision established further hearing procedures to quantify the effect of repricing the opportunity sales in accordance with the FERC’s June 2012 decision. The hearing was held in May 2013 and the ALJ issued an initial decision in August 2013. The LPSC, the APSC, the City Council, and FERC staff filed briefs on exceptions and/or briefs opposing exceptions. Entergy filed a brief on exceptions requesting that the FERC reverse the initial decision and a brief opposing certain exceptions taken by the LPSC and FERC staff.
In April 2016 the FERC issued orders addressing requests for rehearing filed in July 2012 and the ALJ’s August 2013 initial decision. The first order denied Entergy’s request for rehearing and affirmed the FERC’s earlier rulings that Entergy’s original methodology for allocating energy costs to the opportunity sales was incorrect and, as a result, Entergy Arkansas must make payments to the other Utility operating companies to put them in the same position that they would have been in absent the incorrect allocation. The FERC clarified that interest should be included with the payments. The second order affirmed in part, and reversed in part, the rulings in the ALJ’s August 2013 initial decision regarding the methodology that should be used to calculate the payments Entergy Arkansas is to make to the other Utility operating companies. The FERC affirmed the ALJ’s ruling that a full re-run of intra-system bills should be performed but required that methodology be modified so that the sales have the same priority for purposes of energy allocation as joint account sales. The FERC reversed the ALJ’s decision that any payments by Entergy Arkansas should be reduced by 20%. The FERC also reversed the ALJ’s decision that adjustments to other System Agreement service schedules and excess bandwidth payments should not be taken into account when calculating the payments to be made by Entergy Arkansas. The FERC held that such adjustments and excess bandwidth payments should be taken into account but ordered further proceedings before an ALJ to address whether a cap on any reduction due to bandwidth payments was necessary and to implement the other adjustments to the calculation methodology.
In May 2016, Entergy Services filed a request for rehearing of the FERC’s April 2016 order arguing that payments made by Entergy Arkansas should be reduced as a result of the timing of the LPSC’s approval of certain contracts. Entergy Services also filed a request for clarification and/or rehearing of the FERC’s April 2016 order addressing the ALJ’s August 2013 initial decision. The APSC and the LPSC also filed requests for rehearing of the FERC’s April 2016 order. In September 2017 the FERC issued an order denying the request for rehearing on the issue of whether any payments by Entergy Arkansas to the other Utility operating companies should be reduced due to the timing of the LPSC’s approval of Entergy Arkansas’s wholesale baseload contract with Entergy Louisiana. In November 2017 the FERC issued an order denying all of the remaining requests for rehearing of the April 2016 order. In November 2017, Entergy Services filed a petition for review in the D.C. Circuit of the FERC’s orders in the first two phases of the opportunity sales case. In December 2017 the D.C. Circuit granted Entergy Services’ request to hold the appeal in abeyance pending final resolution of the related proceeding before the FERC. In January 2018 the APSC and the LPSC filed separate petitions for review in the D.C. Circuit, and the D.C. Circuit consolidated the appeals with Entergy Services’ appeal.
The hearing required by the FERC’s April 2016 order was held in May 2017. In July 2017 the ALJ issued an initial decision addressing whether a cap on any reduction due to bandwidth payments was necessary and whether to implement the other adjustments to the calculation methodology. In August 2017 the Utility operating companies, the LPSC, the APSC, and FERC staff filed individual briefs on exceptions challenging various aspects of the initial decision. In September 2017 the Utility operating companies, the LPSC, the APSC, the MPSC, the City Council, and FERC staff filed separate briefs opposing exceptions taken by various parties.
Based on testimony previously submitted in the case and its assessment of the April 2016 FERC orders, in the first quarter 2016, Entergy Arkansas recorded a liability of $87 million, which included interest, for its estimated increased costs and payment to the other Utility operating companies, and a deferred fuel regulatory asset of $75 million. Following its assessment of the course of the proceedings, including the FERC’s denial of rehearing in
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
November 2017 described above, in the fourth quarter 2017, Entergy Arkansas recorded an additional liability of $35 million and a regulatory asset of $31 million.
In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to cap the reduction in Entergy Arkansas’s payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ’s decision that Grand Gulf sales from January through September 2000 should be included in the calculation of Entergy Arkansas’s payment. The FERC affirmed on other grounds the ALJ’s rejection of the LPSC’s claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.
In December 2018, Entergy made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. The December 2018 compliance filing is pending FERC action. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:
| | | | | | | | | | | |
| Total refunds including interest |
| Payment/(Receipt) |
| (In Millions) |
| Principal | Interest | Total |
Entergy Arkansas | $68 | $67 | $135 |
Entergy Louisiana | ($30) | ($29) | ($59) |
Entergy Mississippi | ($18) | ($18) | ($36) |
Entergy New Orleans | ($3) | ($4) | ($7) |
Entergy Texas | ($17) | ($16) | ($33) |
Entergy Arkansas previously recognized a regulatory asset with a balance of $116 million as of December 31, 2018 for a portion of the payments due as a result of this proceeding.
As described above, the FERC’s opportunity sales orders have been appealed to the D.C. Circuit. In February 2020 all of the appeals were consolidated and in April 2020 the D.C. Circuit established a briefing schedule. Briefing was completed in September 2020 and oral argument was heard in December 2020.
In February 2019 the LPSC filed a new complaint relating to two issues that were raised in the opportunity sales proceeding, but that, in its October 2018 order, the FERC held were outside the scope of the proceeding. In March 2019, Entergy Services filed an answer and motion to dismiss the new complaint. In November 2019 the FERC issued an order denying the LPSC’s complaint. The order concluded that the settlement agreement approved by the FERC in December 2015 terminating the System Agreement barred the LPSC’s new complaint. In December 2019 the LPSC requested rehearing of the FERC’s November 2019 order, and in July 2020 the FERC issued an order dismissing the LPSC’s request for rehearing. In September 2020 the LPSC appealed to the D.C. Circuit the FERC’s orders dismissing the new opportunity sales complaint. In November 2020 the D.C. Circuit issued an order establishing that briefing will occur in January 2021 through April 2021.
In May 2019, Entergy Arkansas filed an application and supporting testimony with the APSC requesting approval of a special rider tariff to recover the costs of these payments from its retail customers over a 24-month period. The application requested that the APSC approve the rider to take effect within 30 days or, if suspended by the APSC as allowed by commission rule, approve the rider to take effect in the first billing cycle of the first month occurring 30 days after issuance of the APSC’s order approving the rider. In June 2019 the APSC suspended
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Arkansas’s tariff and granted Entergy Arkansas’s motion asking the APSC to establish the proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC’s October 2018 order and related FERC orders in the opportunity sales proceeding. In January 2020 the APSC adopted a procedural schedule with a hearing in April 2020. In January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed a joint motion seeking to dismiss Entergy Arkansas’s application alleging that the APSC, in a prior proceeding, ruled on the issues addressed in the application and determined that Entergy Arkansas’s requested relief violates the filed rate doctrine and the prohibition against retroactive ratemaking. Entergy Arkansas responded to the joint motion in February 2020 rebutting these arguments, including demonstrating that the claims in this proceeding differ substantially from those the APSC addressed previously and that the payment resulting from a FERC tariff violation for which Entergy Arkansas seeks retail cost recovery in this proceeding differs materially from the refunds resulting from a FERC tariff amendment that the APSC previously rejected on filed rate doctrine and the retroactive ratemaking grounds. In addition, in January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed testimony opposing the recovery by Entergy Arkansas of the opportunity sales payment but also claiming that certain components of the payment should be segregated and refunded to customers. In March 2020, Entergy Arkansas filed rebuttal testimony.
In July 2020 the APSC issued a decision finding that Entergy Arkansas’s application is not in the public interest. The order also directed Entergy Arkansas to refund to its retail customers within 30 days of the order the FERC-determined over-collection of $13.7 million, plus interest, associated with a recalculated bandwidth remedy. In addition to these primary findings, the order also denied the Attorney General’s request for Entergy Arkansas to prepare a compliance filing detailing all of the retail impacts from the opportunity sales and denied a request by the Arkansas Electric Energy Consumers to recalculate all costs using the revised responsibility ratio. Entergy Arkansas filed a motion for judgment ontemporary stay of the pleadings.30-day requirement to allow Entergy Arkansas a reasonable opportunity to seek rehearing of the APSC order, but in July 2020 the APSC denied Entergy Arkansas’s request for a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas’s stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In June 2017July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. In September 2020, Entergy Arkansas filed a complaint in the U. S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments. In October 2020 the APSC filed a motion to dismiss Entergy Arkansas’s complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court scheduled a hearing for February 26, 2021 regarding issues addressed in the pre-trial conference report.
Net Metering Legislation
An Arkansas law was enacted effective July 2019 that, among other things, expands the definition of a “net metering customer” to include two additional types of customers: (1) customers that lease net metering facilities, subject to certain leasing arrangements, and (2) government entities or other entities exempt from state and federal income taxes that enter into a service contract for a net metering facility. The latter provision would allow eligible entities, many of whom are small and large general service customers, to purchase renewable energy directly from third party providers and receive bill credits for these purchases. The APSC was given authority under this law to address certain matters, such as cost shifting and the appropriate compensation for net metered energy and has initiated proceedings for this purpose. Because of the size and number of customers eligible under this new law, there is a risk of loss of load and the shifting of costs to customers. A hearing was held in December 2019, with utilities, cooperatives, the Arkansas Attorney General, industrial customers, and Entergy Arkansas advocating the need for establishment of a reasonable rate structure that takes into account impacts to non-net metering customers; an additional hearing was conducted in February 2020 for purposes of public comment only. The APSC issued an order in June 2020, and in July 2020 several parties, including Entergy Arkansas, filed for rehearing on multiple
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
grounds, including for the reasons that it imposes an unreasonable rate structure and allows facilities to net meter that do not meet the statutory definition of net metering facilities. After granting the rehearing requests, the APSC issued an order in September 2020 largely upholding its June 2020 order. In October 2020, Entergy Arkansas and several other parties filed an appeal of the APSC’s September 2020 order.
Separately, as directed by the APSC general staff, the APSC opened a case managementproceeding to compel utilities to amend their net metering tariffs to incorporate the provisions of the legislation that the APSC general staff considered “black letter law.” Entergy Arkansas, the Arkansas Attorney General, and other intervenors opposed this directive pending the development of the rules for implementation that are being considered in the separate net metering rulemaking docket. Nevertheless, reserving its rights, Entergy Arkansas has complied with the directive to amend its tariffs. Asserting procedural and due process violations, in January 2020, Entergy Arkansas and the Arkansas Attorney General separately appealed certain APSC orders in the proceeding.
COVID-19 Orders
In April 2020, in light of the COVID-19 pandemic, the APSC issued an order settingrequiring utilities, to the extent they had not already done so, to suspend service disconnections during the remaining pendency of the Arkansas Governor’s emergency declaration or until the APSC rescinds the directive. The order also authorizes utilities to establish a trial date in November 2018. Discovery is currently in progress.
Storm Damage Provision
Entergy Mississippi has approvalregulatory asset to record costs resulting from the MPSCsuspension of service disconnections, directs that in future proceedings the APSC will consider whether the request for recovery of these regulatory assets is reasonable and necessary, and requires utilities to collecttrack and report the costs and any savings directly attributable to suspension of disconnects. In May 2020 the APSC approved Entergy Arkansas expanding deferred payment agreements to assist customers during the COVID-19 pandemic. Quarterly reporting began in August 2020 and the APSC ordered additional reporting in October 2020 regarding utilities’ transitional plans for ending the moratorium on service disconnects. In February 2021 the APSC issued an order finding that it is not in the public interest to immediately lift the moratorium on service disconnects, but to announce a storm damage provisiontarget date of $1.75 million per month. If Entergy Mississippi’s accumulated storm damage provision balance exceeds $15 million,May 3, 2021. In March 2021 the collectionAPSC will issue an order either confirming the lifting of the storm damage provision ceases until such time thatmoratorium on service disconnects or extending the accumulated storm damage provision becomes less than $10 million.moratorium. As of April 30, 2016,December 31, 2020, Entergy Mississippi’s storm damage provision balance was less than $10Arkansas recorded a regulatory asset of $10.5 million therefore Entergy Mississippi resumed billingfor costs associated with the monthly storm damage provision effective with June 2016 bills. As of September 30, 2016, however, Entergy Mississippi’s storm damage provision balance again exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with November 2016 bills. As of July 31, 2017, the balance in Entergy Mississippi’s accumulated storm damage provision was again less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with September 2017 bills.COVID-19 pandemic.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation– Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Nuclear Matters
Entergy Arkansas owns and, through an affiliate, operates the ANO 1 and ANO 2 nuclear power plants. Entergy Arkansas is, therefore, subject to the risks related to owning and operating nuclear plants. These include risks related to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, to position Entergy’s nuclear fleet to meet its operational goals; the performance and capacity factors of these nuclear plants including the financial requirements to address emerging issues like stress corrosion cracking of certain materials within the plant systems; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license amendments, and decommissioning; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts and types of insurance commercially available for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident. In the event of an unanticipated early shutdown of either ANO 1 or ANO 2, Entergy Arkansas may be required to
Entergy Mississippi, Inc.Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
file with the APSC a rate mechanism to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. ANO 1’s operating license expires in 2034 and ANO 2’s operating license expires in 2038.
Nuclear Matters
See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.
Environmental Risks
Entergy Mississippi’sArkansas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy MississippiArkansas is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Mississippi’sArkansas’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements that could produce estimates that would have a material impacteffect on the presentation of Entergy Mississippi’sArkansas’s financial position or results of operations.
In the first quarter 2019, Entergy Arkansas recorded a revision to its estimated decommissioning cost liabilities for ANO 1 and ANO 2 as a result of a revised decommissioning cost study. The revised estimates resulted in a $126.2 million increase in its decommissioning cost liabilities, along with corresponding increases in the related asset retirement cost assets that will be depreciated over the remaining lives of the units.
Nuclear Decommissioning Costs
See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Unbilled Revenue
See “Unbilled Revenue” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the unbilled revenue amounts.
Impairment of Long-lived Assets and Trust Fund Investments
See “Impairment of Long-lived Assets and Trust Fund Investments” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Qualified Pension and Other Postretirement Benefits
Entergy Mississippi’sArkansas’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Cost SensitivityCosts and Sensitivities
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
Actuarial Assumption | | Change in Assumption | | Impact on 2021 Qualified Pension Cost | | Impact on 2020 Qualified Projected Benefit Obligation |
| | | | Increase/(Decrease) | | |
Discount rate | | (0.25%) | | $2,406 | | $46,791 |
Rate of return on plan assets | | (0.25%) | | $2,914 | | $— |
Rate of increase in compensation | | 0.25% | | $1,838 | | $8,922 |
|
| | | | | | | | |
Actuarial Assumption | | Change in Assumption | | Impact on 2018 Qualified Pension Cost | | Impact on 2017 Projected Qualified Benefit Obligation |
| | | | Increase/(Decrease) | | |
Discount rate | | (0.25%) | | $874 | |
| $13,479 |
|
Rate of return on plan assets | | (0.25%) | | $867 | |
| $— |
|
Rate of increase in compensation | | 0.25% | | $381 | |
| $1,848 |
|
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
Actuarial Assumption | | Change in Assumption | | Impact on 2021 Postretirement Benefit Cost | | Impact on 2020 Accumulated Postretirement Benefit Obligation |
| | | | Increase/(Decrease) | | |
Discount rate | | (0.25%) | | $174 | | $6,576 |
Health care cost trend | | 0.25% | | $225 | | $4,516 |
|
| | | | | | |
Actuarial Assumption | | Change in Assumption | | Impact on 2018 Postretirement Benefit Cost | | Impact on 2017 Accumulated Postretirement Benefit Obligation |
| | | | Increase/(Decrease) | | |
Discount rate | | (0.25%) | | $184 | | $2,561 |
Health care cost trend | | 0.25% | | $296 | | $2,024 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and FundingEmployer Contributions
Total qualified pension cost for Entergy MississippiArkansas in 20172020 was $8.5 million.$81.7 million, including $21.1 million in settlement costs. Entergy MississippiArkansas anticipates 20182021 qualified pension cost to be $10.8 million. In 2016, Entergy Mississippi refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $3.8$61.6 million. Entergy MississippiArkansas contributed $19.1$60 million to its qualified pension plans in 20172020 and estimates 2018 pension contributions will be approximately $14.9$66.6 million in 2021, although the 20182021 required pension contributions will be known with more certainty when the January 1, 20182021 valuations are completed, which is expected by April 1, 2018.2021.
Total other postretirement health care and life insurance benefit income for Entergy MississippiArkansas in 20172020 was $1$10.1 million. Entergy MississippiArkansas expects 20182021 postretirement health care and life insurance benefit income of approximately $1.5$11.1 million. In 2016, Entergy Mississippi refinedArkansas contributed $2.2 million to its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $770 thousand. In 2017, Entergy Mississippi’s contributions (that is, contributions to the external trusts plus claims payments) were offset by trust claims reimbursements, resultingplans in a net reimbursement of $2 thousand. Entergy Mississippi2020 and estimates that 20182021 contributions will be approximately $110$517 thousand.
Entergy Mississippi, Inc.Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other Contingencies
Federal Healthcare Legislation
See “Qualified Pension and Other Postretirement Benefits -Federal Healthcare LegislationContingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholdersmember and Board of Directors of
Entergy Mississippi, Inc.Arkansas, LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Mississippi, Inc.Arkansas, LLC and Subsidiaries (the “Company”) as of December 31, 20172020 and 2016,2019, the related consolidated statements of income, cash flows and changes in commonmember’s equity (pages 370332 through 374336 and applicable items in pages 5551 through 230)238), for each of the three years in the period ended December 31, 2017,2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172020 and 2016,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2020, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate and Regulatory Matters —Entergy Arkansas, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Arkansas Public Service Commission (the “APSC”), which has jurisdiction with respect to the rates of electric companies in Arkansas, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment;
regulatory assets and liabilities; income taxes; operating revenues; operation and maintenance expense; and depreciation and amortization expense.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the APSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the APSC and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs, including costs related to the Opportunity Sales Proceeding and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the APSC and the FERC, involved especially subjective judgment and specialized knowledge of accounting for rate regulation and the rate setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the APSC and the FERC included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the APSC and the FERC for the Company and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the APSC’s and the FERC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, including the Opportunity Sales Proceeding, we inspected the Company’s filings with the APSC and the FERC, including the annual formula rate plan filing, and considered the filings with the APSC and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
•We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order, including the Opportunity Sales Proceeding, to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 20182021
We have served as the Company’s auditor since 2001.
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| | | | | | | | | | | | |
ENTERGY MISSISSIPPI, INC. |
INCOME STATEMENTS |
| | |
| | For the Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In Thousands) |
| | | | | | |
OPERATING REVENUES | | | | | | |
Electric | |
| $1,198,229 |
| |
| $1,094,649 |
| |
| $1,396,985 |
|
| | | | | | |
OPERATING EXPENSES | | |
| | |
| | |
|
Operation and Maintenance: | | |
| | |
| | |
|
Fuel, fuel-related expenses, and gas purchased for resale | | 185,816 |
| | 95,090 |
| | 291,666 |
|
Purchased power | | 328,463 |
| | 297,902 |
| | 389,950 |
|
Other operation and maintenance | | 243,480 |
| | 250,443 |
| | 261,255 |
|
Taxes other than income taxes | | 95,051 |
| | 94,482 |
| | 94,152 |
|
Depreciation and amortization | | 143,479 |
| | 136,214 |
| | 129,029 |
|
Other regulatory charges (credits) - net | | (19,134 | ) | | (3,721 | ) | | 19,027 |
|
TOTAL | | 977,155 |
| | 870,410 |
| | 1,185,079 |
|
| | | | | | |
OPERATING INCOME | | 221,074 |
| | 224,239 |
| | 211,906 |
|
| | | | | | |
OTHER INCOME | | |
| | |
| | |
|
Allowance for equity funds used during construction | | 9,667 |
| | 5,801 |
| | 3,095 |
|
Interest and investment income | | 85 |
| | 656 |
| | 195 |
|
Miscellaneous - net | | 510 |
| | (3,531 | ) | | (4,418 | ) |
TOTAL | | 10,262 |
| | 2,926 |
| | (1,128 | ) |
| | | | | | |
INTEREST EXPENSE | | |
| | |
| | |
|
Interest expense | | 51,260 |
| | 57,114 |
| | 57,842 |
|
Allowance for borrowed funds used during construction | | (3,875 | ) | | (2,987 | ) | | (1,644 | ) |
TOTAL | | 47,385 |
| | 54,127 |
| | 56,198 |
|
| | | | | | |
INCOME BEFORE INCOME TAXES | | 183,951 |
| | 173,038 |
| | 154,580 |
|
| | | | | | |
Income taxes | | 73,919 |
| | 63,854 |
| | 61,872 |
|
| | | | | | |
NET INCOME | | 110,032 |
| | 109,184 |
| | 92,708 |
|
| | | |
|
| | |
Preferred dividend requirements and other | | 953 |
| | 2,443 |
| | 2,828 |
|
| | | | | | |
EARNINGS APPLICABLE TO COMMON STOCK | |
| $109,079 |
| |
| $106,741 |
| |
| $89,880 |
|
| | | | | | |
See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
CONSOLIDATED INCOME STATEMENTS |
| | |
| | For the Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | (In Thousands) |
| | | | | | |
OPERATING REVENUES | | | | | | |
Electric | | $2,084,494 | | | $2,259,594 | | | $2,060,643 | |
| | | | | | |
OPERATING EXPENSES | | | | | | |
Operation and Maintenance: | | | | | | |
Fuel, fuel-related expenses, and gas purchased for resale | | 271,896 | | | 458,907 | | | 517,245 | |
Purchased power | | 187,690 | | | 204,640 | | | 252,390 | |
Nuclear refueling outage expenses | | 55,737 | | | 68,769 | | | 77,915 | |
Other operation and maintenance | | 669,518 | | | 720,217 | | | 724,831 | |
Decommissioning | | 73,319 | | | 68,030 | | | 60,420 | |
Taxes other than income taxes | | 121,057 | | | 115,869 | | | 104,771 | |
Depreciation and amortization | | 338,029 | | | 307,351 | | | 292,649 | |
Other regulatory credits - net | | (35,310) | | | (11,186) | | | (14,807) | |
TOTAL | | 1,681,936 | | | 1,932,597 | | | 2,015,414 | |
| | | | | | |
OPERATING INCOME | | 402,558 | | | 326,997 | | | 45,229 | |
| | | | | | |
OTHER INCOME | | | | | | |
Allowance for equity funds used during construction | | 15,019 | | | 15,499 | | | 16,557 | |
Interest and investment income | | 35,579 | | | 26,020 | | | 25,406 | |
Miscellaneous - net | | (21,908) | | | (18,566) | | | (14,874) | |
TOTAL | | 28,690 | | | 22,953 | | | 27,089 | |
| | | | | | |
INTEREST EXPENSE | | | | | | |
Interest expense | | 144,834 | | | 140,087 | | | 124,459 | |
Allowance for borrowed funds used during construction | | (6,595) | | | (6,332) | | | (7,781) | |
TOTAL | | 138,239 | | | 133,755 | | | 116,678 | |
| | | | | | |
INCOME (LOSS) BEFORE INCOME TAXES | | 293,009 | | | 216,195 | | | (44,360) | |
| | | | | | |
Income taxes | | 47,777 | | | (46,769) | | | (297,067) | |
| | | | | | |
NET INCOME | | 245,232 | | | 262,964 | | | 252,707 | |
| | | | | | |
Preferred dividend requirements | | 0 | | | 0 | | | 1,249 | |
| | | | | | |
EARNINGS APPLICABLE TO COMMON EQUITY | | $245,232 | | | $262,964 | | | $251,458 | |
| | | | | | |
See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
ENTERGY MISSISSIPPI, INC. |
STATEMENTS OF CASH FLOWS |
| | |
| | For the Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In Thousands) |
| | | | | | |
OPERATING ACTIVITIES | | | | | | |
Net income | |
| $110,032 |
| |
| $109,184 |
| |
| $92,708 |
|
Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
Depreciation and amortization | | 143,479 |
| | 136,214 |
| | 129,029 |
|
Deferred income taxes, investment tax credits, and non-current taxes accrued | | 84,816 |
| | 60,986 |
| | 18,673 |
|
Changes in assets and liabilities: | | |
| | |
| | |
|
Receivables | | (29,528 | ) | | (28,819 | ) | | 50,199 |
|
Fuel inventory | | 5,266 |
| | 401 |
| | (8,537 | ) |
Accounts payable | | 3,595 |
| | 33,733 |
| | (26,682 | ) |
Taxes accrued | | 18,803 |
| | 20,579 |
| | (10,104 | ) |
Interest accrued | | 1,248 |
| | 822 |
| | (2,341 | ) |
Deferred fuel costs | | (25,487 | ) | | (114,711 | ) | | 105,560 |
|
Other working capital accounts | | 5,115 |
| | (5,222 | ) | | (663 | ) |
Provisions for estimated losses | | (9,676 | ) | | 6,378 |
| | (2,080 | ) |
Other regulatory assets | | (17,412 | ) | | (3,626 | ) | | 39,582 |
|
Other regulatory liabilities | | 405,395 |
| | (2,986 | ) | | 9,172 |
|
Deferred tax rate change recognized as regulatory liability/asset | | (452,429 | ) | | — |
| | — |
|
Pension and other postretirement liabilities | | (8,055 | ) | | (10,648 | ) | | (14,939 | ) |
Other assets and liabilities | | (8,577 | ) | | 9,995 |
| | (7,298 | ) |
Net cash flow provided by operating activities | | 226,585 |
| | 212,280 |
| | 372,279 |
|
INVESTING ACTIVITIES | | |
| | |
| | |
|
Construction expenditures | | (427,616 | ) | | (310,356 | ) | | (235,894 | ) |
Allowance for equity funds used during construction | | 9,667 |
| | 5,801 |
| | 3,095 |
|
Insurance proceeds | | — |
| | — |
| | 12,932 |
|
Changes in money pool receivable - net | | 8,962 |
| | 15,335 |
| | (25,286 | ) |
Payment for purchase of assets | | (6,958 | ) | | — |
| | — |
|
Other | | (1,281 | ) | | (224 | ) | | 26 |
|
Net cash flow used in investing activities | | (417,226 | ) | | (289,444 | ) | | (245,127 | ) |
FINANCING ACTIVITIES | | |
| | |
| | |
|
Proceeds from the issuance of long-term debt | | 148,185 |
| | 623,812 |
| | — |
|
Retirement of long-term debt | | — |
| | (562,400 | ) | | — |
|
Redemption of preferred stock | | — |
| | (30,000 | ) | | — |
|
Dividends paid: | | |
| | |
| | |
|
Common stock | | (26,000 | ) | | (24,000 | ) | | (40,000 | ) |
Preferred stock | | (953 | ) | | (2,755 | ) | | (2,828 | ) |
Other | | (1,329 | ) | | 3,736 |
| | (352 | ) |
Net cash flow provided by (used in) financing activities | | 119,903 |
| | 8,393 |
| | (43,180 | ) |
Net increase (decrease) in cash and cash equivalents | | (70,738 | ) | | (68,771 | ) | | 83,972 |
|
Cash and cash equivalents at beginning of period | | 76,834 |
| | 145,605 |
| | 61,633 |
|
Cash and cash equivalents at end of period | |
| $6,096 |
| |
| $76,834 |
| |
| $145,605 |
|
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | |
| | |
|
Cash paid (received) during the period for: | | |
| | |
| | |
|
Interest - net of amount capitalized | |
| $47,631 |
| |
| $53,693 |
| |
| $57,576 |
|
Income taxes | |
| ($25,043 | ) | |
| ($12,487 | ) | |
| $61,333 |
|
See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | For the Years Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | (In Thousands) |
OPERATING ACTIVITIES | | | | | | |
Net income | | $245,232 | | | $262,964 | | | $252,707 | |
Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 490,457 | | | 465,299 | | | 443,698 | |
Deferred income taxes, investment tax credits, and non-current taxes accrued | | 87,019 | | | 94,368 | | | 129,524 | |
Changes in assets and liabilities: | | | | | | |
Receivables | | (24,507) | | | (58,077) | | | 4,294 | |
Fuel inventory | | (10,066) | | | (10,597) | | | 6,210 | |
Accounts payable | | (22,773) | | | 3,059 | | | (126,405) | |
Prepaid taxes and taxes accrued | | 6 | | | 24,942 | | | 9,568 | |
Interest accrued | | (43) | | | 3,895 | | | 678 | |
Deferred fuel costs | | (1,186) | | | 72,560 | | | 43,869 | |
Other working capital accounts | | (11,061) | | | 18,783 | | | (30,118) | |
Provisions for estimated losses | | 6,289 | | | 14,901 | | | 14,250 | |
Other regulatory assets | | (165,534) | | | (131,873) | | | 32,460 | |
Other regulatory liabilities | | 106,878 | | | 39,293 | | | (341,682) | |
| | | | | | |
Pension and other postretirement liabilities | | 42,576 | | | 5,831 | | | (40,157) | |
Other assets and liabilities | | (83,469) | | | (127,582) | | | (187,071) | |
Net cash flow provided by operating activities | | 659,818 | | | 677,766 | | | 211,825 | |
INVESTING ACTIVITIES | | | | | | |
Construction expenditures | | (775,595) | | | (641,525) | | | (660,044) | |
Allowance for equity funds used during construction | | 15,019 | | | 15,306 | | | 17,013 | |
Nuclear fuel purchases | | (100,678) | | | (54,344) | | | (99,417) | |
Proceeds from sale of nuclear fuel | | 30,638 | | | 22,782 | | | 54,810 | |
| | | | | | |
Proceeds from nuclear decommissioning trust fund sales | | 321,360 | | | 317,377 | | | 300,801 | |
Investment in nuclear decommissioning trust funds | | (336,392) | | | (336,519) | | | (315,163) | |
Payment for purchase of assets | | (5,988) | | | 0 | | | 0 | |
Changes in money pool receivable - net | | (3,110) | | | 0 | | | 0 | |
| | | | | | |
| | | | | | |
| | | | | | |
Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | 55,001 | | | 0 | | | 0 | |
| | | | | | |
Insurance proceeds | | 0 | | | 0 | | | 14,790 | |
Other | | 4,036 | | | 630 | | | (1,517) | |
Net cash flow used in investing activities | | (795,709) | | | (676,293) | | | (688,727) | |
FINANCING ACTIVITIES | | | | | | |
Proceeds from the issuance of long-term debt | | 1,071,121 | | | 834,038 | | | 958,434 | |
Retirement of long-term debt | | (632,175) | | | (548,952) | | | (690,488) | |
Capital contribution from parent | | 0 | | | 0 | | | 350,000 | |
Redemption of preferred stock | | 0 | | | 0 | | | (32,660) | |
Change in money pool payable - net | | (21,634) | | | (161,104) | | | 16,601 | |
Changes in short-term borrowings - net | | 0 | | | 0 | | | (49,974) | |
Distributions/dividends paid: | | | | | | |
Common equity | | (95,000) | | | (115,000) | | | (91,751) | |
Preferred stock | | 0 | | | 0 | | | (1,606) | |
Other | | 2,188 | | | (7,055) | | | 12,249 | |
Net cash flow provided by financing activities | | 324,500 | | | 1,927 | | | 470,805 | |
Net increase (decrease) in cash and cash equivalents | | 188,609 | | | 3,400 | | | (6,097) | |
Cash and cash equivalents at beginning of period | | 3,519 | | | 119 | | | 6,216 | |
Cash and cash equivalents at end of period | | $192,128 | | | $3,519 | | | $119 | |
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
Cash paid (received) during the period for: | | | | | | |
Interest - net of amount capitalized | | $140,735 | | | $131,134 | | | $118,731 | |
Income taxes | | ($21,971) | | | ($33,989) | | | $44,393 | |
See Notes to Financial Statements. | | | | | | |
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ENTERGY MISSISSIPPI, INC. |
BALANCE SHEETS |
ASSETS |
| | |
| | December 31, |
| | 2017 | | 2016 |
| | (In Thousands) |
| | | | |
CURRENT ASSETS | | | | |
Cash and cash equivalents: | | | | |
Cash | |
| $1,607 |
| |
| $16 |
|
Temporary cash investments | | 4,489 |
| | 76,818 |
|
Total cash and cash equivalents | | 6,096 |
| | 76,834 |
|
Accounts receivable: | | |
| | |
|
Customer | | 72,039 |
| | 51,218 |
|
Allowance for doubtful accounts | | (574 | ) | | (549 | ) |
Associated companies | | 45,081 |
| | 45,973 |
|
Other | | 9,738 |
| | 12,006 |
|
Accrued unbilled revenues | | 54,256 |
| | 51,327 |
|
Total accounts receivable | | 180,540 |
| | 159,975 |
|
Deferred fuel costs | | 32,444 |
| | 6,957 |
|
Fuel inventory - at average cost | | 45,606 |
| | 50,872 |
|
Materials and supplies - at average cost | | 42,571 |
| | 41,146 |
|
Prepayments and other | | 7,041 |
| | 8,873 |
|
TOTAL | | 314,298 |
| | 344,657 |
|
| | | | |
OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
Non-utility property - at cost (less accumulated depreciation) | | 4,592 |
| | 4,608 |
|
Escrow accounts | | 31,969 |
| | 31,783 |
|
TOTAL | | 36,561 |
| | 36,391 |
|
| | | | |
UTILITY PLANT | | |
| | |
|
Electric | | 4,660,297 |
| | 4,321,214 |
|
Property under capital lease | | 125 |
| | 1,590 |
|
Construction work in progress | | 149,367 |
| | 118,182 |
|
TOTAL UTILITY PLANT | | 4,809,789 |
| | 4,440,986 |
|
Less - accumulated depreciation and amortization | | 1,681,306 |
| | 1,602,711 |
|
UTILITY PLANT - NET | | 3,128,483 |
| | 2,838,275 |
|
| | | | |
DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
Regulatory assets: | | |
| | |
|
Regulatory asset for income taxes - net | | — |
| | 38,284 |
|
Other regulatory assets | | 397,909 |
| | 342,213 |
|
Other | | 2,124 |
| | 2,320 |
|
TOTAL | | 400,033 |
| | 382,817 |
|
| | | | |
TOTAL ASSETS | |
| $3,879,375 |
| |
| $3,602,140 |
|
| | | | |
See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | |
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
CONSOLIDATED BALANCE SHEETS |
ASSETS |
| | |
| | December 31, |
| | 2020 | | 2019 |
| | (In Thousands) |
| | | | |
CURRENT ASSETS | | | | |
Cash and cash equivalents: | | | | |
Cash | | $24,108 | | | $3,519 | |
Temporary cash investments | | 168,020 | | | 0 | |
Total cash and cash equivalents | | 192,128 | | | 3,519 | |
Securitization recovery trust account | | 0 | | | 4,036 | |
Accounts receivable: | | | | |
Customer | | 183,719 | | | 117,679 | |
Allowance for doubtful accounts | | (18,334) | | | (1,169) | |
Associated companies | | 34,216 | | | 29,178 | |
Other | | 35,845 | | | 117,653 | |
Accrued unbilled revenues | | 109,000 | | | 108,489 | |
Total accounts receivable | | 344,446 | | | 371,830 | |
| | | | |
| | | | |
Fuel inventory - at average cost | | 43,811 | | | 33,745 | |
Materials and supplies - at average cost | | 237,640 | | | 211,320 | |
Deferred nuclear refueling outage costs | | 32,692 | | | 48,875 | |
| | | | |
| | | | |
Prepayments and other | | 13,296 | | | 14,096 | |
| | | | |
TOTAL | | 864,013 | | | 687,421 | |
| | | | |
OTHER PROPERTY AND INVESTMENTS | | | | |
Decommissioning trust funds | | 1,273,921 | | | 1,101,283 | |
| | | | |
Other | | 341 | | | 345 | |
TOTAL | | 1,274,262 | | | 1,101,628 | |
| | | | |
UTILITY PLANT | | | | |
Electric | | 12,905,322 | | | 12,293,483 | |
| | | | |
Construction work in progress | | 234,213 | | | 197,775 | |
Nuclear fuel | | 163,044 | | | 195,547 | |
TOTAL UTILITY PLANT | | 13,302,579 | | | 12,686,805 | |
Less - accumulated depreciation and amortization | | 5,255,355 | | | 5,019,826 | |
UTILITY PLANT - NET | | 8,047,224 | | | 7,666,979 | |
| | | | |
DEFERRED DEBITS AND OTHER ASSETS | | | | |
Regulatory assets: | | | | |
| | | | |
Other regulatory assets (includes securitization property of $0 as of December 31, 2020 and $1,706 as of December 31, 2019) | | 1,832,384 | | | 1,666,850 | |
Deferred fuel costs | | 68,220 | | | 67,690 | |
Other | | 14,028 | | | 15,065 | |
TOTAL | | 1,914,632 | | | 1,749,605 | |
| | | | |
TOTAL ASSETS | | $12,100,131 | | | $11,205,633 | |
| | | | |
See Notes to Financial Statements. | | | | |
| | ENTERGY MISSISSIPPI, INC. | |
BALANCE SHEETS | |
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES | | ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
CONSOLIDATED BALANCE SHEETS | | CONSOLIDATED BALANCE SHEETS |
LIABILITIES AND EQUITY | LIABILITIES AND EQUITY | LIABILITIES AND EQUITY |
| | | | |
| | December 31, | | | December 31, |
| | 2017 | | 2016 | | | 2020 | | 2019 |
| | (In Thousands) | | | (In Thousands) |
| | | | | |
CURRENT LIABILITIES | | | | | CURRENT LIABILITIES | | | | |
Currently maturing long-term debt | | Currently maturing long-term debt | | $485,000 | | | $0 | |
| Accounts payable: | | |
| | |
| Accounts payable: | | | | |
Associated companies | |
| $55,689 |
| |
| $43,647 |
| Associated companies | | 59,448 | | | 111,785 | |
Other | | 77,326 |
| | 80,227 |
| Other | | 208,591 | | | 202,201 | |
Customer deposits | | 83,654 |
| | 84,112 |
| Customer deposits | | 98,506 | | | 101,411 | |
Taxes accrued | | 82,843 |
| | 64,040 |
| Taxes accrued | | 81,837 | | | 81,831 | |
| Interest accrued | | 22,901 |
| | 21,653 |
| Interest accrued | | 22,745 | | | 22,788 | |
Deferred fuel costs | | Deferred fuel costs | | 53,065 | | | 53,721 | |
Current portion of unprotected excess accumulated deferred income taxes | | Current portion of unprotected excess accumulated deferred income taxes | | 0 | | | 9,296 | |
Other | | 12,785 |
| | 9,554 |
| Other | | 40,628 | | | 38,760 | |
TOTAL | | 335,198 |
| | 303,233 |
| TOTAL | | 1,049,820 | | | 621,793 | |
| | | | | | | | |
NON-CURRENT LIABILITIES | | |
| | |
| NON-CURRENT LIABILITIES | | | | |
Accumulated deferred income taxes and taxes accrued | | 488,806 |
| | 861,331 |
| Accumulated deferred income taxes and taxes accrued | | 1,286,123 | | | 1,183,126 | |
Accumulated deferred investment tax credits | | 8,867 |
| | 8,667 |
| Accumulated deferred investment tax credits | | 30,500 | | | 31,701 | |
Regulatory liability for income taxes - net | | 411,011 |
| | — |
| Regulatory liability for income taxes - net | | 467,031 | | | 478,174 | |
Asset retirement cost liabilities | | 9,219 |
| | 8,722 |
| |
Other regulatory liabilities | | Other regulatory liabilities | | 686,872 | | | 559,555 | |
Decommissioning | | Decommissioning | | 1,314,160 | | | 1,242,616 | |
Accumulated provisions | | 44,764 |
| | 54,440 |
| Accumulated provisions | | 70,169 | | | 63,880 | |
Pension and other postretirement liabilities | | 101,498 |
| | 109,551 |
| Pension and other postretirement liabilities | | 361,682 | | | 319,075 | |
Long-term debt | | 1,270,122 |
| | 1,120,916 |
| |
Long-term debt (includes securitization bonds of $0 as of December 31, 2020 and $6,772 as of December 31, 2019) | | Long-term debt (includes securitization bonds of $0 as of December 31, 2020 and $6,772 as of December 31, 2019) | | 3,482,507 | | | 3,517,208 | |
Other | | 11,639 |
| | 20,108 |
| Other | | 75,098 | | | 62,568 | |
TOTAL | | 2,345,926 |
| | 2,183,735 |
| TOTAL | | 7,774,142 | | | 7,457,903 | |
| | | | | | | | |
Commitments and Contingencies | |
|
| |
|
| Commitments and Contingencies | | 0 | | 0 |
| | | | | |
Preferred stock without sinking fund | | 20,381 |
| | 20,381 |
| |
| | | | | |
COMMON EQUITY | | |
| | |
| |
Common stock, no par value, authorized 12,000,000 shares; issued and outstanding 8,666,357 shares in 2017 and 2016 | | 199,326 |
| | 199,326 |
| |
Capital stock expense and other | | 167 |
| | 167 |
| |
Retained earnings | | 978,377 |
| | 895,298 |
| |
| EQUITY | | EQUITY | | | | |
Member's equity | | Member's equity | | 3,276,169 | | | 3,125,937 | |
TOTAL | | 1,177,870 |
| | 1,094,791 |
| TOTAL | | 3,276,169 | | | 3,125,937 | |
| | | | | | | | |
TOTAL LIABILITIES AND EQUITY | |
| $3,879,375 |
| |
| $3,602,140 |
| TOTAL LIABILITIES AND EQUITY | | $12,100,131 | | | $11,205,633 | |
| | | | | | | | |
See Notes to Financial Statements. | | |
| | |
| See Notes to Financial Statements. | | | | |
Decreases in Entergy New Orleans’s receivable from the money pool are a source of cash flow, and Entergy New Orleans’s receivable from the money pool decreased $1.6$5.2 million in 20162020 compared to increasing $15.4decreasing $16.8 million in 2015.2019. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowingsborrowings.
(a) Calculation excludes the securitization bonds, which are non-recourse to Entergy New Orleans.
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, long-term debt, including the currently maturing portion, and the long-term payable due to Entergy Louisiana.an associated company. Capital consists of debt preferred stock without sinking fund, and common equity. Net capital consists of capital less cash and cash equivalents. Entergy New Orleans uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy New Orleans’s financial condition because the securitization bonds are non-recourse to Entergy New Orleans, as more fully described in Note 5 to the financial statements. Entergy New Orleans also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy New Orleans’s financial condition because net debt indicates Entergy New Orleans’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy New Orleans seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend,distribution, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy New Orleans may issue incremental debt or reduce dividends,distributions, or both, to maintain its targeted capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reducing dividends,distributions, Entergy New Orleans may receive equity contributions to maintain the targetedits capital structure.
Following are the amounts of Entergy New Orleans’s planned construction and other capital investments.
Following are the amounts of Entergy New Orleans’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy New Orleans includes specific investments such as the New Orleans Power Station discussed below; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including investment to support advanced metering;meters and related investments; resource planning, including potential generation and renewables projects; system improvements; software and security; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring,
changes in project plans, and the ability to access capital. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the financial statements.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy New Orleans pays distributions from its earnings at a percentage determined monthly.
In September 2016, Entergy New Orleans submitted to the City Council a request for authorization for Entergy New Orleans to proceed with annual incremental capital funding of $12.5 million for its gas infrastructure rebuild plan, which would replace of all of Entergy New Orleans’s low pressure cast iron, steel, and vintage plastic pipe over a ten-year period commencing in 2017. Entergy New Orleans also proposed that recovery of the investment to fund its gas infrastructure replacement plan be determined in connection with its next base rate case, which is anticipated to be filed in 2018.case. The City Council has authorized Entergy New Orleans to proceed with its replacement plans at the requested pace until such time that rates resulting from the anticipated 2018 rate case are implemented (approximately 13 months after filing). As a result of the anticipated 2018 rate case, the City Council may establish new overall gas base rates to allow Entergy New Orleans to continue to recover these replacement costs. The City Council hasand established a schedule for proceedings in advance of the rate case intended to provide an opportunity for evaluation of the gas infrastructure replacement plan that would best serve the public interest and the effect on customers of the approval of any such plan. In the course of that proceeding, the City Council’s advisors submitted pre-filed testimony recommending that Entergy New Orleans be allowed to continue with its condition-based approach to gas pipeline replacement to replace approximately 238 miles of low pressure pipe at a rate of approximately 25 miles per year. The City Council’s advisors also recommended that Entergy New Orleans be required to adhere to certain reporting requirements and recognized the need to address the sustained level of investment in gas infrastructure on customer bills. In September 2017, Entergy New Orleans filed rebuttal testimony suggesting that its recovery of future investment and customer effects would be addressed in the rate case that Entergy New Orleans was required to file in July 2018. The procedural schedule was suspended in order to allow for resolution in the rate case proceeding. As a result of the rate case, the City Council approved the planned gas rebuild expenditures through 2019, but rejected Entergy New Orleans’s proposed gas infrastructure rider. In April 2020, Entergy New Orleans submitted its gas infrastructure rebuild plan to the City Council, which maintained the previously proposed timeline and cost estimates, but included measures to spread out the cost impact to customers of the program.
Entergy New Orleans may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest rates are favorable.
See Note 4 to the financial statements for a description of the money pool.
Entergy New Orleans has a credit facility in the amount of $25 million scheduled to expire in November 2018.2021. The credit facility allows Entergy New Orleans to issueincludes fronting commitments for the issuance of letters of credit against $10 million of the borrowing capacity of the facility. As of December 31, 2017,2020, there were no cash borrowings and aan $0.8 million letter of credit was outstanding under the facility. In addition, Entergy New Orleans is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2017,2020, a $1.4$1 million letter of credit was outstanding under Entergy New Orleans’s letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
The rates that Entergy New Orleans charges for electricity and natural gas significantly influence its financial position, results of operations, and liquidity. Entergy New Orleans is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the City Council, is primarily responsible for approval of the rates charged to customers.
Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.
Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
In July 2016 the City Council approved the issuance of a show cause order, which directed Entergy New Orleans to make a filing on or before September 29, 2016 to demonstrate the reasonableness of its actions or positions with regard to certain issues in four existing dockets that relate to Entergy New Orleans’s: (i) storm hardening proposal; (ii) 2015 integrated resource plan; (iii) gas infrastructure rebuild proposal; and (iv) proposed sizing of the New Orleans Power Station and its community outreach prior to the filing. In September 2016, Entergy New Orleans filed its response to the City Council’s show cause order. The City Council has not established any further procedural schedule with regard to this proceeding.
The preparation of Entergy New Orleans’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements that could produce estimates that would have a material impact on the presentation of Entergy New Orleans’s financial position or results of operations.
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
Each fluctuation above assumes that the other components of the calculation are held constant.
Total postretirement health care and life insurance benefit income for Entergy New Orleans in 20172020 was $2.5$4.9 million. Entergy New Orleans expects 20182021 postretirement health care and life insurance benefit income of approximately $3.7$6.4 million. In 2016, Entergy New Orleans refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $548 thousand. Entergy New Orleans contributed $3.7 million$641 thousand to its other postretirement plans in 20172020 and estimates 20182021 contributions will be approximately $3.7 million.$175 thousand.
We have audited the accompanying consolidated balance sheets of Entergy New Orleans, LLC and Subsidiaries (the “Company”) as of December 31, 20172020 and 2016,2019, the related consolidated statements of income, cash flows, and changes in commonmember’s equity (pages 392402 through 396406 and applicable items in pages 5551 through 230)238), for each of the three years in the period ended December 31, 2017,2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172020 and 2016,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2020, in conformity with accounting principles generally accepted in the United States of America.
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
We have served as the Company’s auditor since 2001.