The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.
The following unaudited notes to the condensed financial statements are a combined presentation; however, information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf and each Registrant makes no representation as to information related to the other Registrants. The list below indicates the Registrants to which each footnote applies.
The condensed quarterly financial statements of each Registrant included herein have been prepared by such Registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 20192020 have been derived from the audited financial statements of each Registrant. In the opinion of each Registrant's management, the information regarding such Registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended June 30, 2020March 31, 2021 and 2019.2020. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each Registrant believes that the disclosures regarding such Registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy and other factors, including the impacts of the COVID-19 pandemic, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.
Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the overall results of operations, financial position, or cash flows of any Registrant.
| | | | | | |
| Goodwill | |
| (in millions) |
Southern Company | $ | 5,280 | | |
Southern Company Gas: | | |
Gas distribution operations | $ | 4,034 | | |
Gas marketing services | 981 | | |
Southern Company Gas total | $ | 5,015 | | |
Goodwill is not amortized but is subject to an annual impairment test in the fourth quarter of the year and on an interim basis as events and changes in circumstances occur, including, but not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. The continued COVID-19 pandemic and related responses continue to disrupt supply chains and capital markets, reduce labor availability and productivity, and reduce economic activity. These effects could have a variety of adverse impacts on Southern Company and its subsidiaries, including the $263 million of goodwill recorded at PowerSecure. If the impact of the COVID-19 pandemic becomes significant to the operating results of PowerSecure and its businesses, a portion of the associated goodwill may become impaired. The ultimate outcome of this matter cannot be determined at this time.occur.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Other intangible assets were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| At March 31, 2021 | | At December 31, 2020 |
| Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net | | Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net |
| (in millions) | | (in millions) |
Southern Company | | | | | | | |
Other intangible assets subject to amortization: | | | | | | | |
Customer relationships | $ | 212 | | $ | (139) | | $ | 73 | | | $ | 212 | | $ | (135) | | $ | 77 | |
Trade names | 64 | | (33) | | 31 | | | 64 | | (31) | | 33 | |
Storage and transportation contracts | 64 | | (64) | | 0 | | | 64 | | (64) | | 0 | |
PPA fair value adjustments | 390 | | (94) | | 296 | | | 390 | | (89) | | 301 | |
Other | 11 | | (9) | | 2 | | | 10 | | (9) | | 1 | |
Total other intangible assets subject to amortization | $ | 741 | | $ | (339) | | $ | 402 | | | $ | 740 | | $ | (328) | | $ | 412 | |
Other intangible assets not subject to amortization: | | | | | | | |
Federal Communications Commission licenses | 75 | | — | | 75 | | | 75 | | — | | 75 | |
Total other intangible assets | $ | 816 | | $ | (339) | | $ | 477 | | | $ | 815 | | $ | (328) | | $ | 487 | |
| | | | | | | |
Southern Power | | | | | | | |
Other intangible assets subject to amortization: | | | | | | | |
PPA fair value adjustments | $ | 390 | | $ | (94) | | $ | 296 | | | $ | 390 | | $ | (89) | | $ | 301 | |
| | | | | | | |
Southern Company Gas | | | | | | | |
Other intangible assets subject to amortization: | | | | | | | |
Gas marketing services | | | | | | | |
Customer relationships | $ | 156 | | $ | (122) | | $ | 34 | | | $ | 156 | | $ | (119) | | $ | 37 | |
Trade names | 26 | | (13) | | 13 | | | 26 | | (12) | | 14 | |
Wholesale gas services | | | | | | | |
Storage and transportation contracts | 64 | | (64) | | 0 | | | 64 | | (64) | | 0 | |
Total other intangible assets subject to amortization | $ | 246 | | $ | (199) | | $ | 47 | | | $ | 246 | | $ | (195) | | $ | 51 | |
|
| | | | | | | | | | | | | | | | | | | |
| At June 30, 2020 | | At December 31, 2019 |
| Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net | | Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net |
| (in millions) | | (in millions) |
Southern Company | | | | | | | |
Other intangible assets subject to amortization: | | | | | | | |
Customer relationships | $ | 212 |
| $ | (126 | ) | $ | 86 |
| | $ | 212 |
| $ | (116 | ) | $ | 96 |
|
Trade names | 64 |
| (28 | ) | 36 |
| | 64 |
| (25 | ) | 39 |
|
Storage and transportation contracts | 64 |
| (63 | ) | 1 |
| | 64 |
| (62 | ) | 2 |
|
PPA fair value adjustments | 390 |
| (79 | ) | 311 |
| | 390 |
| (69 | ) | 321 |
|
Other | 10 |
| (8 | ) | 2 |
| | 11 |
| (8 | ) | 3 |
|
Total other intangible assets subject to amortization | $ | 740 |
| $ | (304 | ) | $ | 436 |
|
| $ | 741 |
| $ | (280 | ) | $ | 461 |
|
Other intangible assets not subject to amortization: | | | | | | | |
Federal Communications Commission licenses | 75 |
| — |
| 75 |
| | 75 |
| — |
| 75 |
|
Total other intangible assets | $ | 815 |
| $ | (304 | ) | $ | 511 |
| | $ | 816 |
| $ | (280 | ) | $ | 536 |
|
| | | | | | | |
Southern Power | | | | | | | |
Other intangible assets subject to amortization: | | | | | | | |
PPA fair value adjustments | $ | 390 |
| $ | (79 | ) | $ | 311 |
| | $ | 390 |
| $ | (69 | ) | $ | 321 |
|
| | | | | | | |
Southern Company Gas | | | | | | | |
Other intangible assets subject to amortization: | | | | | | | |
Gas marketing services | | | | | | | |
Customer relationships | $ | 156 |
| $ | (112 | ) | $ | 44 |
| | $ | 156 |
| $ | (104 | ) | $ | 52 |
|
Trade names | 26 |
| (11 | ) | 15 |
| | 26 |
| (10 | ) | 16 |
|
Wholesale gas services | | | | | | | |
Storage and transportation contracts | 64 |
| (63 | ) | 1 |
| | 64 |
| (62 | ) | 2 |
|
Total other intangible assets subject to amortization | $ | 246 |
| $ | (186 | ) | $ | 60 |
| | $ | 246 |
| $ | (176 | ) | $ | 70 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Amortization associated with other intangible assets was as follows:
|
| | | | | | |
| Three Months Ended | Six Months Ended |
| June 30, 2020 |
| (in millions) |
Southern Company(a) | $ | 13 |
| $ | 25 |
|
Southern Power(b) | $ | 5 |
| $ | 10 |
|
Southern Company Gas |
|
| |
Gas marketing services | $ | 5 |
| $ | 9 |
|
Wholesale gas services(b) | — |
| 1 |
|
Southern Company Gas total | $ | 5 |
| $ | 10 |
|
| | | | | | |
(a) | Includes $5 million and $11 million for the three and six months ended June 30, 2020, respectively, recorded as a reduction to operating revenues. | Three Months Ended |
| | March 31, 2021 |
| | (in millions) |
Southern Company(a) | | $ | 11 | |
Southern Power(b) | Recorded as a reduction to operating revenues. | 5 | |
Southern Company Gas(c) | | 4 | |
(a)Includes $5 million recorded as a reduction to operating revenues.
(b)Recorded as a reduction to operating revenues.
(c)Relates to gas marketing services.
Restricted Cash
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amountsamount shown in the condensed statements of cash flows for the Registrants that had restricted cash at June 30, 2020March 31, 2021 and/or December 31, 2019:2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Southern Company | | Southern Power | | Southern Company Gas |
| March 31, 2021 | | December 31, 2020 | | March 31, 2021 | | March 31, 2021 | December 31, 2020 |
| (in millions) | | (in millions) | | (in millions) |
Cash and cash equivalents | $ | 1,770 | | | $ | 1,065 | | | $ | 314 | | | $ | 309 | | $ | 17 | |
Restricted cash(a): | | | | | | | | |
Other current assets | 2 | | | 2 | | | 0 | | | 2 | | 2 | |
Other deferred charges and assets | 29 | | | 0 | | | 29 | | | 0 | | 0 | |
Total cash, cash equivalents, and restricted cash | $ | 1,801 | | | $ | 1,068 | | (b) | $ | 343 | | | $ | 311 | | $ | 19 | |
|
| | | | | | | | | | | | | | | | | |
| Southern Company | | Southern Power | | Southern Company Gas |
| At June 30, 2020 | At December 31, 2019 | | At June 30, 2020 | | At June 30, 2020 | At December 31, 2019 |
| (in millions) | | (in millions) | | (in millions) |
Cash and cash equivalents | $ | 1,879 |
| $ | 1,975 |
| | $ | 154 |
| | $ | 120 |
| $ | 46 |
|
Restricted cash(*): | | | | | | | |
Other accounts and notes receivable | — |
| 3 |
| | — |
| | — |
| 3 |
|
Other current assets | 4 |
| — |
| | — |
| | 4 |
| — |
|
Other deferred charges and assets | 2 |
| — |
| | 2 |
| | — |
| — |
|
Total cash, cash equivalents, and restricted cash | $ | 1,885 |
| $ | 1,978 |
| | $ | 156 |
| | $ | 124 |
| $ | 49 |
|
(a)For Southern Company Gas, reflects restricted cash held as collateral for workers' compensation, life insurance, and long-term disability insurance. For Southern Power, reflects restricted cash held for construction payables. | |
(*) | For Southern Company Gas, reflects restricted cash held as collateral for workers' compensation, life insurance, and long-term disability insurance. For Southern Power, reflects restricted cash held for construction payables. |
(b)Total does not add due to rounding.
Natural Gas for Sale
Southern Company Gas, withWith the exception of Nicor Gas, carriesSouthern Company Gas' natural gas inventorydistribution utilities record natural gas inventories on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Southern Company Gas recorded no material adjustments for the three and six months ended June 30, 2020 and recorded adjustments of $7 million and $10 million for the three and six months ended June 30, 2019, respectively.
Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated.
Southern Company Gas recorded no material adjustments to natural gas inventories for either period presented. Nicor Gas' inventory decrement at March 31, 2021 is expected to be restored prior to year end.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
cost of the inventory layers liquidated. Nicor Gas' inventory decrement at June 30, 2020 is expected to be restored prior to year end.
Asset Retirement Obligations
See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
Details of changes in AROs for Southern Company and Alabama Power during the first six months of 2020 are shown in the following table. There were no material changes in AROs for the other Registrants during the first six months of 2020.
|
| | | | | | |
| Southern Company | Alabama Power |
| (in millions) |
Balance at December 31, 2019 | $ | 9,786 |
| $ | 3,540 |
|
Liabilities incurred | 15 |
| — |
|
Liabilities settled | (193 | ) | (100 | ) |
Accretion | 204 |
| 74 |
|
Cash flow revisions | 462 |
| 462 |
|
Balance at June 30, 2020 | $ | 10,274 |
| $ | 3,976 |
|
In June 2020, Alabama Power recorded an increase of approximately $462 million to its AROs related to the CCR Rule and the related state rule primarily due to management's completion of a feasibility study and the related cost estimates during the second quarter 2020 for 1 of its ash ponds. Alabama Power's increase also reflects costs associated with the addition of a water treatment system to the design of another ash pond. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to inputs from contractor bids, design revisions, and changes in the expected volume of ash handling.
The traditional electric operating companies expect to continue updating their cost estimates and ARO liabilities periodically as additional information related to ash pond closure methodologies, schedules, and/or costs becomes available. Additionally, the closure designs and plans in the States of Alabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, results of operations, cash flows, and financial condition for Southern Company and the traditional electric operating companies could be materially impacted. See Note (B) under "Georgia Power – Integrated Resource Plan" for additional information. The ultimate outcome of these matters cannot be determined at this time.
Depreciation and Amortization
See Note 5 to the financial statements under "Depreciation and Amortization – Southern Power" in Item 8 of the Form 10-K for additional information.
Effective January 1, 2020, Southern Power revised the depreciable lives of its natural gas generating facilities from up to 45 years to up to 50 years. This revision resulted in an immaterial decrease in depreciation for the three and six months ended June 30, 2020 and is expected to result in an immaterial decrease in annual depreciation for 2020.
(B) REGULATORY MATTERS
See Note 2 to the financial statements in Item 8 of the Form 10-K for additional information relating to regulatory matters.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
The recovery balances for certain retail regulatory clauses of the traditional electric operating companies and Southern Company Gas at June 30, 2020March 31, 2021 and December 31, 20192020 were as follows:
| | | | | | | | | | | |
Regulatory Clause | Balance Sheet Line Item | March 31, 2021 | December 31, 2020 |
| | (in millions) |
Alabama Power | | | |
Rate CNP Compliance | Other regulatory liabilities, current | $ | 33 | | $ | 28 | |
| | | |
| | | |
Rate CNP PPA | Other regulatory assets, deferred | 58 | | 58 | |
Retail Energy Cost Recovery | Other regulatory liabilities, current | 0 | | 18 | |
| | | |
| Other regulatory assets, deferred | 15 | | 0 | |
| | | |
Natural Disaster Reserve | Other regulatory liabilities, deferred | 52 | | 77 | |
Georgia Power | | | |
Fuel Cost Recovery | Over recovered fuel clause revenues | $ | 83 | | $ | 113 | |
| | | |
Mississippi Power | | | |
Fuel Cost Recovery | Over recovered regulatory clause liabilities | $ | 18 | | $ | 24 | |
Ad Valorem Tax | Other regulatory assets, current | 12 | | 11 | |
| Other regulatory assets, deferred | 45 | | 41 | |
Property Damage Reserve | Other regulatory liabilities, deferred | 0 | | 4 | |
| Other regulatory assets, deferred | 1 | | 0 | |
Southern Company Gas | | | |
Natural Gas Cost Recovery(*) | Other regulatory liabilities | $ | 12 | | $ | 88 | |
| Natural gas cost under recovery | 487 | | 0 | |
| Other regulatory assets, deferred | 185 | | 0 | |
|
| | | | | | | |
Regulatory Clause | Balance Sheet Line Item | June 30, 2020 | December 31, 2019 |
| | (in millions) |
Alabama Power | | | |
Rate CNP Compliance | Other regulatory liabilities, current | $ | 25 |
| $ | 55 |
|
| Other regulatory liabilities, deferred | — |
| 7 |
|
Rate CNP PPA | Deferred under recovered regulatory clause revenues | 41 |
| 40 |
|
Retail Energy Cost Recovery | Other regulatory liabilities, current | 22 |
| 32 |
|
| Other regulatory liabilities, deferred | 93 |
| 17 |
|
Natural Disaster Reserve | Other regulatory liabilities, current | 16 |
| 37 |
|
| Other regulatory liabilities, deferred | 96 |
| 113 |
|
Georgia Power | | | |
Fuel Cost Recovery | Other current liabilities | $ | 109 |
| $ | — |
|
| Other deferred credits and liabilities | 95 |
| 73 |
|
Mississippi Power | | | |
Fuel Cost Recovery | Over recovered regulatory clause liabilities | $ | 22 |
| $ | 23 |
|
Ad Valorem Tax | Other regulatory assets | 11 |
| 47 |
|
| Other regulatory assets, deferred | 39 |
| — |
|
Property Damage Reserve | Other regulatory liabilities, deferred | 50 |
| 54 |
|
Southern Company Gas | | | |
Natural Gas Cost Recovery | Other regulatory liabilities | $ | 100 |
| $ | 74 |
|
(*)The significant change during the three months ended March 31, 2021 was primarily driven by an increase in the cost of gas purchased in February 2021 resulting from Winter Storm Uri.Alabama Power
Petition for Certificate of Convenience and Necessity
On June 9, 2020,Energy Alabama, Gasp, Inc., and the Sierra Club filed requests for reconsideration and rehearing with the Alabama PSC approved in part Alabama Power's petition for aregarding the certificate of convenience and necessity (CCN) which authorizesissued to Alabama Power to (i) construct an approximately 720-MW combined cycle facility at Alabama Power's Plant Barry (Plant Barry Unit 8),in August 2020, which is expected to be placed in service by the end of 2023, (ii) complete the Autauga Combined Cycle Acquisition, which was approved by the FERC on April 22, 2020 and is expected to close by September 1, 2020, (iii) purchase approximately 240 MWs of combined cycle generation under a long-term PPA expected to begin later in 2020 and (iv) pursue up to approximately 200 MWs of certain demand-side management and distributed energy resource programs.
The Alabama PSC authorized, the recovery of actual costs foramong other things, the construction of Plant Barry Unit 8 up to 5% aboveand the estimated in-service costacquisition of $652 million.the Central Alabama Generating Station. In so doing, it recognized the potential for developments that could cause the project costs to exceed the capped amount, in which case Alabama Power would provide documentation toDecember 2020, the Alabama PSC to explainissued an order denying the requests. On January 7, 2021, Energy Alabama and justify potential recovery of the additional costs.
The Alabama PSC further directed that the proposed solar generation of approximately 400 MWs, coupled with battery energy storage systems (solar/battery systems), be evaluated under an existing Renewable Generation Certificate issued byGasp, Inc. filed judicial appeals regarding both the Alabama PSCPSC's August 2020 CCN order and the December 2020 order denying reconsideration and rehearing. On February 23, 2021, Alabama Power filed a motion to intervene in September 2015.the appeal and, on March 9, 2021, the Circuit Court of Montgomery County, Alabama granted the motion. At March 31, 2021, expenditures associated with the construction of Plant Barry Unit 8 included in CWIP totaled approximately $161 million. The ultimate outcome of this matter cannot be determined at this time.
Plant Greene County
Alabama Power expectsjointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 5 under "Joint Ownership Agreements" in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
On April 15, 2021, Mississippi Power filed its 2021 IRP with the Mississippi PSC, which includes a schedule to retire its 40% ownership interest in Plant Greene County Units 1 and 2 in December 2025 and 2026, respectively, consistent with each unit's remaining useful life. Mississippi Power's IRP is subject to a review period during which the Mississippi PSC may note any deficiencies which could require re-evaluation or resubmission of the IRP. If no deficiencies are noted, the Mississippi PSC's review will conclude on August 13, 2021.
The Plant Greene County unit retirements identified by Mississippi Power require the completion of transmission and system reliability improvements, as well as agreement by Alabama Power. Alabama Power will continue to monitor the status of Mississippi Power's IRP and associated regulatory processes, as well as the transmission and system reliability improvements. Currently, Alabama Power plans to retire Plant Greene County Units 1 and 2 at the dates indicated. The ultimate outcome of this matter cannot be determined at this time.
Georgia Power
Rate Plan
Effective January 1, 2021, Georgia Power reduced its amortization of costs associated with CCR AROs by approximately $90 million as approved by the CCN through existing rate mechanisms as outlinedGeorgia PSC in conjunction with Georgia Power's annual compliance filings.
In February 2020, the Georgia PSC denied a motion for reconsideration filed by the Sierra Club regarding the Georgia PSC's decision in the 2019 ARP allowing Georgia Power to recover compliance costs for CCR AROs, and, in December 2020, the Superior Court of Fulton County affirmed the decision of the Georgia PSC. On January 5, 2021, the Sierra Club filed a notice of appeal with the Georgia Court of Appeals. The ultimate outcome of this matter cannot be determined at this time.
See Note 26 to the financial statements in Item 8 of the Form 10-K.10-K for additional information regarding Georgia Power's AROs.
Nuclear Construction
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4, in which Georgia Power holds a 45.7% ownership interest. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the 2 AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement.
In connection with the EPC Contractor's bankruptcy filing in March 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Alabama PSC's approval in partVogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work,
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.
See Note 8 to the CCNfinancial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for information on the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
Cost and Schedule
Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by December 2021 and November 2022, respectively, is as follows:
| | | | | |
| (in millions) |
Base project capital cost forecast(a)(b) | $ | 8,619 | |
Construction contingency estimate | 136 | |
| |
Total project capital cost forecast(a)(b) | 8,755 | |
Net investment as of March 31, 2021(b) | (7,560) | |
Remaining estimate to complete(a) | $ | 1,195 | |
(a) Excludes financing costs expected to be capitalized through AFUDC of approximately $250 million, of which $118 million had been accrued through March 31, 2021.
(b) Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds.
Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will be followedtotal approximately $3.0 billion, of which $2.7 billion had been incurred through March 31, 2021.
As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers and related test results, and workforce statistics. Southern Nuclear establishes aggressive target values for monthly construction production and system turnover activities as part of a strategy that was designed to maintain margin to the regulatory-approved in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4.
In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures, isolating individuals who have tested positive for COVID-19, are showing symptoms consistent with COVID-19, are being tested for COVID-19, or have been in close contact with such persons, requiring self-quarantine, and adopting additional precautionary measures. Since March 2020, the number of active cases at the site has fluctuated and impacted productivity levels and pace of activity completion. The lower productivity levels and slower pace of activity completion contributed to a backlog to the aggressive site work plan established at the beginning of 2020. Georgia Power estimates the productivity impacts of the COVID-19 pandemic have consumed approximately three to four months of schedule margin previously embedded in the site work plan for Unit 3 and Unit 4. In addition, the project continued to face challenges including, but not limited to, higher than expected absenteeism; overall construction and subcontractor labor productivity; system turnover and testing activities; and electrical equipment and commodity installation. As a result of these factors, in January 2021, Southern Nuclear further extended certain milestone dates, including the start of hot functional testing and fuel load for Unit 3, from those established in October 2020.
Following the January 2021 milestone extensions, Southern Nuclear has been performing additional construction remediation work, primarily related to electrical commodity installations, necessary to ensure quality and design standards are met as system turnovers are completed to support hot functional testing and fuel load for Unit 3. Hot functional testing commenced in late April 2021 and the site work plan currently targets fuel load for Unit 3 in the third quarter 2021 and an in-service date of December 2021. As the site work plan includes minimal margin to these milestone dates, any delay could result in an in-service date in the first quarter 2022 for Unit 3. Achievement of the
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
extended milestone dates established in January 2021 for Unit 4, which are expected to support a regulatory-approved in-service date of November 2022, primarily depends on overall construction productivity and production levels significantly improving as well as appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, being added and maintained.
Considering the factors above, during the first quarter 2021, approximately $84 million of the construction contingency established in the fourth quarter 2020 was assigned to the base capital cost forecast for costs primarily associated with the schedule extension for Unit 3 to December 2021, construction productivity, support resources, and construction remediation work. Georgia Power increased its total capital cost forecast as of March 31, 2021 by a written order whichadding $48 million to the remaining construction contingency.
After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to any rehearingthe outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded a pre-tax charge to income of $48 million ($36 million after tax) for the increase in the total project capital cost forecast as of March 31, 2021. As and when these amounts are spent, Georgia Power may request or judicial appeal filed within 30 daysthe Georgia PSC to evaluate those expenditures for rate recovery.
In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction and testing activities at Plant Vogtle Units 3 and 4. Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be between $150 million and $190 million and is included in the total project capital cost forecast. Estimated costs associated with near-term COVID-19 mitigation actions and related impacts on construction productivity are also included in the total project capital cost forecast described above.
As construction, including subcontract work, continues and testing and system turnover activities increase, challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale), any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. In connection with the additional construction remediation work described above, Southern Nuclear reviewed the project's construction quality programs and, where needed, is implementing improvement plans consistent with these processes. Findings resulting from such inspections could require additional remediation and/or further NRC oversight. In addition, certain license amendment requests have been filed and approved or are pending before the NRC. On March 15, 2021, the NRC issued an appealable order denying the Blue Ridge Environmental Defense League's (BREDL) December 2020 motion to reopen proceedings on BREDL's petition challenging a license amendment request. The staff of the NRC has issued the requested amendment.
In September 2020, Southern Nuclear notified the NRC of its intent to load fuel for Unit 3 in 2021. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues, including inspections and ITAACs, are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
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The ultimate outcome of these matters cannot be determined at this time. However, any extension of the in-service date beyond December 2021 for Unit 3 or November 2022 for Unit 4 is currently estimated to result in additional base capital costs for Georgia Power of approximately $25 million per month for Unit 3 and approximately $15 million per month for Unit 4, as well as the related AFUDC. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.
Joint Owner Contracts
In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
As a result of an increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs in conjunction with the nineteenth VCM report in 2018, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. In September 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4.
Amendments to the Vogtle Joint Ownership Agreements
In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG Power's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG Power and MEAG SPVJ to provide up to $300 million of funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. In January 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. In February 2019, Georgia Power, the other Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet (Global Amendments).
As previously disclosed, pursuant to the Global Amendments: (i) each Vogtle Owner must pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which formed the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such order.costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests. If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option at the time the project budget forecast is
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so revised to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion.
In addition, pursuant to the Global Amendments, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including, among other events: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power's public announcement of its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Global Amendments described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule.
The ultimate outcome of these matters cannot be determined at this time.
In 2009, the Georgia Power
DeferralPSC voted to certify construction of Incremental COVID-19 Costs
On April 7, 2020Plant Vogtle Units 3 and June 2, 2020,4 with a certified capital cost of $4.418 billion. In addition, in response to the COVID-19 pandemic,2009 the Georgia PSC approved orders directinginclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to continue its previous, voluntary suspensionrecover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of customer disconnections$4.418 billion. At March 31, 2021, Georgia Power had recovered approximately $2.6 billion of financing costs. Financing costs related to capital costs above $4.418 billion are being recognized through July 14, 2020AFUDC and are expected to deferbe recovered through retail rates over the resulting incremental bad debt as a regulatory asset. On June 16, 2020life of Plant Vogtle Units 3 and July 7,4; however, Georgia Power will not record AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery. In November 2020, the Georgia PSC approved orders establishing a methodology for identifying incremental bad debt and allowingGeorgia Power's request to decrease the deferral of other incremental costs associatedNCCR tariff by $142 million annually, effective January 1, 2021.
Georgia Power is required to file semi-annual VCM reports with the COVID-19 pandemic.Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The period over whichVogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the $0.3 billion paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and related customer refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap
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and that prudence decisions on cost recovery will be recovered is expectedmade at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 alternate rate plan) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be determined inless than Georgia Power's nextaverage cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rate case. Atrates would be adjusted to include the costs related to Unit 3 and common facilities deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective Unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $150 million in 2020 and are estimated to have negative earnings impacts of approximately $265 million and $200 million in 2021 and 2022, respectively. In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.
The Georgia PSC has approved 23 VCM reports covering periods through June 30, 2020, including total construction capital costs incurred through that date of $8.1 billion (before $1.7 billion of payments received under the incrementalGuarantee Settlement Agreement and approximately $188 million in related customer refunds). The Georgia PSC's order approving the twenty-third VCM report also instructed Georgia Power and the staff of the Georgia PSC to develop a mutually-agreeable recommendation to the Georgia PSC by the end of March 2021 regarding the procedure for and the timing, form, and substance of the rate adjustment filing related to the Unit 3 and common facility costs. On March 31, 2021, the staff of the Georgia PSC, on behalf of itself and Georgia Power, requested an extension through April 30, 2021. Georgia Power filed its twenty-fourth VCM report with the Georgia PSC on February 18, 2021, covering the period from July 1, 2020 through December 31, 2020, requesting approval of $670 million of construction capital costs deferred totaledincurred during that period.
The ultimate outcome of these matters cannot be determined at this time.
Mississippi Power
Performance Evaluation Plan
On March 15, 2021, Mississippi Power submitted its annual retail PEP filing for 2021 to the Mississippi PSC, which requested a 1.8%, or approximately $34 million.$16 million, annual increase in revenues, primarily due to increased investment and amortization and lower sales. In accordance with the PEP rate schedule, the rate increase became effective with the first billing cycle of April 2021, subject to refund. The ultimate outcome of this matter cannot be determined at this time.
Integrated Resource Plan
On March 5, 2020, the Sierra Club filed a petition for judicial review in the Superior Court of Fulton County to appeal the Georgia PSC's decision in the 2019 ARP allowing Georgia Power to recover compliance costs for CCR AROs. Georgia Power intervened in the appeal on June 22, 2020. The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
On May 28, 2020, the Georgia PSC approved a stipulation agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors to lower total fuel billings by approximately $740 million over a two-year period effective June 1, 2020. In addition, Georgia Power will further lower fuel billings by approximately $44 million under an interim fuel rider effective June 1, 2020 through September 30, 2020. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to its next fuel case if the under or over recovered fuel balance exceeds $200 million. Georgia Power is scheduled to file its next fuel case no later than February 28, 2023.
Nuclear ConstructionRegulatory Matters
In 2009, the Georgia PSC certifiedvoted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in which2009 the Georgia Power holds a 45.7% ownership interest. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full constructionPSC approved inclusion of the 2 AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued underrelated CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. At March 31, 2021, Georgia Power had recovered approximately $2.6 billion of financing costs. Financing costs related to capital costs above $4.418 billion are being recognized through AFUDC and are expected to be recovered through retail rates over the life of Plant Vogtle Units 3 and 4; however, Georgia Power will not record AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery. In November 2020, the Georgia PSC approved Georgia Power's request to decrease the NCCR tariff by $142 million annually, effective January 1, 2021.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 Agreement, which wascertificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
In 2016, the Georgia PSC voted to approve a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.
Insettlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the EPC Contractor's bankruptcy filing,fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the $0.3 billion paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power acting for itselfwould have the burden to show that any capital costs above $5.68 billion were prudent, and as agent for(c) a revised capital cost forecast of $7.3 billion (after reflecting the other Vogtle Owners, entered into several transitional arrangements to allowimpact of payments received under the Guarantee Settlement Agreement and related customer refunds) was found reasonable; (iv) construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are completeshould be completed, with Southern Nuclear serving as project manager and electricity is generatedBechtel as primary contractor; (v) approved and sold from both units. Thedeemed reasonable Georgia Power's revised schedule placing Plant Vogtle Services Agreement is terminable byUnits 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the Vogtle Owners upon 30 days' written notice.
In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement,revised cost forecast does not represent a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedulecap
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targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, basedand that prudence decisions on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Ownerscost recovery will be requiredmade at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to pay amounts related to work performed prior tocalculate the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel AgreementNCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.
See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for information on the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
Cost and Schedule
Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:
|
| | | |
| (in billions) |
Base project capital cost forecast(a)(b) | $ | 8.4 |
|
Construction contingency estimate | 0.1 |
|
Total project capital cost forecast(a)(b) | 8.5 |
|
Net investment as of June 30, 2020(b) | (6.6 | ) |
Remaining estimate to complete(a) | $ | 1.9 |
|
| |
(a) | Excludes financing costs expected to be capitalized through AFUDC of approximately $260 million, of which $52 million had been accrued through June 30, 2020. |
| |
(b) | Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds. |
Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.0 billion, of which $2.4 billion had been incurred through June 30, 2020.
As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers, and workforce statistics.
During the second quarter 2020, approximately $194 million of construction contingency was assigned to the base capital cost forecast for cost risks including, among other things, construction productivity, including the April 2020 reduction in workforce designed to mitigate impacts of the COVID-19 pandemic described below, field support, subcontracts, engineering resources, and procurement. The second quarter 2020 assignment of contingency exceeded the remaining balance of the $366 million construction contingency originally established in the second quarter 2018 by approximately $34 million. Through June 30, 2020, assignments of contingency for cost risks also have included, among other factors, construction productivity; craft labor incentives; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement. As a result of these factors, Southern Nuclear recommended establishing additional construction contingency, of which Georgia Power's share is approximately $115 million, for further potential risks including, among other factors, construction productivity and expected impacts of the COVID-19 pandemic; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement.
After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income
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of $149 million ($111 million after tax) for the increase in the total project capital cost forecast as of June 30, 2020. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.
In April 2019, Southern Nuclear established aggressive target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the regulatory-approved in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. Through early 2020, the project faced challenges with the April 2019 aggressive strategy targets including, but not limited to, electrical and pipefitting labor productivity and work package closure rates, which resulted in a backlog of activities and completion percentages below the April 2019 aggressive strategy targets.
In February 2020, Southern Nuclear updated its cost and schedule forecast, which, at that time, did not change the total project capital cost forecast and confirmed the expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. This update included initiatives to improve productivity while refining and extending system turnover plans and certain near-term milestone dates. Other milestone dates did not change. Achievement of the February 2020 aggressive site work plan relied on meeting increased monthly production and activity target values during 2020.
In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures, isolating individuals who have tested positive for COVID-19, are showing symptoms consistent with COVID-19, are being tested for COVID-19, or have been in close contact with such persons, requiring self-quarantine, and adopting additional precautionary measures.
In April 2020, Georgia Power, acting for itself and as agent for the other Vogtle Owners, announced a reduction in workforce at Plant Vogtle Units 3 and 4, which totaled approximately 20% of the then-existing site workforce. This reduction in workforce was a mitigation action intended to address the impact of the COVID-19 pandemic on the Plant Vogtle Units 3 and 4 workforce and construction site, including challenges with labor productivity that were exacerbated by the impact of the COVID-19 pandemic. The April 2020 workforce reduction was intended to provide operational efficiencies by increasing productivity of the remaining workforce and reducing workforce fatigue and absenteeism. Further, it was also intended to allow for increased social distancing by the workforce and facilitate compliance with the recommendations from the Centers for Disease Control and Prevention. The April 2020 workforce reduction did reduce absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing. From the initial peak in April 2020, the number of active cases at the site declined significantly during May and early June, but began increasing again in mid-June and continues to impact productivity levels and pace of activity completion. As a result of these factors, overall production improvements have not been achieved at the levels anticipated, contributing to the allocation of, and increase in, construction contingency described above. Through mid-July 2020, Unit 3 mechanical, electrical, and subcontract activities continued to build a backlog to Southern Nuclear's February 2020 aggressive site work plan.
To address these issues, in July 2020, Southern Nuclear updated its aggressive site work plan for both Unit 3 and Unit 4. To meet the targets in the July2013 alternate rate plan) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, aggressive site work plan, absenteeism rates must continueand (c) from 8.30% to normalize and overall construction productivity and production levels, including subcontractors, must significantly improve and5.30%, effective January 1, 2021 (provided that the ROE in no case will be sustained above pre-pandemic levels. In addition, appropriate levelsless than Georgia Power's average cost of craft laborers, particularly electrical and pipefitter craft labor, must be added and maintained. While Southern Nuclear's July 2020 aggressive site work plan extended milestone dates fromlong-term debt); (viii) reduced the February 2020 aggressive site work plan, Georgia Power still expects to achieve the regulatory-approved in-service dates of November 2021 and November 2022ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 respectively. Southern Nuclearfrom 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and Georgia Power continue(ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to believe that pursuit of an aggressive site work plan is an appropriate strategyinclude the costs related to achieve completion of the units by their regulatory-approved in-service dates.
As construction, including subcontract work, continuesUnit 3 and testing and system turnover activities increase, challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularlycommon facilities deemed prudent in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication,
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
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delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures, or components (some of which are based on new technologyVogtle Cost Settlement Agreement. The January 11, 2018 order also stated that only within the last few years began initial operation in the global nuclear industry at this scale), any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.
In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4. Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be between $70 million and $115 million, which is included in the total project capital cost forecast and assumes (i) absenteeism rates continue to normalize and (ii) the intended productivity efficiencies and production targets assumed in Southern Nuclear's July 2020 aggressive site work plan are realized in the coming months. However, the ultimate impact of the COVID-19 pandemic on the construction schedule and budget forif Plant Vogtle Units 3 and 4 cannot be determined at this time.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, may arise, which may result in additional license amendments or require other resolution. As part of the aggressive site work plan, in January 2020, Southern Nuclear notified the NRC of its intent to load fuel in 2020. On May 11, 2020, the Blue Ridge Environmental Defense League filed a petition with the NRC that challenges a license amendment request. On June 15, 2020, the NRC issued an appealable order rejecting Nuclear Watch South's April 20, 2020 petition requesting a hearing and challenging the closure of certain ITAAC. If any license amendment requests or other licensing-based compliance issues are not resolvedcommercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective Unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $150 million in a timely manner, there may be delays in the project schedule that could result in increased costs.
The ultimate outcome of these matters cannot be determined at this time. However, any extension of the regulatory-approved project schedule is currently2020 and are estimated to result in additional base capital costshave negative earnings impacts of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $10 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.
Joint Owner Contracts
In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
As a result of an increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs in conjunction with the nineteenth VCM report in 2018, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue
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construction. In September 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4.
Amendments to the Vogtle Joint Ownership Agreements
In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG Power's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG Power and MEAG SPVJ to provide up to $300 million of funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. In January 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. In February 2019, Georgia Power, the other Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet (Global Amendments).
As previously disclosed, pursuant to the Global Amendments: (i) each Vogtle Owner must pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which formed the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800$265 million and $1.6 billion over the EAC$200 million in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests;2021 and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests. If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option at the time the project budget forecast is so revised to tender a portion of2022, respectively. In its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion.
In addition, pursuant to the Global Amendments, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including, among other events: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power's public announcement of its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 orJanuary 11, 2018 order, the Georgia PSC determines that any ofalso stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.
The Georgia PSC has approved 23 VCM reports covering periods through June 30, 2020, including total construction capital costs relatingincurred through that date of $8.1 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). The Georgia PSC's order approving the twenty-third VCM report also instructed Georgia Power and the staff of the Georgia PSC to develop a mutually-agreeable recommendation to the constructionGeorgia PSC by the end of Plant Vogtle UnitsMarch 2021 regarding the procedure for and the timing, form, and substance of the rate adjustment filing related to the Unit 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid bycommon facility costs. On March 31, 2021, the staff of the Georgia PowerPSC, on behalf of the other Vogtle Owners pursuant to the Global Amendments described aboveitself and the first 6% of costs during any six-monthGeorgia Power, requested an extension through April 30, 2021. Georgia Power filed its twenty-fourth VCM reporting period that are disallowed byreport with the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery,on February 18, 2021, covering the period from July 1, 2020 through retail rates; and (iv) an incremental extensionDecember 31, 2020, requesting approval of one year or more over the most recently approved schedule.$670 million of construction capital costs incurred during that period.
The ultimate outcome of these matters cannot be determined at this time.
Mississippi Power
Performance Evaluation Plan
On March 15, 2021, Mississippi Power submitted its annual retail PEP filing for 2021 to the Mississippi PSC, which requested a 1.8%, or approximately $16 million, annual increase in revenues, primarily due to increased investment and amortization and lower sales. In accordance with the PEP rate schedule, the rate increase became effective with the first billing cycle of April 2021, subject to refund. The ultimate outcome of this matter cannot be determined at this time.
Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all
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applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. At June 30, 2020,March 31, 2021, Georgia Power had recovered approximately $2.4$2.6 billion of financing costs. Financing costs related to capital costs above $4.418 billion are being recognized through AFUDC and are expected to be recovered through retail rates over the life of Plant Vogtle Units 3 and 4; however, Georgia Power will not record AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery. In December 2019,November 2020, the Georgia PSC approved Georgia Power's request to decrease the NCCR tariff by $62$142 million annually, effective January 1, 2020.2021.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts$0.3 billion paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and related customer refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap
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and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP)alternate rate plan) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carryingthe costs on those capital costsrelated to Unit 3 and common facilities deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective Unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $75$150 million in 20192020 and are estimated to have negative earnings impacts of approximately $145 million, $255$265 million and $200 million in 2020, 2021 and 2022, respectively. In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.
In February 2018, Georgia Interfaith Power & Light, Inc. (GIPL) and Partnership for Southern Equity, Inc. (PSE) filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. In March 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's decision and denial of Georgia Watch's motion for reconsideration. In December 2018, the Fulton County Superior Court granted Georgia Power's motion to dismiss the 2 appeals. In January 2019, GIPL, PSE,
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and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. In October 2019, the Georgia Court of Appeals issued an opinion affirming the Fulton County Superior Court's ruling that the Georgia PSC's January 11, 2018 order was not a final, appealable decision. In addition, the Georgia Court of Appeals remanded the case to the Fulton County Superior Court to clarify its ruling as to whether the petitioners showed that review of the Georgia PSC's final order would not provide them an adequate remedy. On April 21, 2020, the Fulton County Superior Court granted Georgia Power's motion to dismiss the 2 appeals. The petitioners filed a notice of appeal of the dismissal on May 20, 2020. Georgia Power believes the petitions have no merit; however, an adverse outcome in the litigation combined with subsequent adverse action by the Georgia PSC could have a material impact on Southern Company's and Georgia Power's results of operations, financial condition, and liquidity.
The Georgia PSC has approved 2123 VCM reports covering the periods through June 30, 2019,2020, including total construction capital costs incurred through that date of $6.7$8.1 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). On August 18, 2020,The Georgia PSC's order approving the twenty-third VCM report also instructed Georgia Power and the staff of the Georgia PSC is scheduled to votedevelop a mutually-agreeable recommendation to the Georgia PSC by the end of March 2021 regarding the procedure for and the timing, form, and substance of the rate adjustment filing related to the Unit 3 and common facility costs. On March 31, 2021, the staff of the Georgia PSC, on behalf of itself and Georgia Power's twenty-secondPower, requested an extension through April 30, 2021. Georgia Power filed its twenty-fourth VCM report which requestedwith the Georgia PSC on February 18, 2021, covering the period from July 1, 2020 through December 31, 2020, requesting approval of $674$670 million of construction capital costs incurred from July 1, 2019 through December 31, 2019.
Georgia Power expects to file its twenty-third VCM report with the Georgia PSC by August 31, 2020, which will reflect the revised capital cost forecast discussed above and request approval of $701 million of construction capital costs incurred from January 1, 2020 through June 30, 2020.during that period.
The ultimate outcome of these matters cannot be determined at this time.
Mississippi Power
2019 Base Rate Case
On March 17, 2020, the Mississippi PSC approved a settlement agreement between Mississippi Power and the Mississippi Public Utilities Staff related to Mississippi Power's base rate case filed in November 2019 (Mississippi Power Rate Case Settlement Agreement).
Under the terms of the Mississippi Power Rate Case Settlement Agreement, annual retail rates decreased approximately $16.7 million, or 1.85%, effective for the first billing cycle of April 2020, based on a test year period of January 1, 2020 through December 31, 2020, a 53% average equity ratio, an allowed maximum actual equity ratio of 55% by the end of 2020, and a 7.57% return on investment.
Additionally, the approved Mississippi Power Rate Case Settlement Agreement: (i) established common amortization periods of four years for regulatory assets and three years for regulatory liabilities included in the approved revenue requirement, including those related to unprotected deferred income taxes; (ii) established new depreciation rates reflecting an annual increase in depreciation of approximately $10 million; and (iii) excluded certain compensation costs totaling approximately $3.9 million. It also eliminated separate rates for costs associated with Plant Ratcliffe and energy efficiency initiatives and includes such costs in the PEP, ECO Plan, and ad valorem tax adjustment factor, as applicable. In accordance with the previous order of the Mississippi PSC suspending the operation of PEP and the ECO Plan for 2018 through 2020, Mississippi Power plans to resume PEP proceedings and ECO Plan filings for 2021.
Performance Evaluation Plan
On July 24, 2020,March 15, 2021, Mississippi Power submitted its annual retail PEP filing for 2021 to the Mississippi PSC, approved Mississippi Power's July 14, 2020 filing of its PEP compliance rate clause reflecting revisions agreedwhich requested a 1.8%, or approximately $16 million, annual increase in revenues, primarily due to inincreased investment and amortization and lower sales. In accordance with the Mississippi Power Rate Case Settlement Agreement. These revisions include, among other things, changing the filing date for the annual PEP rate filing from Novemberschedule, the rate increase became effective with the first billing cycle of the immediately preceding yearApril 2021, subject to March of the current year, utilizing a historic test year adjusted for "known and measurable" changes, using discounted cash flow and regression formulas to determine base return on equity, and moving all embedded ad valorem property taxes currently collected in PEP to the ad valorem tax adjustment clause.
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Deferral of Incremental COVID-19 Costs
On April 14, 2020 and May 12, 2020, in order to mitigate the economic impact of the COVID-19 pandemic on customers, the Mississippi PSC approved orders directing Mississippi Power to continue its previous, voluntary suspension of customer disconnections through May 25, 2020 and to defer as a regulatory asset all necessary and reasonable incremental costs or expenses to plan, prepare, stage, or react to protect and keep safe its employees and customers, and to reliably operate its utility system during the COVID-19 pandemic. The period over which such costs will be recovered is expected to be determined in a future PEP filing. At June 30, 2020, the incremental costs deferred totaled approximately $2 million.refund. The ultimate outcome of this matter cannot be determined at this time.
Municipal and Rural Associations TariffIntegrated Resource Plan
On June 25,In December 2020, the FERC acceptedMississippi PSC issued an order in the Reserve Margin Plan docket requiring Mississippi Power to incorporate into its 2021 IRP a schedule reflecting the retirement of 950 MWs of fossil-steam generation by year-end 2027 to reduce Mississippi Power's excess reserve margin. On April 27, 2020 request for an increase in wholesale base revenues under the MRA tariff as agreed upon in a settlement agreement reached with15, 2021, Mississippi Power filed its wholesale customers. The MRA settlement agreement resulted in a $2 million annual increase in base rates effective June 1, 2020.
Southern Company Gas
Rate Proceedings
On June 1, 2020, Virginia Natural Gas filed a general rate case2021 IRP with the Virginia Commission seeking an increaseMississippi PSC. The filing includes a schedule to retire Plant Watson Unit 4 (268 MWs) and Mississippi Power's 40% ownership interest in ratesPlant Greene County Units 1 and 2 (103 MWs each) in December 2023, 2025, and 2026, respectively, consistent with each unit's remaining useful life in the most recent approved depreciation studies. In addition, the schedule reflects the early retirement of Mississippi Power's 50% undivided ownership interest in Plant Daniel Units 1 and 2 (502 MWs) by the end of 2027. The Plant Greene County unit retirements require the completion by Alabama Power of transmission and system reliability improvements, as well as agreement by Alabama Power.
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The remaining net book value of Plant Daniel Units 1 and 2 was approximately $531 million primarilyat March 31, 2021. Mississippi Power expects to recover investmentsreclassify the net book value remaining at retirement to a regulatory asset to be amortized over a period to be determined by the Mississippi PSC in future proceedings, consistent with the December 2020 order. The Plant Watson and increased costs associated with infrastructure, technology, and workforce development. The requested increase is based on a projected 12-month test year beginning November 1, 2020, a ROE of 10.35%, and an equity ratio of 54%. Rate adjustmentsGreene County units are expected to be effective November 1, 2020,fully depreciated upon retirement.
The 2021 IRP is subject to refund. The Virginia Commission is expected to rule ona review period during which the requested increase in the second quarter 2021.
On July 1, 2020, Atlanta Gas Light filed its 2020 GRAM filing with the Georgia PSC. The filing requests an annual base rate increase of $37.6 million based on the projected 12-month period beginning January 1, 2021,Mississippi PSC may note any deficiencies which does not exceed the 5% limitation established by the Georgia PSC in its December 2019 approval of Atlanta Gas Light's general base rate case. Resolutioncould require re-evaluation or resubmission of the 2020 GRAM filing is expected by December 31, 2020, with rates effective January 1,IRP. If no deficiencies are noted, the Mississippi PSC's review will conclude on August 13, 2021.
The ultimate outcome of these matters cannot be determined at this time.
Deferral of Incremental COVID-19 Costs
Atlanta Gas Light
On April 30, 2020, in response to the COVID-19 pandemic, the Georgia PSC approved orders directing Atlanta Gas Light to continue its previous, voluntary suspension of customer disconnections. On June 22, 2020, the Georgia PSC ordered Atlanta Gas Light to resume customer disconnections beginning July 1, 2020, with exceptions for customers still covered by a shelter-in-place order. The orders provide the Marketers, including SouthStar, with a mechanism to receive credits from Atlanta Gas Light for the base rates it charged to the Marketers of non-paying customers during the suspension. Atlanta Gas Light expects to recover these credits through the annual revenue true-up process within its 2021 GRAM filing, which would impact rates effective January 1, 2022. The ultimate outcome of this matter cannot be determined at this time.
NicorAd Valorem Tax Adjustment
On April 6, 2021, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment filing for 2021, which requested an annual increase in revenues of approximately $28 million, including approximately $19 million of ad valorem taxes previously recovered through PEP in accordance with the Mississippi Power Rate Case Settlement Agreement. The rate became effective with the first billing cycle of May 2021.
Southern Company Gas
Infrastructure Replacement Programs and Capital Projects
Capital expenditures incurred under specific infrastructure replacement programs during the first three months of 2021 were as follows:
| | | | | | | | |
Utility | Program | Three Months Ended March 31, 2021 |
| | (in millions) |
Nicor Gas | Investing in Illinois | $ | 45 | |
Virginia Natural Gas | Steps to Advance Virginia's Energy | 9 | |
Total | | $ | 54 | |
Atlanta Gas Light
On March 18, 2020,April 28, 2021, Atlanta Gas Light filed its first Integrated Capacity and Delivery Plan (i-CDP) with the Illinois Commission issued an order directing utilitiesGeorgia PSC, which includes a series of ongoing and proposed pipeline safety, reliability, and growth programs for the next 10 years (2022 through 2031), as well as the required capital investments and related costs to cease disconnections for non-payment andimplement the programs. The i-CDP reflects capital investments totaling approximately $0.5 billion to suspend the imposition of late payment fees or penalties until the Governor of Illinois announces the end$0.6 billion annually.
Recovery of the COVID-19 state of emergency. In responserelated revenue requirements will be included in either subsequent annual GRAM filings or the new System Reinforcement Rider for authorized large pressure improvement and system reliability projects. The i-CDP is subject to this order, on March 27, 2020, Nicor Gas and other utilities in Illinois filed their plans seeking cost recovery and more flexible credit and collection plans.
On June 18, 2020, the Illinois Commission approved a stipulation pursuant tofive-month review period, which the utilities will provide more flexible credit and collection procedures to assist customers with financial hardship and which authorizes a special
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purpose rider for recovery of the following COVID-19 pandemic-related impacts: incremental costs directly associated with the COVID-19 pandemic, net of the offset for COVID-19 pandemic-related credits received, foregone late fees, foregone reconnection charges, and the costs associated with a bill payment assistance program. The special purpose rider is proposed tomay be effective on October 1, 2020 and continue over a 24-month period. At June 30, 2020, Nicor Gas' related regulatory asset was $12 million.extended. The ultimate outcome of this matter cannot be determined at this time.
Virginia Natural Gas
In response to the COVID-19 pandemic,On April 6, 2021, the Virginia State Corporation Commission issued orders requiringapproved a motion filed by Virginia Natural Gas to suspend disconnections beginning on March 16, 2020 and alsowithdraw the application for its 9.5-mile interconnect project due to suspend late payment and reconnection fees beginning on April 9, 2020, botha change in the capacity needs of which continue in effect through August 31, 2020. On April 29, 2020, the Virginia Commission authorized Virginia Natural Gas to defer the following COVID-19 pandemic-related costs as a regulatory asset: incremental uncollectible expense incurred, suspended late fees, suspended reconnection charges, carrying costs, and other incremental prudently incurred costs associated with the COVID-19 pandemic. Specific recovery of the amounts deferred in a regulatory asset will be addressed in a future rate proceeding. At June 30, 2020, Virginia Natural Gas' related regulatory asset was $1 million. The ultimate outcome of this matter cannot be determined at this time.
Infrastructure Replacement Programs and Capital Projects
In December 2019, Virginia Natural Gas filed an application with the Virginia Commission for a 24.1-mile header improvement project to improve resiliency and increase the supply of natural gas delivered to energy suppliers, including Virginia Natural Gas. On June 26, 2020, the Virginia Commission issued an order requiring Virginia Natural Gas to submit additional information by December 31, 2020 related to the financing plansone of the project's primary customer before ruling on the December 2019 application. The ultimate outcome ofcustomers. No further action is necessary and this matter cannot be determined at this time.is now concluded.
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Deferral of Incremental COVID-19 Costs
Nicor Gas
On March 18, 2021, the Illinois Commission approved a phased-in schedule for disconnections related to non-payment. Nicor Gas began certain disconnections in late April 2021 and will resume normal disconnections in June 2021. Nicor Gas will continue certain flexible credit and collection procedures until mid-2021.
(C) CONTINGENCIES
See Note 3 to the financial statements in Item 8 of the Form 10-K for information relating to various lawsuits and other contingencies.
General Litigation Matters
The Registrants are involved in various other matters being litigated and regulatory matters. The ultimate outcome of such pending or potential litigation or regulatory matters against each Registrant and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such Registrant's financial statements.
The Registrants believe the pending legal challenges discussed below have no merit; however, the ultimate outcome of these matters cannot be determined at this time.
Southern Company
In January 2017, a securities class action complaint was filed in the U.S. District Court for the Northern District of Georgia by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint names as defendants Southern Company, certain of its current and former officers, and certain former Mississippi Power officers and alleges that the defendants made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. Also in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an
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opposition. In 2018, the court issued an order dismissing certain claims against certain officers of Southern Company and Mississippi Power and dismissing the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. In 2018, the court denied the defendants' motion for reconsideration and also denied a motion to certify the issue for interlocutory appeal. In the third quarter 2019, the court certified the plaintiffs' proposed class and the defendants filed a petition for interlocutory appeal of the class certification order with the U.S. Court of Appeals for the Eleventh Circuit. In December 2019, the U.S. District Court for the Northern District of Georgia entered an order staying all deadlines in the case pending mediation. The stay automatically expired on March 31, 2020; however, in light of the COVID-19 pandemic, the U.S. District Court for the Northern District of Georgia vacated all existing discovery deadlines until June 15, 2020. On June 30, 2020, the court entered a revised scheduling order, which resumed discovery and set out remaining case deadlines.
In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. In 2017, these 2 shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. In 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action.
In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, Georgia that names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. In 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. In August 2019, the court granted a motion filed by the plaintiff in July 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust.
The plaintiffs in each of these cases seek to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiffs also seek certain changes to Southern Company's corporate governance and internal processes. In 2018, the court in each case entered an order staying each lawsuit until 30 days after the settlement of a securities class action filed in January 2017 against Southern Company, certain of its current and former officers, and certain former Mississippi Power officers. In September 2020, the plaintiffs in each case filed a status report noting the settlement of the securities class action and informing the court that the parties had scheduled mediation, which occurred in November 2020. The parties in each case did not reach settlement but continue to explore possible resolution. Each case is stayed while the parties discuss potential resolution.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Georgia Power
In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state law claims. This case has been ruled upon and appealed numerous times over the last several years. In one recent appeal, the Georgia Supreme Court remanded the case and noted that the trial court could refer the matter to the Georgia PSC to interpret its tariffs. Following a motion by Georgia Power, in February 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling and also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. Also in March 2019, Georgia Power appealed the class certification decision to the Georgia Court of Appeals. In October 2019, the Georgia PSC issued an order that found Georgia Power has appropriately implemented the municipal franchise fee schedule. OnIn March 11, 2020, the Georgia Court of Appeals vacated the Superior Court of Fulton County's February 2019 order granting conditional class certification. The Court of
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Appealscertification and remanded the case to the Superior Court of Fulton County for further proceedings. In September 2020, the plaintiffs and Georgia Power each filed motions for summary judgment and the plaintiffs renewed their motion for class certification. On March 16, 2021, the Superior Court of Fulton County granted class certification and Georgia Power's motion for summary judgment. On March 22, 2021, the plaintiffs filed a notice of appeal, and, on April 2, 2021, Georgia Power filed a notice of cross appeal on the issue of class certification. The amount of any possible losses cannot be calculatedestimated at this time because, among other factors, it is unknown whether a class will be certified, the ultimate composition of any class, and whether any losses would be subject to recovery from any municipalities.
OnIn July 29, 2020, a group of individual plaintiffs filed a complaint in the Superior Court of Fulton County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater, surface water, and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief. In September 2020, Georgia Power filed a motion to dismiss. The amount of any possible losses cannot be estimated at this time.
Mississippi Power
In May 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on 2 agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. A portion of the claim for damages was on behalf of Martin Transport, Inc. (Martin Transport), an affiliate of Martin. In May 2019, the arbitration panel denied Mississippi Power's and Southern Company's motions to dismiss. In September 2019, Martin Transport filed a separate complaint against Mississippi Power in the Circuit Court of Kemper County, Mississippi alleging claims of fraud, negligent misrepresentation, promissory estoppel, and equitable estoppel, each arising out of the same alleged facts and circumstances that underlie Martin's arbitration demand. Martin Transport seeks compensatory damages of $5 million and punitive damages of $50 million. In November 2019, Martin Transport's claim was combined with the Martin arbitration case and the separate court case was dismissed. In December 2019, Southern Company and Mississippi Power each filed motions for summary judgment on all claims. On February 17, 2020, the arbitration panel granted Southern Company's motion and dismissed Southern Company from the arbitration. On March 12, 2020, the arbitration panel denied Mississippi Power's motions for summary judgment. An adverse outcome in this proceeding could have a material impact on Southern Company's and Mississippi Power's financial statements.
In November 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the 3 then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. In response to Mississippi Power and the Mississippi PSC each filing a motion to dismiss, the plaintiffs filed an amended complaint in March 2019. The amended complaint included 4 additional plaintiffs and additional claims for gross negligence, reckless conduct, and intentional wrongdoing. Mississippi Power and the Mississippi PSC have each filed a motion to dismiss the amended complaint. Oncomplaint, which occurred in May 2020 and March 27, 2020, the Mississippi PSC's motion to dismiss was granted.respectively. Also onin March 27, 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. On April 9, 2020 and April 10, 2020, Mississippi Power and the Mississippi PSC, respectively, filed responses opposing the motion for leave to file a second amended complaint. On May 26, 2020, Mississippi Power's motion to dismiss the first amended complaint filed in 2019 was granted. OnIn July 6, 2020, the plaintiffs filed a motion for revision of the court's decision. The plaintiffs' motion for leave to file a third amended complaint, which included the same federal claims as the proposed second amended complaint, also remainsas well as several additional state law claims based on the allegation that Mississippi Power failed to disclose the annual percentage rate of interest applicable to refunds. In November 2020, the court denied each of the plaintiffs' pending beforemotions and entered final judgment in favor of Mississippi Power. On January 22, 2021, the court.court denied further motions by the plaintiffs to vacate the judgment and to file a revised second
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
amended complaint. On February 19, 2021, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fifth Circuit. An adverse outcome in this proceeding could have a material impact on Mississippi Power's financial statements.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
See Note 23 to the financial statements under "Mississippi"Other Matters – Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and the natural gas distribution utilities in Illinois and Georgia have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental complianceremediation costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.
Georgia Power's environmental remediation liability was $14$16 million and $15 million as of June 30, 2020at March 31, 2021 and December 31, 2019,2020, respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.
In December 2019, Mississippi Power entered into an agreement with the Mississippi Commission on Environmental Quality related to groundwater conditions arising from the closed ash pond at Plant Watson. Mississippi Power will complete an assessment and remediation consistent with the requirements of the agreement and the CCR Rule. Potential remediation activities and related cost estimates are pending the result of further site assessment and cannot be determined at this time. Mississippi Power expects to recover the retail portion of remedial costs through the ECO Plan and the wholesale portion through MRA rates.
Southern Company Gas' environmental remediation liability was $253$240 million and $269$245 million as of June 30, 2020March 31, 2021 and December 31, 2019,2020, respectively, based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are generally recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities.
The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the financial statements of the applicable Registrants.
Other Matters
Southern Company
See Notes 1 and 3 under "Leveraged Leases" and "Other Matters – Southern Company," respectively, in Item 8 of the Form 10-K for discussion of challenges associated with a leveraged lease agreement with a subsidiary of Southern Holdings. While all required lease payments through June 30, 2020 have been paid in full, the operational and remarketing risks and the resulting cash liquidity challenges persist and significant concerns continue regarding the lessee's ability to make the remaining required semi-annual lease payments to the Southern Holdings subsidiary through the term of the lease.
In its annual impairment analysis of the expected residual value of the generation assets and the overall collectability of the related lease receivable, Southern Company uses multiple scenarios of long-term market energy prices to estimate the cash flows expected to be received from remarketing the generation assets following the expiration of the existing PPA in 2032 and the residual value of the generation assets at the end of the lease in 2047. Southern Company received the latest annual forecasts of natural gas prices during the second quarter 2020 and considered the significant decline in forecasted prices to be an indicator of potential impairment that required an interim impairment assessment. Accordingly, consistent with prior years, Southern Company evaluated the recoverability of the lease receivable and the expected residual value of the generation assets under various natural gas price scenarios. Based on the current forecasts of energy prices in the years following the expiration of the
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
existing PPA, Southern Company concluded that it is no longer probable that any of the associated rental payments will be received, because it is no longer probable the generation assets will be successfully remarketed and continue to operate after that date. During the second quarter 2020, Southern Company revised the estimated cash flows to be received under the leveraged lease to reflect this conclusion, which resulted in a full impairment of the lease investment and a pre-tax charge to earnings of $154 million ($74 million after tax).
If any future lease payment due prior to the expiration of the associated PPA is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders could represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets, in effect terminating the lease. As the full amount of the lease investment has been charged against earnings as of June 30, 2020, termination would not be expected to result in additional charges. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments and meet its obligations associated with a future closure or retirement of the generation assets and associated properties, including the dry ash landfill.
Mississippi Power
Kemper County Energy Facility
See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.
As the mining permit holder, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities related to the lignite mine and equipment and mineral reserves located around the Kemper County energy facility site. As a result of the abandonment of the Kemper IGCC, final mine reclamation began in 2018 and is expected to be substantially completed in 2020, with monitoring expected to continue through 2027. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
Dismantlement of the abandoned gasifier-related assets and site restoration activities are expected to be completed in 2025. The additional pre-tax period costs associated with dismantlement and site restoration activities, including related costs for compliance and safety, ARO accretion, and property taxes, are estimated to total $5 million for the remainder of 2020, $16 million in 2021, and $11 million to $13 million annually in 2022 through 2025. In addition, closure costs for the mine and gasifier-related assets, currently estimated at up to $6 million pre-tax (excluding dismantlement costs, net of salvage), may be incurred during the remainder of 2020.
In December 2019, Mississippi Power transferred ownership of the CO2 pipeline to an unrelated gas pipeline company, with no resulting impact on income. In conjunction with the transfer of the CO2 pipeline, the parties agreed to enter into a 15-year firm transportation agreement, which is expected to be signed by the end of 2020, providing for the conversion by the pipeline company of the CO2 pipeline to a natural gas pipeline to be used for the delivery of natural gas to Plant Ratcliffe. The agreement will be treated as a finance lease for accounting purposes upon commencement.
In 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of grants received for the Kemper County energy facility. Mississippi Power expects to close out the DOE contract in 2020. In connection with the DOE closeout discussions, in April 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of an investigation related to the Kemper County energy facility. The ultimate outcome of this matter cannot be determined at this time; however, it could have a material impact on Southern Company's and Mississippi Power's financial statements.
Plant Daniel
In conjunction with Southern Company's sale of Gulf Power, Mississippi Power and Gulf Power agreed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the restructuring, own 100% of a generating unit. On April 24, 2020, Mississippi Power and Gulf Power amended the
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
terms of the agreement to extend the deadline from May 1, 2020 to August 1, 2020 for Mississippi Power to notify Gulf Power of which generating unit it has selected for 100% ownership. Mississippi Power and Gulf Power are continuing negotiations on a mutually acceptable revised operating agreement for Plant Daniel and, as a result, the parties have agreed not to select a specific unit on August 1, 2020. The impacts of operating the units on an individual basis continue to be evaluated by Mississippi Power and any transfer of ownership would be subject to approval by the FERC and the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time.
Southern Company Gas
See Notes 3PennEast Pipeline Project
Work continues with state and 7federal agencies to obtain the financial statements in Item 8required permits to begin construction of the Form 10-K under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively, and Note (E) under "Southern Company Gas" for additional information.
On March 24, 2020, Southern Company Gas completed the sale of its interest in Atlantic CoastPennEast Pipeline. See Note (K) under "Southern Company Gas" for additional information.
On February 20, 2020, the FERC approved a two-year extension for PennEast Pipeline to complete the project by January 19, 2022.
In September 2019, an appellate court ruled that the PennEast Pipeline does not have federal eminent domain authority over lands in which a state has property rights interests. On June 29, 2020, the U.S. Supreme Court requested the U.S. Solicitor General to provide an opinion on PennEast Pipeline's petition for a writ of certiorari seeking its review of the appellate court's decision.
Expected project costs related to the PennEast Pipeline for Southern Company Gas total approximately $300 million, excluding financing costs. The ultimate outcome of the PennEast Pipeline construction project cannot be determined at this time; however, any work delays, whether caused by judicial or regulatory action, abnormal weather, or other conditions, may result in additional cost or schedule modifications or, ultimately, in project cancellation, any of which could result in impairment of Southern Company Gas' investment ($93 million at March 31, 2021) and could have a significant impact on Southern Company's financial statements and a material impact on Southern Company Gas' financial statements. See Note (E) under "Southern Company Gas" for additional information.
SNG
As a 50% equity investor in SNG, Southern Company Gas is required to make additional capital contributions as necessary pursuant to the terms of its operating agreement with SNG. SNG has $300 million of debt maturing in June 2021 that it anticipates refinancing prior to its maturity. If SNG is unable to refinance or otherwise satisfy this debt obligation, Southern Company Gas has committed to fund up to $150 million as a contingent capital contribution. See Note (E) under "Southern Company Gas" for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
(D) REVENUE FROM CONTRACTS WITH CUSTOMERS AND LEASE INCOME
Revenue from Contracts with Customers
The Registrants generate revenues from a variety of sources, some of which are not accounted for as revenue from contracts with customers, such as leases, derivatives, and certain cost recovery mechanisms. See Note 1 to the financial statements under "Revenues" in Item 8 of the Form 10-K for additional information on the revenue policies of the Registrants. See "Lease Income""Lease Income" herein and Note (J) for additional information on revenue accounted for under lease and derivative accounting guidance, respectively.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
The following table disaggregates revenue from contracts with customers for the three and six months ended June 30, 2020March 31, 2021 and 2019:2020:
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| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
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Three Months Ended March 31, 2021 | | | | | | |
Operating revenues | | | | | | |
Retail electric revenues | | | | | | |
Residential | $ | 1,468 | | $ | 628 | | $ | 776 | | $ | 64 | | $ | 0 | | $ | 0 | |
Commercial | 1,117 | | 372 | | 686 | | 59 | | 0 | | 0 | |
Industrial | 668 | | 320 | | 284 | | 64 | | 0 | | 0 | |
Other | 24 | | 5 | | 17 | | 2 | | 0 | | 0 | |
Total retail electric revenues | 3,277 | | 1,325 | | 1,763 | | 189 | | 0 | | 0 | |
Natural gas distribution revenues | | | | | | |
Residential | 614 | | 0 | | 0 | | 0 | | 0 | | 614 | |
Commercial | 170 | | 0 | | 0 | | 0 | | 0 | | 170 | |
Transportation | 288 | | 0 | | 0 | | 0 | | 0 | | 288 | |
Industrial | 16 | | 0 | | 0 | | 0 | | 0 | | 16 | |
Other | 97 | | 0 | | 0 | | 0 | | 0 | | 97 | |
Total natural gas distribution revenues | 1,185 | | 0 | | 0 | | 0 | | 0 | | 1,185 | |
Wholesale electric revenues | | | | | | |
PPA energy revenues | 212 | | 43 | | 13 | | 4 | | 156 | | 0 | |
PPA capacity revenues | 119 | | 29 | | 13 | | 3 | | 75 | | — | |
Non-PPA revenues | 67 | | 32 | | 9 | | 88 | | 61 | | 0 | |
Total wholesale electric revenues | 398 | | 104 | | 35 | | 95 | | 292 | | 0 | |
Other natural gas revenues | | | | | | |
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Wholesale gas services | 1,590 | | 0 | | 0 | | 0 | | 0 | | 1,590 | |
Gas marketing services | 194 | | 0 | | 0 | | 0 | | 0 | | 194 | |
Other natural gas revenues | 7 | | 0 | | 0 | | 0 | | 0 | | 7 | |
Total natural gas revenues | 1,791 | | 0 | | 0 | | 0 | | 0 | | 1,791 | |
Other revenues | 249 | | 46 | | 113 | | 8 | | 4 | | 0 | |
Total revenue from contracts with customers | 6,900 | | 1,475 | | 1,911 | | 292 | | 296 | | 2,976 | |
Other revenue sources(a) | 1,306 | | 84 | | 59 | | 15 | | 144 | | 1,014 | |
Other adjustments(b) | (2,296) | | 0 | | 0 | | 0 | | 0 | | (2,296) | |
Total operating revenues | $ | 5,910 | | $ | 1,559 | | $ | 1,970 | | $ | 307 | | $ | 440 | | $ | 1,694 | |
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| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
Three Months Ended June 30, 2020 | | | | | | |
Operating revenues | | | | | | |
Retail electric revenues | | | | | | |
Residential | $ | 1,430 |
| $ | 549 |
| $ | 817 |
| $ | 64 |
| $ | — |
| $ | — |
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Commercial | 1,103 |
| 353 |
| 689 |
| 61 |
| — |
| — |
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Industrial | 642 |
| 302 |
| 273 |
| 67 |
| — |
| — |
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Other | 23 |
| 6 |
| 15 |
| 2 |
| — |
| — |
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Total retail electric revenues | 3,198 |
| 1,210 |
| 1,794 |
| 194 |
| — |
| — |
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Natural gas distribution revenues | | | | | | |
Residential | 239 |
| — |
| — |
| — |
| — |
| 239 |
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Commercial | 58 |
| — |
| — |
| — |
| — |
| 58 |
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Transportation | 234 |
| — |
| — |
| — |
| — |
| 234 |
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Industrial | 5 |
| — |
| — |
| — |
| — |
| 5 |
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Other | 49 |
| — |
| — |
| — |
| — |
| 49 |
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Total natural gas distribution revenues | 585 |
| — |
| — |
| — |
| — |
| 585 |
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Wholesale electric revenues | | | | | | |
PPA energy revenues | 167 |
| 28 |
| 7 |
| 2 |
| 134 |
| — |
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PPA capacity revenues | 108 |
| 25 |
| 13 |
| 1 |
| 71 |
| — |
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Non-PPA revenues | 50 |
| 5 |
| 2 |
| 73 |
| 59 |
| — |
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Total wholesale electric revenues | 325 |
| 58 |
| 22 |
| 76 |
| 264 |
| — |
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Other natural gas revenues | | | | | | |
Wholesale gas services | 341 |
| — |
| — |
| — |
| — |
| 341 |
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Gas marketing services | 57 |
| — |
| — |
| — |
| — |
| 57 |
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Other natural gas revenues | 8 |
| — |
| — |
| — |
| — |
| 8 |
|
Total natural gas revenues | 406 |
| — |
| — |
| — |
| — |
| 406 |
|
Other revenues | 251 |
| 44 |
| 119 |
| 6 |
| 4 |
| — |
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Total revenue from contracts with customers | 4,765 |
| 1,312 |
| 1,935 |
| 276 |
| 268 |
| 991 |
|
Other revenue sources(a) | 728 |
| 53 |
| (7 | ) | 7 |
| 171 |
| 518 |
|
Other adjustments(b) | (873 | ) | — |
| — |
| — |
| — |
| (873 | ) |
Total operating revenues | $ | 4,620 |
| $ | 1,365 |
| $ | 1,928 |
| $ | 283 |
| $ | 439 |
| $ | 636 |
|
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NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
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| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
Three Months Ended March 31, 2020 | | | | | | |
Operating revenues | | | | | | |
Retail electric revenues | | | | | | |
Residential | $ | 1,370 | | $ | 553 | | $ | 760 | | $ | 57 | | $ | 0 | | $ | 0 | |
Commercial | 1,146 | | 364 | | 720 | | 62 | | 0 | | 0 | |
Industrial | 680 | | 321 | | 281 | | 78 | | 0 | | 0 | |
Other | 23 | | 5 | | 16 | | 2 | | 0 | | 0 | |
Total retail electric revenues | 3,219 | | 1,243 | | 1,777 | | 199 | | 0 | | 0 | |
Natural gas distribution revenues | | | | | | |
Residential | 496 | | 0 | | 0 | | 0 | | 0 | | 496 | |
Commercial | 130 | | 0 | | 0 | | 0 | | 0 | | 130 | |
Transportation | 264 | | 0 | | 0 | | 0 | | 0 | | 264 | |
Industrial | 12 | | 0 | | 0 | | 0 | | 0 | | 12 | |
Other | 97 | | 0 | | 0 | | 0 | | 0 | | 97 | |
Total natural gas distribution revenues | 999 | | 0 | | 0 | | 0 | | 0 | | 999 | |
Wholesale electric revenues | | | | | | |
PPA energy revenues | 159 | | 27 | | 9 | | 2 | | 125 | | 0 | |
PPA capacity revenues | 105 | | 27 | | 12 | | 1 | | 66 | | 0 | |
Non-PPA revenues | 51 | | 19 | | 2 | | 69 | | 58 | | 0 | |
Total wholesale electric revenues | 315 | | 73 | | 23 | | 72 | | 249 | | 0 | |
Other natural gas revenues | | | | | | |
| | | | | | |
Wholesale gas services | 396 | | 0 | | 0 | | 0 | | 0 | | 396 | |
Gas marketing services | 163 | | 0 | | 0 | | 0 | | 0 | | 163 | |
Other natural gas revenues | 7 | | 0 | | 0 | | 0 | | 0 | | 7 | |
Total natural gas revenues | 566 | | 0 | | 0 | | 0 | | 0 | | 566 | |
Other revenues | 192 | | 37 | | 95 | | 5 | | 3 | | 0 | |
Total revenue from contracts with customers | 5,291 | | 1,353 | | 1,895 | | 276 | | 252 | | 1,565 | |
Other revenue sources(a) | 868 | | (2) | | (70) | | 1 | | 123 | | 825 | |
Other adjustments(b) | (1,141) | | 0 | | 0 | | 0 | | 0 | | (1,141) | |
Total operating revenues | $ | 5,018 | | $ | 1,351 | | $ | 1,825 | | $ | 277 | | $ | 375 | | $ | 1,249 | |
(a)Other revenue sources relate to revenues from customers accounted for as derivatives and leases, alternative revenue programs at Southern Company Gas, and cost recovery mechanisms and revenues that meet other scope exceptions for revenues from contracts with customers at the traditional electric operating companies.
(b)Other adjustments relate to the cost of Southern Company Gas' energy and risk management activities. Wholesale gas services revenues are presented net of the related costs of those activities on the statement of income. See Note (L) under "Southern Company Gas" for additional information on the components of wholesale gas services' operating revenues.
|
| | | | | | | | | | | | | | | | | | |
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
Six Months Ended June 30, 2020 | | | | | | |
Operating revenues | | | | | | |
Retail electric revenues | | | | | | |
Residential | $ | 2,801 |
| $ | 1,103 |
| $ | 1,577 |
| $ | 121 |
| $ | — |
| $ | — |
|
Commercial | 2,247 |
| 717 |
| 1,409 |
| 121 |
| — |
| — |
|
Industrial | 1,323 |
| 623 |
| 555 |
| 145 |
| — |
| — |
|
Other | 46 |
| 11 |
| 31 |
| 4 |
| — |
| — |
|
Total retail electric revenues | 6,417 |
| 2,454 |
| 3,572 |
| 391 |
| — |
| — |
|
Natural gas distribution revenues | | | | | | |
Residential | 736 |
| — |
| — |
| — |
| — |
| 736 |
|
Commercial | 188 |
| — |
| — |
| — |
| — |
| 188 |
|
Transportation | 499 |
| — |
| — |
| — |
| — |
| 499 |
|
Industrial | 17 |
| — |
| — |
| — |
| — |
| 17 |
|
Other | 144 |
| — |
| — |
| — |
| — |
| 144 |
|
Total natural gas distribution revenues | 1,584 |
| — |
| — |
| — |
| — |
| 1,584 |
|
Wholesale electric revenues | | | | | | |
PPA energy revenues | 326 |
| 55 |
| 15 |
| 4 |
| 259 |
| — |
|
PPA capacity revenues | 213 |
| 52 |
| 25 |
| 2 |
| 136 |
| — |
|
Non-PPA revenues | 100 |
| 24 |
| 4 |
| 142 |
| 117 |
| — |
|
Total wholesale electric revenues | 639 |
| 131 |
| 44 |
| 148 |
| 512 |
| — |
|
Other natural gas revenues | | | | | | |
Wholesale gas services | 737 |
| — |
| — |
| — |
| — |
| 737 |
|
Gas marketing services | 220 |
| — |
| — |
| — |
| — |
| 220 |
|
Other natural gas revenues | 15 |
| — |
| — |
| — |
| — |
| 15 |
|
Total natural gas revenues | 972 |
| — |
| — |
| — |
| — |
| 972 |
|
Other revenues | 441 |
| 78 |
| 214 |
| 13 |
| 7 |
| — |
|
Total revenue from contracts with customers | 10,053 |
| 2,663 |
| 3,830 |
| 552 |
| 519 |
| 2,556 |
|
Other revenue sources(a) | 1,599 |
| 53 |
| (76 | ) | 7 |
| 295 |
| 1,343 |
|
Other adjustments(b) | (2,014 | ) | — |
| — |
| — |
| — |
| (2,014 | ) |
Total operating revenues | $ | 9,638 |
| $ | 2,716 |
| $ | 3,754 |
| $ | 559 |
| $ | 814 |
| $ | 1,885 |
|
| | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | |
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
Three Months Ended June 30, 2019 | | | | | | |
Operating revenues | | | | | | |
Retail electric revenues | | | | | | |
Residential | $ | 1,491 |
| $ | 592 |
| $ | 831 |
| $ | 68 |
| $ | — |
| $ | — |
|
Commercial | 1,264 |
| 422 |
| 770 |
| 72 |
| — |
| — |
|
Industrial | 766 |
| 369 |
| 327 |
| 70 |
| — |
| — |
|
Other | 25 |
| 7 |
| 15 |
| 3 |
| — |
| — |
|
Total retail electric revenues | 3,546 |
| 1,390 |
| 1,943 |
| 213 |
| — |
| — |
|
Natural gas distribution revenues | | | | | | |
Residential | 229 |
| — |
| — |
| — |
| — |
| 229 |
|
Commercial | 65 |
| — |
| — |
| — |
| — |
| 65 |
|
Transportation | 213 |
| — |
| — |
| — |
| — |
| 213 |
|
Industrial | 5 |
| — |
| — |
| — |
| — |
| 5 |
|
Other | 45 |
| — |
| — |
| — |
| — |
| 45 |
|
Total natural gas distribution revenues | 557 |
| — |
| — |
| — |
| — |
| 557 |
|
Wholesale electric revenues | | | | | | |
PPA energy revenues | 208 |
| 35 |
| 17 |
| 3 |
| 163 |
| — |
|
PPA capacity revenues | 109 |
| 25 |
| 13 |
| 1 |
| 81 |
| — |
|
Non-PPA revenues | 53 |
| 3 |
| 1 |
| 89 |
| 68 |
| — |
|
Total wholesale electric revenues | 370 |
| 63 |
| 31 |
| 93 |
| 312 |
| — |
|
Other natural gas revenues | | | | | | |
Wholesale gas services | 444 |
| — |
| — |
| — |
| — |
| 444 |
|
Gas marketing services | 55 |
| — |
| — |
| — |
| — |
| 55 |
|
Other natural gas revenues | 12 |
| — |
| — |
| — |
| — |
| 12 |
|
Total natural gas revenues | 511 |
| — |
| — |
| — |
| — |
| 511 |
|
Other revenues | 238 |
| 37 |
| 95 |
| 4 |
| 3 |
| — |
|
Total revenue from contracts with customers | 5,222 |
| 1,490 |
| 2,069 |
| 310 |
| 315 |
| 1,068 |
|
Other revenue sources(a) | 1,050 |
| 23 |
| 48 |
| 3 |
| 195 |
| 795 |
|
Other adjustments(b) | (1,174 | ) | — |
| — |
| — |
| — |
| (1,174 | ) |
Total operating revenues | $ | 5,098 |
| $ | 1,513 |
| $ | 2,117 |
| $ | 313 |
| $ | 510 |
| $ | 689 |
|
| | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | |
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
Six Months Ended June 30, 2019 | | | | | | |
Operating revenues | | | | | | |
Retail electric revenues | | | | | | |
Residential | $ | 2,818 |
| $ | 1,151 |
| $ | 1,539 |
| $ | 128 |
| $ | — |
| $ | — |
|
Commercial | 2,390 |
| 790 |
| 1,463 |
| 137 |
| — |
| — |
|
Industrial | 1,474 |
| 707 |
| 623 |
| 144 |
| — |
| — |
|
Other | 44 |
| 13 |
| 25 |
| 6 |
| — |
| — |
|
Total retail electric revenues | 6,726 |
| 2,661 |
| 3,650 |
| 415 |
| — |
| — |
|
Natural gas distribution revenues | | | | | | |
Residential | 830 |
| — |
| — |
| — |
| — |
| 830 |
|
Commercial | 235 |
| — |
| — |
| — |
| — |
| 235 |
|
Transportation | 469 |
| — |
| — |
| — |
| — |
| 469 |
|
Industrial | 22 |
| — |
| — |
| — |
| — |
| 22 |
|
Other | 161 |
| — |
| — |
| — |
| — |
| 161 |
|
Total natural gas distribution revenues | 1,717 |
| — |
| — |
| — |
| — |
| 1,717 |
|
| | | | | | |
Wholesale electric revenues | | | | | | |
PPA energy revenues | 398 |
| 67 |
| 28 |
| 5 |
| 314 |
| — |
|
PPA capacity revenues | 217 |
| 52 |
| 27 |
| 2 |
| 163 |
| — |
|
Non-PPA revenues | 108 |
| 62 |
| 3 |
| 164 |
| 109 |
| — |
|
Total wholesale electric revenues | 723 |
| 181 |
| 58 |
| 171 |
| 586 |
| — |
|
Other natural gas revenues | | | | | | |
Wholesale gas services | 1,165 |
| — |
| — |
| — |
| — |
| 1,165 |
|
Gas marketing services | 276 |
| — |
| — |
| — |
| — |
| 276 |
|
Other natural gas revenues | 22 |
| — |
| — |
| — |
| — |
| 22 |
|
Total natural gas revenues | 1,463 |
| — |
| — |
| — |
| — |
| 1,463 |
|
Other revenues | 502 |
| 83 |
| 186 |
| 10 |
| 6 |
| — |
|
Total revenue from contracts with customers | 11,131 |
| 2,925 |
| 3,894 |
| 596 |
| 592 |
| 3,180 |
|
Other revenue sources(a) | 2,413 |
| (4 | ) | 57 |
| 4 |
| 361 |
| 2,017 |
|
Other adjustments(b) | (3,034 | ) | — |
| — |
| — |
| — |
| (3,034 | ) |
Total operating revenues | $ | 10,510 |
| $ | 2,921 |
| $ | 3,951 |
| $ | 600 |
| $ | 953 |
| $ | 2,163 |
|
| |
(a) | Other revenue sources primarily relate to revenues from customers accounted for as derivatives and leases, as well as alternative revenue programs at Southern Company Gas and other cost recovery mechanisms at the traditional electric operating companies. |
| |
(b) | Other adjustments relate to the cost of Southern Company Gas' energy and risk management activities. Wholesale gas services revenues are presented net of the related costs of those activities on the statement of income. See Note (L) under "Southern Company Gas" for additional information on the components of wholesale gas services' operating revenues.
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Contract Balances
The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers at June 30, 2020March 31, 2021 and December 31, 2019:2020:
| | | | | | | | | | | | | | | | | | | | |
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
Accounts Receivable | | | | | | |
As of March 31, 2021 | $ | 2,375 | | $ | 567 | | $ | 679 | | $ | 87 | | $ | 85 | | $ | 778 | |
As of December 31, 2020 | 2,614 | | 632 | | 806 | | 77 | | 112 | | 788 | |
Contract Assets | | | | | | |
As of March 31, 2021 | $ | 106 | | $ | 1 | | $ | 47 | | $ | 0 | | $ | 0 | | $ | 0 | |
As of December 31, 2020 | 158 | | 2 | | 71 | | 0 | | 0 | | 0 | |
Contract Liabilities | | | | | | |
As of March 31, 2021 | $ | 75 | | $ | 4 | | $ | 34 | | $ | 1 | | $ | 1 | | $ | 1 | |
As of December 31, 2020 | 61 | | 6 | | 27 | | 1 | | 1 | | 1 | |
|
| | | | | | | | | | | | | | | | | | |
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
Accounts Receivables | | | | | | |
As of June 30, 2020 | $ | 2,283 |
| $ | 592 |
| $ | 796 |
| $ | 84 |
| $ | 115 |
| $ | 523 |
|
As of December 31, 2019 | 2,413 |
| 586 |
| 688 |
| 79 |
| 97 |
| 749 |
|
Contract Assets | | | | | | |
As of June 30, 2020 | $ | 103 |
| $ | — |
| $ | 54 |
| $ | 1 |
| $ | — |
| $ | — |
|
As of December 31, 2019 | 117 |
| — |
| 69 |
| — |
| — |
| — |
|
Contract Liabilities | | | | | | |
As of June 30, 2020 | $ | 57 |
| $ | 6 |
| $ | 23 |
| $ | — |
| $ | 1 |
| $ | 2 |
|
As of December 31, 2019 | 52 |
| 10 |
| 13 |
| — |
| 1 |
| 1 |
|
As of June 30, 2020March 31, 2021 and December 31, 2019,2020, Georgia Power had contract assets primarily related to unregulated service agreements, where payment is contingent on project completion, and fixed retail customer bill programs, where the payment is contingent upon Georgia Power's continued performance and the customer's continued participation in the program over a one-year contract term. Contract liabilities for Georgia Power relate to cash collections recognized in advance of revenue for certain unregulated service agreements. Alabama Power had contract liabilities for outstanding performance obligations primarily related to pole attachment and extended service agreements. Southern Company's unregulated distributed generation business had $41$55 million and $40$81 million of contract assets and $26$34 million and $28$27 million of contract liabilities at June 30, 2020March 31, 2021 and December 31, 2019,2020, respectively, for outstanding performance obligations.
Revenues recognized by Southern Company in the three and six months ended June 30, 2020,March 31, 2021, which were included in contract liabilities at December 31, 2019,2020, were $11 million and $21 million, respectively, and immaterial for all other applicable Registrants.
Remaining Performance Obligations
The traditional electric operating companies and Southern Power have long-term contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. These contracts primarily relate to PPAs whereby the traditional electric operating companies and Southern Power provide electricity and generation capacity to a customer. The revenue recognized for the delivery of electricity is variable; however, certain PPAs include a fixed payment for fixed generation capacity over the term of the contract. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain fixed price contracts. RevenueRevenues from contracts with customers related to these performance obligations remaining at June 30, 2020March 31, 2021 are expected to be recognized as follows:
|
| | | | | | | | | | | | | | | | | | |
| 2020 (remaining) | 2021 | 2022 | 2023 | 2024 | 2025 and Thereafter |
| (in millions) |
Southern Company | $ | 319 |
| $ | 432 |
| $ | 362 |
| $ | 339 |
| $ | 319 |
| $ | 3,062 |
|
Alabama Power | 12 |
| 33 |
| 31 |
| 24 |
| 7 |
| 5 |
|
Georgia Power | 37 |
| 70 |
| 39 |
| 34 |
| 23 |
| 62 |
|
Southern Power | 156 |
| 290 |
| 292 |
| 282 |
| 290 |
| 3,013 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | |
| 2021 (remaining) | 2022 | 2023 | 2024 | 2025 | Thereafter |
| (in millions) |
Southern Company | $ | 485 | | $ | 408 | | $ | 340 | | $ | 327 | | $ | 307 | | $ | 2,666 | |
Alabama Power | 24 | | 31 | | 24 | | 7 | | 5 | | 0 | |
Georgia Power | 57 | | 51 | | 36 | | 24 | | 21 | | 41 | |
| | | | | | |
Southern Power | 213 | | 287 | | 280 | | 296 | | 280 | | 2,644 | |
Revenue expected to be recognized for performance obligations remaining at June 30, 2020 was March 31, 2021 was immaterial for Mississippi Power.Power and Southern Company Gas.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Lease Income
Lease income for the three and six months ended June 30,March 31, 2021 and 2020 and 2019 is as follows:
|
| | | | | | | | | | | | | | | | | | |
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
For the Three Months Ended June 30, 2020 | | | | | | |
Lease income - interest income on sales-type leases | $ | 3 |
| $ | — |
| $ | — |
| $ | 3 |
| $ | — |
| $ | — |
|
Lease income - operating leases | 47 |
| 6 |
| 15 |
| — |
| 21 |
| 9 |
|
Variable lease income | 126 |
| — |
| — |
| — |
| 136 |
| — |
|
Total lease income | $ | 176 |
| $ | 6 |
| $ | 15 |
| $ | 3 |
| $ | 157 |
| $ | 9 |
|
| | | | | | |
For the Six Months Ended June 30, 2020 | | | | | | |
Lease income - interest income on sales-type leases | $ | 6 |
| $ | — |
| $ | — |
| $ | 5 |
| $ | — |
| $ | — |
|
Lease income - operating leases | 97 |
| 13 |
| 30 |
| — |
| 45 |
| 17 |
|
Variable lease income | 200 |
| — |
| — |
| — |
| 215 |
| — |
|
Total lease income | $ | 303 |
| $ | 13 |
| $ | 30 |
| $ | 5 |
| $ | 260 |
| $ | 17 |
|
| | | | | | |
For the Three Months Ended June 30, 2019 | | | | | | |
Lease income - interest income on sales-type leases | $ | 2 |
| $ | — |
| $ | — |
| $ | 2 |
| $ | — |
| $ | — |
|
Lease income - operating leases | 67 |
| 7 |
| 19 |
| — |
| 44 |
| 9 |
|
Variable lease income | 115 |
| — |
| — |
| — |
| 129 |
| — |
|
Total lease income | $ | 184 |
| $ | 7 |
| $ | 19 |
| $ | 2 |
| $ | 173 |
| $ | 9 |
|
| | | | | | |
For the Six Months Ended June 30, 2019 | | | | | | |
Lease income - interest income on sales-type leases | $ | 5 |
| $ | — |
| $ | — |
| $ | 5 |
| $ | — |
| $ | — |
|
Lease income - operating leases | 139 |
| 13 |
| 39 |
| — |
| 90 |
| 17 |
|
Variable lease income | 182 |
| — |
| — |
| — |
| 204 |
| — |
|
Total lease income | $ | 326 |
| $ | 13 |
| $ | 39 |
| $ | 5 |
| $ | 294 |
| $ | 17 |
|
| | | | | | | | | | | | | | | | | | | | |
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
|
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
For the Three Months Ended March 31, 2021 |
Lease income - interest income on sales-type leases | $ | 3 | | $ | 0 | | $ | 0 | | $ | 3 | | $ | 0 | | $ | 0 | |
Lease income - operating leases | 55 | | 21 | | 10 | | 0 | | 21 | | 9 | |
Variable lease income | 84 | | 0 | | 0 | | 0 | | 90 | | 0 | |
Total lease income | $ | 142 | | $ | 21 | | $ | 10 | | $ | 3 | | $ | 111 | | $ | 9 | |
| | | | | | |
|
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
For the Three Months Ended March 31, 2020 |
Lease income - interest income on sales-type leases | $ | 3 | | $ | 0 | | $ | 0 | | $ | 3 | | $ | 0 | | $ | 0 | |
Lease income - operating leases | 51 | | 6 | | 16 | | 0 | | 24 | | 9 | |
Variable lease income | 74 | | 0 | | 0 | | 0 | | 80 | | 0 | |
Total lease income | $ | 128 | | $ | 6 | | $ | 16 | | $ | 3 | | $ | 104 | | $ | 9 | |
Lease income for Southern Power is included in wholesale revenues. Lease payments received under tolling arrangements and PPAs consist of either scheduled payments or variable payments based on the amount of energy produced by the underlying electric generating units. Lease income for Alabama Power and Southern Power is included in wholesale revenues.
(E) CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS
See Note 7 to the financial statements in Item 8 of the Form 10-K for additional information.
Southern Power
Variable Interest Entities
Southern Power has certain subsidiaries that are determined to be VIEs. Southern Power is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
SP Solar and SP Wind
At June 30, 2020March 31, 2021 and December 31, 2019,2020, SP Solar had total assets of $6.2$6.1 billion, and $6.4 billion, respectively, and total liabilities of $381 million. Noncontrolling$377 million and $387 million, respectively, and noncontrolling interests totaledof $1.1 billion at both June 30, 2020 and December 31, 2019.billion. Cash distributions from SP Solar are allocated 67% to Southern Power and 33% to Global Atlantic in accordance with their partnership interest percentage. Under the terms of the limited partnership agreement, distributions without limited partner consent are limited to available cash and SP Solar is obligated to distribute all such available cash to its partners each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves.
At June 30, 2020March 31, 2021 and December 31, 2019,2020, SP Wind had total assets of $2.4 billion, and $2.5 billion, respectively, total liabilities of $125$171 million and $128$138 million, respectively, and noncontrolling interests of $44$42 million and $45$43 million, respectively. Under the terms of the limited liability agreement, distributions without Class A member consent are limited to available cash and SP Wind is obligated to distribute all such available cash to its members each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves. Cash distributions from SP Wind are generally allocated 60% to Southern Power and 40% to the 3 financial investors in accordance with the limited liability agreement.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Southern Power consolidates both SP Solar and SP Wind, as the primary beneficiary, since it controls the most significant activities of each entity, including operating and maintaining their assets. Certain transfers and sales of the assets in the VIEs are subject to partner consent and the liabilities are non-recourse to the general credit of Southern Power. Liabilities consist of customary working capital items and do not include any long-term debt.
Other Variable Interest Entities
Southern Power has other consolidated VIEs that relate to certain subsidiaries that have either sold noncontrolling interests to tax-equity investors or acquired less than a 100% interest from facility developers. These entities are considered VIEs because the arrangements are structured similar to a limited partnership and the noncontrolling members do not have substantive kick-out rights.
At June 30, 2020March 31, 2021 and December 31, 2019,2020, the other VIEs had total assets of $1.5$1.9 billion and $1.1 billion, respectively, total liabilities of $160$260 million and $104$110 million, respectively, and noncontrolling interests of $557$926 million and $409$454 million, respectively. Under the terms of the partnership agreements, distributions of all available cash are required each month or quarter and additional distributions require partner consent.
Equity Method Investments
At June 30, 2020March 31, 2021 and December 31, 2019,2020, Southern Power had equity method investments in wind and battery storage projects totaling $19$84 million and $28$19 million, respectively.
Southern Company Gas
Equity Method Investments
The carrying amounts of Southern Company Gas' equity method investments as of March 31, 2021 and December 31, 2020 and related income from those investments for the three months ended March 31, 2021 and 2020 were as follows:
| | | | | | | | |
Investment Balance | March 31, 2021 | December 31, 2020 |
| (in millions) |
SNG | $ | 1,164 | | $ | 1,167 | |
PennEast Pipeline(*) | 93 | | 91 | |
Other | 33 | | 32 | |
Total | $ | 1,290 | | $ | 1,290 | |
(*)See Note (C) under "Other Matters – Southern Company Gas" for additional information.
| | | | | | | | | | |
Earnings from Equity Method Investments | | | Three Months Ended March 31, 2021 | Three Months Ended March 31, 2020 |
| | | (in millions) |
SNG | | | $ | 38 | | $ | 37 | |
| | | | |
PennEast Pipeline(a) | | | 2 | | 2 | |
Other(a)(b) | | | 1 | | 4 | |
Total | | | $ | 41 | | $ | 43 | |
(a)Earnings primarily result from AFUDC equity recorded by the project entity.
(b)On March 24, 2020, Southern Company Gas completed the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline.Pipeline and Pivotal LNG. See Note (K)15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
The carrying amounts of Southern Company Gas' equity method investments as of June 30, 2020 and December 31, 2019 and related income from those investments for the three and six months ended June 30, 2020 and 2019 were as follows:
|
| | | | | | |
Investment Balance | June 30, 2020 | December 31, 2019(a) |
| (in millions) |
SNG(b) | $ | 1,189 |
| $ | 1,137 |
|
PennEast Pipeline(c) | 87 |
| 82 |
|
Other | 32 |
| 32 |
|
Total | $ | 1,308 |
| $ | 1,251 |
|
| |
(a) | Excludes investments in Atlantic Coast Pipeline and Pivotal JAX LNG classified as held for sale at December 31, 2019. See Note 15 to the financial statements under "Assets Held for Sale" in Item 8 of the Form 10-K for additional information. |
| |
(b) | Increase primarily relates to a capital contribution, partially offset by the continued amortization of deferred tax assets established upon acquisition. |
| |
(c) | See Note (C) under "Other Matters – Southern Company Gas" for additional information on the PennEast Pipeline. |
|
| | | | | | | | | | | | |
Earnings from Equity Method Investments | Three Months Ended June 30, 2020 | Three Months Ended June 30, 2019 | Six Months Ended June 30, 2020 | Six Months Ended June 30, 2019 |
| (in millions) |
SNG | $ | 28 |
| $ | 32 |
| $ | 65 |
| $ | 74 |
|
Atlantic Coast Pipeline(a)(b) | — |
| 3 |
| 3 |
| 6 |
|
PennEast Pipeline(a) | 1 |
| 1 |
| 3 |
| 3 |
|
Other | 1 |
| (5 | ) | 1 |
| (3 | ) |
Total | $ | 30 |
| $ | 31 |
| $ | 72 |
| $ | 80 |
|
| |
(a) | Amounts primarily result from AFUDC equity recorded by the project entity. |
| |
(b) | On March 24, 2020, Southern Company Gas completed the sale of its interest in Atlantic Coast Pipeline. See Note (K) under "Southern Company Gas" for additional information. |
SNG
Selected financial information of SNG for the three and six months ended June 30, 2020 and 2019 is as follows:
|
| | | | | | | | | | | | |
Income Statement Information | Three Months Ended June 30, 2020 | Three Months Ended June 30, 2019 | Six Months Ended June 30, 2020 | Six Months Ended June 30, 2019 |
| (in millions) |
Revenues | $ | 149 |
| $ | 155 |
| $ | 307 |
| $ | 321 |
|
Operating income | 78 |
| 86 |
| 176 |
| 192 |
|
Net income | 55 |
| 64 |
| 130 |
| 148 |
|
(F) FINANCING
Bank Credit Arrangements
See Note 8 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
At June 30, 2020,March 31, 2021, committed credit arrangements with banks were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expires | | | | | | | | |
Company | 2021 | 2022 | 2023 | 2024 | | | Total | | Unused | | | | | | | | Due within One Year |
| (in millions) |
Southern Company parent | $ | 0 | | $ | 0 | | $ | 0 | | $ | 2,000 | | | | $ | 2,000 | | | $ | 1,999 | | | | | | | | | $ | 0 | |
Alabama Power | 3 | | 525 | | 0 | | 800 | | | | 1,328 | | | 1,328 | | | | | | | | | 3 | |
Georgia Power | 0 | | 0 | | 0 | | 1,750 | | | | 1,750 | | | 1,728 | | | | | | | | | 0 | |
Mississippi Power | 0 | | 150 | | 125 | | 0 | | | | 275 | | | 250 | | | | | | | | | 0 | |
Southern Power(a) | 0 | | 0 | | 0 | | 600 | | | | 600 | | | 568 | | | | | | | | | 0 | |
Southern Company Gas(b) | 0 | | 0 | | 0 | | 1,750 | | | | 1,750 | | | 1,745 | | | | | | | | | 0 | |
SEGCO | 30 | | 0 | | 0 | | 0 | | | | 30 | | | 30 | | | | | | | | | 30 | |
Southern Company | $ | 33 | | $ | 675 | | $ | 125 | | $ | 6,900 | | | | $ | 7,733 | | | $ | 7,648 | | | | | | | | | $ | 33 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expires | | | |
Company | 2020 | 2021 | 2022 | 2023 | 2024 | | Total | | Unused | Due within One Year |
| (in millions) |
Southern Company parent | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | 2,000 |
| | $ | 2,000 |
| | $ | 1,999 |
| $ | — |
|
Alabama Power | 3 |
| — |
| 525 |
| — |
| 800 |
| | 1,328 |
| | 1,328 |
| 3 |
|
Georgia Power | — |
| — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,733 |
| — |
|
Mississippi Power | — |
| — |
| 150 |
| 125 |
| — |
| | 275 |
| | 250 |
| — |
|
Southern Power(a) | — |
| — |
| — |
| — |
| 600 |
| | 600 |
| | 590 |
| — |
|
Southern Company Gas(b) | — |
| — |
| — |
| — |
| 1,750 |
| | 1,750 |
| | 1,745 |
| — |
|
SEGCO | — |
| 30 |
| — |
| — |
| — |
| | 30 |
| | 30 |
| 30 |
|
Southern Company | $ | 3 |
| $ | 30 |
| $ | 675 |
| $ | 125 |
| $ | 6,900 |
| | $ | 7,733 |
| | $ | 7,675 |
| $ | 33 |
|
(a)Does not include Southern Power Company's $75 million and $60 million continuing letter of credit facilities for standby letters of credit expiring in 2023, of which $12 million and $1 million, respectively, was unused at March 31, 2021. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities. | |
(a) | Does not include Southern Power Company's $120 million and $60 million continuing letter of credit facilities for standby letters of credit expiring in 2021 and 2023, respectively, of which $19 million and $60 million, respectively, was unused at June 30, 2020. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities. |
| |
(b) | (b)Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.25 billion of this arrangement. Southern Company Gas' committed credit arrangement also includes $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to this multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. |
As reflected in the table above, in March 2020, Mississippi Power entered into a $125parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.05 billion of this arrangement. Southern Company Gas' committed credit arrangement also includes $700 million revolvingfor which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to this multi-year credit facility that matures in March 2023.arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
These bank credit arrangements, as well as the term loan arrangements of the Registrants, Nicor Gas, and SEGCO, contain covenants that limit debt levels and contain cross-acceleration or, in the case of Southern Power, cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross-default provisions to other indebtedness would trigger an event of default if Southern Power defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross-acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2020,March 31, 2021, the Registrants, Nicor Gas, and SEGCO were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of the Registrants and Nicor Gas, and SEGCO.Gas. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support at June 30, 2020March 31, 2021 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, and $34 million at Mississippi Power). In addition, at June 30, 2020,March 31, 2021, Georgia Power and Mississippi Power had approximately $257$174 million and $50 million, respectively, of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Earnings per Share
For Southern Company, the only differences in computing basic and diluted earnings per share are attributable to awards outstanding under stock-based compensation plans and as a result of stock price volatility in the first six months of 2020, the equity units issued in August 2019. Earnings per share dilution resulting from stock-based
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
compensation plans and the equity units issuance is determined using the treasury stock method. See Note 8 to the financial statements under "Equity Units" in Item 8 of the Form 10-K for information on the August 2019 equity units issuance and Note 12 to the financial statements in Item 8 of the Form 10-K for information on stock-based compensation plans. Shares used to compute diluted earnings per share were as follows:
|
| | | | | | | | |
| Three Months Ended June 30, 2020 | Three Months Ended June 30, 2019 | Six Months Ended June 30, 2020 | Six Months Ended June 30, 2019 |
| (in millions) |
As reported shares | 1,058 |
| 1,044 |
| 1,057 |
| 1,041 |
|
Effect of stock-based compensation | 5 |
| 8 |
| 7 |
| 8 |
|
Effect of equity units | — |
| — |
| 1 |
| — |
|
Diluted shares | 1,063 |
| 1,052 |
| 1,065 |
| 1,049 |
|
| | | | | | | | | | |
| | | Three Months Ended March 31, 2021 | Three Months Ended March 31, 2020 |
| | | (in millions) |
As reported shares | | | 1,060 | | 1,057 | |
Effect of stock-based compensation | | | 6 | | 7 | |
Effect of equity units | | | 0 | | 3 | |
Diluted shares | | | 1,066 | | 1,067 | |
An immaterial number of stock-based compensation awards was not included in the diluted earnings per share calculation because the awards were anti-dilutive for the three and six months ended June 30,March 31, 2021 and 2020. There were 0 such amounts for the three and six months ended June 30, 2019.
(G) INCOME TAXES
See Note 10 to the financial statements in Item 8 of the Form 10-K for additional tax information.
Current and Deferred Income Taxes
Tax Credit and Net Operating Loss Carryforwards
The utilization of each Registrants'Registrant's estimated tax credit and state net operating loss carryforwards and related valuation allowances could be impacted by numerous factors, including the acquisition of additional renewable projects, the purchase of rights to additional PTCs of Plant Vogtle Units 3 and 4 pursuant to certain joint ownership agreements, potential impacts of the COVID-19 pandemic, and changes in taxable income projections.projections, and potential income tax rate changes. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.
Effective Tax Rate
Details of significant changes in the effective tax rate for the applicable Registrants are provided herein.
Southern Company
Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity at the traditional electric operating companies, flowback of excess deferred income taxes at the regulated utilities, and federal income tax benefits from ITCs and PTCs primarily at Southern Power.
Southern Company'sDetails of significant changes in the effective tax rate for the applicable Registrants are provided herein.
Mississippi Power
Mississippi Power's effective tax rate was 9.3%8.4% for the sixthree months ended June 30, 2020March 31, 2021 compared to 33.5%16.2% for the corresponding period in 2019. The effective tax rate decrease was primarily due to the tax impact from the sale of Gulf Power in 2019, as well as an increase in the flowback of excess deferred income taxes in 2020 primarily at Georgia Power. See Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K for additional information.
Georgia Power
Georgia Power's effective tax rate was 4.0% for the six months ended June 30, 2020 compared to 21.7% for the corresponding period in 2019.2020. The effective tax rate decrease was primarily due to an increase in the flowback of excess deferred income taxes beginning in 2020 as authorized in the 2019 ARP, as well as the second quarter 2020 charge to
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
earnings associated with the construction of Plant Vogtle Units 3 and 4. See Note (B) under "Georgia Power – Nuclear Construction" and Note 2 to the financial statements under "Georgia Power" in Item 8 of the Form 10-K for additional information.
Mississippi Power
Mississippi Power's effective tax rate was 10.6% for the six months ended June 30, 2020 compared to 14.0% for the corresponding period in 2019. The effective tax rate decrease was primarily due to an increase in the flowback of excess deferred income taxes inApril 2020 as authorized in the Mississippi Power Rate Case Settlement Agreement. See Note (B)2 to the financial statements under "Mississippi"Mississippi Power – 2019 Base Rate Case" for additional information.
Southern Power
Southern Power's effective tax rate was 10.5% for the six months ended June 30, 2020 compared to a benefit rate of (35.5)% for the corresponding period in 2019. The effective tax rate increase was primarily due to tax benefits resulting from ITCs recognized upon the sale of Plant Nacogdoches in 2019. See Note (K) under "Southern Power" for additional information.
Southern Company Gas
Southern Company Gas' effective tax rate was 21.5% for the six months ended June 30, 2020 compared to 18.0% for the corresponding period in 2019. The effective tax rate increase was primarily due to higher flowback of excess deferred income taxes in 2019, primarily at Atlanta Gas Light as previously authorized by the Georgia PSC, and the reversal of a federal tax valuation allowance in connection with Southern Company Gas' sale of its investment in Triton in 2019. See Notes 2 and 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Southern Power
Southern Power's effective tax benefit rate was (17.3)% for the three months ended March 31, 2021 compared to an effective tax rate of 13.5% for the corresponding period in 2020. The effective tax rate decrease was primarily due to changes in state apportionment methodology resulting from tax legislation enacted by the State of Alabama in February 2021, as well as the tax impact from the sale of Plant Mankato in January 2020. See Note 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K for additional information.
(H) RETIREMENT BENEFITS
The Southern Company system has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at PowerSecure. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). NaN mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2020.2021. The Southern Company system also provides certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis. In addition, the Southern Company system provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund other postretirement trusts to the extent required by their respective regulatory commissions. Southern Company Gas has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.
See Note 11 to the financial statements in Item 8 of the Form 10-K for additional information.
Effective January 1, 2020, Southern Company adopted a change in method of calculating the market-related value of the liability-hedging securities included in its pension plan assets. The market-related value is used to determine the expected return on plan assets component of net periodic pension cost. Southern Company previously used the calculated value approach for all plan assets, which smoothed asset returns and deferred gains and losses by amortizing them into the calculation of the market-related value over five years. Southern Company changed to the fair value approach for liability-hedging securities, which includes measuring the market-related value of that portion of the plan assets at fair value for purposes of determining the expected return on plan assets. The remaining asset classes of plan assets will continue to use the calculated value approach in determining the market-related value. Southern Company considers the fair value approach to be preferable because it results in a current reflection of changes in the value of plan assets in the measurement of net periodic pension cost. Southern Company evaluated the effect of this change in accounting method and deemed it immaterial to the historical and current financial statements of all Registrants and therefore did not account for the change retrospectively. The change in accounting principle was recorded through earnings as a prior period adjustment for the amounts related to the unregulated
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
businesses of Southern Company and Southern Power. Amounts related to the traditional electric operating companies and the natural gas distribution utilities have been reflected as adjustments to regulatory assets as appropriate, consistent with the expected regulatory treatment.
On each Registrant's condensed statements of income, the service cost component of net periodic benefit costs is included in other operations and maintenance expenses and all other components of net periodic benefit costs are included in other income (expense), net. Components of the net periodic benefit costs for the three and six months ended June 30,March 31, 2021 and 2020 and 2019 are presented in the following tables.
|
| | | | | | | | | | | | | | | | | | | | | | | |
Three Months Ended June 30, 2020 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas |
| (in millions) |
Pension Plans |
Service cost | $ | 94 |
| | $ | 22 |
| | $ | 24 |
| | $ | 4 |
| | $ | 2 |
| | $ | 8 |
|
Interest cost | 108 |
| | 25 |
| | 34 |
| | 5 |
| | 2 |
| | 7 |
|
Expected return on plan assets | (275 | ) | | (66 | ) | | (87 | ) | | (12 | ) | | (3 | ) | | (20 | ) |
Amortization: | | | | | | | | | | | |
Prior service costs | — |
| | — |
| | 1 |
| | — |
| | — |
| | — |
|
Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
|
Net (gain)/loss | 67 |
| | 18 |
| | 21 |
| | 3 |
| | — |
| | 3 |
|
Net periodic pension cost (income) | $ | (6 | ) | | $ | (1 | ) | | $ | (7 | ) | | $ | — |
| | $ | 1 |
| | $ | 2 |
|
Postretirement Benefits |
Service cost | $ | 6 |
| | $ | 1 |
| | $ | 2 |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
|
Interest cost | 14 |
| | 3 |
| | 5 |
| | 1 |
| | — |
| | 4 |
|
Expected return on plan assets | (18 | ) | | (7 | ) | | (6 | ) | | (1 | ) | | — |
| | (2 | ) |
Amortization: | | | | | | | | | | | |
Prior service costs | (1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
|
Net (gain)/loss | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) |
Net periodic postretirement benefit cost | $ | 1 |
| | $ | (3 | ) | | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | 3 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Three Months Ended March 31, 2021 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas |
| (in millions) |
Pension Plans |
Service cost | $ | 109 | | | $ | 26 | | | $ | 28 | | | $ | 4 | | | $ | 2 | | | $ | 9 | |
Interest cost | 87 | | | 20 | | | 26 | | | 4 | | | 1 | | | 6 | |
Expected return on plan assets | (298) | | | (72) | | | (94) | | | (14) | | | (3) | | | (21) | |
Amortization: | | | | | | | | | | | |
Prior service costs | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | (1) | |
Regulatory asset | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 4 | |
Net (gain)/loss | 78 | | | 21 | | | 25 | | | 4 | | | 1 | | | 3 | |
Net periodic pension cost (income) | $ | (24) | | | $ | (5) | | | $ | (15) | | | $ | (2) | | | $ | 1 | | | $ | 0 | |
| | | | | | | | | | | |
Postretirement Benefits |
Service cost | $ | 6 | | | $ | 1 | | | $ | 2 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Interest cost | 8 | | | 2 | | | 3 | | | 0 | | | 0 | | | 1 | |
Expected return on plan assets | (19) | | | (7) | | | (7) | | | 0 | | | 0 | | | (2) | |
Amortization: | | | | | | | | | | | |
| | | | | | | | | | | |
Regulatory asset | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 2 | |
Net (gain)/loss | 1 | | | 0 | | | 1 | | | 0 | | | 0 | | | (1) | |
Net periodic postretirement benefit cost (income) | $ | (4) | | | $ | (4) | | | $ | (1) | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
Six Months Ended June 30, 2020 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas |
| (in millions) |
Pension Plans |
Service cost | $ | 188 |
| | $ | 44 |
| | $ | 48 |
| | $ | 8 |
| | $ | 4 |
| | $ | 16 |
|
Interest cost | 216 |
| | 50 |
| | 67 |
| | 10 |
| | 3 |
| | 15 |
|
Expected return on plan assets | (550 | ) | | (132 | ) | | (174 | ) | | (25 | ) | | (6 | ) | | (39 | ) |
Amortization: | | | | | | | | | | | |
Prior service costs | 1 |
| | — |
| | 1 |
| | — |
| | — |
| | (1 | ) |
Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 8 |
|
Net (gain)/loss | 134 |
| | 36 |
| | 43 |
| | 6 |
| | 1 |
| | 5 |
|
Net periodic pension cost (income) | $ | (11 | ) | | $ | (2 | ) | | $ | (15 | ) | | $ | (1 | ) | | $ | 2 |
| | $ | 4 |
|
| | | | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Three Months Ended March 31, 2020 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas |
| (in millions) |
Pension Plans |
Service cost | $ | 94 | | | $ | 22 | | | $ | 24 | | | $ | 4 | | | $ | 2 | | | $ | 8 | |
Interest cost | 108 | | | 25 | | | 33 | | | 5 | | | 1 | | | 8 | |
Expected return on plan assets | (275) | | | (66) | | | (87) | | | (13) | | | (3) | | | (19) | |
Amortization: | | | | | | | | | | | |
Prior service costs | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | (1) | |
Regulatory asset | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 4 | |
Net (gain)/loss | 67 | | | 18 | | | 22 | | | 3 | | | 1 | | | 2 | |
Net periodic pension cost (income) | $ | (5) | | | $ | (1) | | | $ | (8) | | | $ | (1) | | | $ | 1 | | | $ | 2 | |
Postretirement Benefits |
Service cost | $ | 5 | | | $ | 2 | | | $ | 1 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
Interest cost | 13 | | | 3 | | | 5 | | | 0 | | | 0 | | | 2 | |
Expected return on plan assets | (18) | | | (7) | | | (7) | | | 0 | | | 0 | | | (2) | |
Amortization: | | | | | | | | | | | |
| | | | | | | | | | | |
Regulatory asset | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 2 | |
Net (gain)/loss | 1 | | | 0 | | | 1 | | | 0 | | | 0 | | | (1) | |
Net periodic postretirement benefit cost (income) | $ | 1 | | | $ | (2) | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 1 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
Six Months Ended June 30, 2020 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas |
| (in millions) |
Postretirement Benefits |
Service cost | $ | 11 |
| | $ | 3 |
| | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
|
Interest cost | 27 |
| | 6 |
| | 10 |
| | 1 |
| | — |
| | 6 |
|
Expected return on plan assets | (36 | ) | | (14 | ) | | (13 | ) | | (1 | ) | | — |
| | (4 | ) |
Amortization: | | | | | | | | | | | |
Prior service costs | (1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
|
Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 3 |
|
Net (gain)/loss | 1 |
| | — |
| | 1 |
| | — |
| | — |
| | (2 | ) |
Net periodic postretirement benefit cost | $ | 2 |
| | $ | (5 | ) | | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | 4 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
Three Months Ended June 30, 2019 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas |
| (in millions) |
Pension Plans |
Service cost | $ | 73 |
|
| $ | 17 |
|
| $ | 18 |
|
| $ | 3 |
|
| $ | 1 |
|
| $ | 6 |
|
Interest cost | 123 |
|
| 29 |
|
| 39 |
|
| 5 |
|
| 2 |
|
| 9 |
|
Expected return on plan assets | (221 | ) |
| (52 | ) |
| (73 | ) |
| (10 | ) |
| (3 | ) |
| (15 | ) |
Amortization: | | | | | | | | | | | |
Prior service costs | 1 |
|
| 1 |
|
| 1 |
|
| — |
|
| — |
|
| — |
|
Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
|
Net (gain)/loss | 30 |
|
| 9 |
|
| 11 |
|
| 2 |
|
| — |
|
| — |
|
Net periodic pension cost (income) | $ | 6 |
|
| $ | 4 |
|
| $ | (4 | ) |
| $ | — |
|
| $ | — |
|
| $ | 4 |
|
Postretirement Benefits |
Service cost | $ | 4 |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Interest cost | 17 |
| | 4 |
| | 6 |
| | 1 |
| | — |
| | 3 |
|
Expected return on plan assets | (17 | ) | | (7 | ) | | (6 | ) | | (1 | ) | | — |
| | (1 | ) |
Amortization: | | | | | | | | | | | |
Prior service costs | 1 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
|
Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
|
Net (gain)/loss | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) |
Net periodic postretirement benefit cost | $ | 5 |
| | $ | (1 | ) | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | | | | | | | | | | | | |
Six Months Ended June 30, 2019 | Southern Company | | Alabama Power | | Georgia Power | | Mississippi Power | | Southern Power | | Southern Company Gas |
| (in millions) |
Pension Plans |
Service cost | $ | 146 |
| | $ | 34 |
| | $ | 37 |
| | $ | 6 |
| | $ | 3 |
| | $ | 12 |
|
Interest cost | 246 |
| | 57 |
| | 78 |
| | 11 |
| | 3 |
| | 18 |
|
Expected return on plan assets | (442 | ) | | (103 | ) | | (146 | ) | | (20 | ) | | (5 | ) | | (30 | ) |
Amortization: | | | | | | | | | | | |
Prior service costs | 1 |
| | 1 |
| | 1 |
| | — |
| | — |
| | (1 | ) |
Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 7 |
|
Net (gain)/loss | 60 |
| | 18 |
| | 22 |
| | 3 |
| | — |
| | 1 |
|
Net periodic pension cost (income) | $ | 11 |
| | $ | 7 |
| | $ | (8 | ) | | $ | — |
| | $ | 1 |
| | $ | 7 |
|
Postretirement Benefits |
Service cost | $ | 9 |
| | $ | 2 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
Interest cost | 34 |
| | 8 |
| | 13 |
| | 2 |
| | — |
| | 5 |
|
Expected return on plan assets | (33 | ) | | (13 | ) | | (12 | ) | | (1 | ) | | — |
| | (3 | ) |
Amortization: | | | | | | | | | | | |
Prior service costs | 2 |
| | 2 |
| | — |
| | — |
| | — |
| | — |
|
Regulatory asset | — |
| | — |
| | — |
| | — |
| | — |
| | 3 |
|
Net (gain)/loss | (1 | ) | | — |
| | — |
| | — |
| | — |
| | (2 | ) |
Net periodic postretirement benefit cost | $ | 11 |
| | $ | (1 | ) | | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | 4 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
(I) FAIR VALUE MEASUREMENTS
As of June 30, 2020,March 31, 2021, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using: | | |
As of March 31, 2021: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| (in millions) |
Southern Company | | | | | | | | | |
Assets: | | | | | | | | | |
Energy-related derivatives(a) | $ | 372 | | | $ | 179 | | | $ | 34 | | | $ | — | | | $ | 585 | |
Interest rate derivatives | 0 | | | 10 | | | 0 | | | — | | | 10 | |
Foreign currency derivatives | 0 | | | 41 | | | 0 | | | — | | | 41 | |
Investments in trusts:(b)(c) | | | | | | | | | |
Domestic equity | 782 | | | 214 | | | 0 | | | — | | | 996 | |
Foreign equity | 145 | | | 197 | | | 0 | | | — | | | 342 | |
U.S. Treasury and government agency securities | 0 | | | 325 | | | 0 | | | — | | | 325 | |
Municipal bonds | 0 | | | 45 | | | 0 | | | — | | | 45 | |
Pooled funds – fixed income | 0 | | | 18 | | | 0 | | | — | | | 18 | |
Corporate bonds | 5 | | | 436 | | | 0 | | | — | | | 441 | |
Mortgage and asset backed securities | 0 | | | 81 | | | 0 | | | — | | | 81 | |
Private equity | 0 | | | 0 | | | 0 | | | 83 | | | 83 | |
| | | | | | | | | |
Other | 50 | | | 7 | | | 0 | | | — | | | 57 | |
Cash equivalents | 1,121 | | | 11 | | | 0 | | | — | | | 1,132 | |
Other investments | 9 | | | 33 | | | 0 | | | — | | | 42 | |
Total | $ | 2,484 | | | $ | 1,597 | | | $ | 34 | | | $ | 83 | | | $ | 4,198 | |
Liabilities: | | | | | | | | | |
Energy-related derivatives(a) | $ | 359 | | | $ | 158 | | | $ | 6 | | | $ | — | | | $ | 523 | |
| | | | | | | | | |
Foreign currency derivatives | 0 | | | 23 | | | 0 | | | — | | | 23 | |
Contingent consideration | 0 | | | 0 | | | 16 | | | — | | | 16 | |
Total | $ | 359 | | | $ | 181 | | | $ | 22 | | | $ | — | | | $ | 562 | |
| | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using: | | |
As of June 30, 2020: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| (in millions) |
Southern Company | | | | | | | | | |
Assets: | | | | | | | | | |
Energy-related derivatives(a) | $ | 388 |
| | $ | 181 |
| | $ | 143 |
| | $ | — |
| | $ | 712 |
|
Interest rate derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
Investments in trusts:(b)(c) | | | | | | | | | |
Domestic equity | 703 |
| | 128 |
| | — |
| | — |
| | 831 |
|
Foreign equity | 65 |
| | 202 |
| | — |
| | — |
| | 267 |
|
U.S. Treasury and government agency securities | — |
| | 268 |
| | — |
| | — |
| | 268 |
|
Municipal bonds | — |
| | 106 |
| | — |
| | — |
| | 106 |
|
Pooled funds – fixed income | — |
| | 16 |
| | — |
| | — |
| | 16 |
|
Corporate bonds | 19 |
| | 369 |
| | — |
| | — |
| | 388 |
|
Mortgage and asset backed securities | — |
| | 75 |
| | — |
| | — |
| | 75 |
|
Private equity | — |
| | — |
| | — |
| | 61 |
| | 61 |
|
Other | 26 |
| | 3 |
| | — |
| | — |
| | 29 |
|
Cash equivalents | 1,315 |
| | 13 |
| | — |
| | — |
| | 1,328 |
|
Other investments | 9 |
| | 21 |
| | — |
| | — |
| | 30 |
|
Total | $ | 2,525 |
| | $ | 1,405 |
| | $ | 143 |
| | $ | 61 |
| | $ | 4,134 |
|
Liabilities: | | | | | | | | | |
Energy-related derivatives(a) | $ | 468 |
| | $ | 187 |
| | $ | 63 |
| | $ | — |
| | $ | 718 |
|
Interest rate derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
Foreign currency derivatives | — |
| | 49 |
| | — |
| | — |
| | 49 |
|
Contingent consideration | — |
| | — |
| | 19 |
| | — |
| | 19 |
|
Total | $ | 468 |
| | $ | 259 |
| | $ | 82 |
| | $ | — |
| | $ | 809 |
|
| | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using: | | |
As of March 31, 2021: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| (in millions) |
Alabama Power | | | | | | | | | |
Assets: | | | | | | | | | |
Energy-related derivatives | $ | 0 | | | $ | 12 | | | $ | 0 | | | $ | — | | | $ | 12 | |
Nuclear decommissioning trusts:(b) | | | | | | | | | |
Domestic equity | 448 | | | 205 | | | 0 | | | — | | | 653 | |
Foreign equity | 145 | | | 15 | | | 0 | | | — | | | 160 | |
U.S. Treasury and government agency securities | 0 | | | 20 | | | 0 | | | — | | | 20 | |
Municipal bonds | 0 | | | 1 | | | 0 | | | — | | | 1 | |
Corporate bonds | 5 | | | 235 | | | 0 | | | — | | | 240 | |
Mortgage and asset backed securities | 0 | | | 26 | | | 0 | | | — | | | 26 | |
Private equity | 0 | | | 0 | | | 0 | | | 83 | | | 83 | |
Other | 27 | | | 0 | | | 0 | | | — | | | 27 | |
Cash equivalents | 401 | | | 11 | | | 0 | | | — | | | 412 | |
Other investments | 0 | | | 33 | | | 0 | | | — | | | 33 | |
Total | $ | 1,026 | | | $ | 558 | | | $ | 0 | | | $ | 83 | | | $ | 1,667 | |
Liabilities: | | | | | | | | | |
Energy-related derivatives | $ | 0 | | | $ | 4 | | | $ | 0 | | | $ | — | | | $ | 4 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Georgia Power | | | | | | | | | |
Assets: | | | | | | | | | |
Energy-related derivatives | $ | 0 | | | $ | 17 | | | $ | 0 | | | $ | — | | | $ | 17 | |
| | | | | | | | | |
Nuclear decommissioning trusts:(b)(c) | | | | | | | | | |
Domestic equity | 334 | | | 1 | | | 0 | | | — | | | 335 | |
Foreign equity | 0 | | | 179 | | | 0 | | | — | | | 179 | |
U.S. Treasury and government agency securities | 0 | | | 305 | | | 0 | | | — | | | 305 | |
Municipal bonds | 0 | | | 44 | | | 0 | | | — | | | 44 | |
Corporate bonds | 0 | | | 201 | | | 0 | | | — | | | 201 | |
Mortgage and asset backed securities | 0 | | | 55 | | | 0 | | | — | | | 55 | |
Other | 23 | | | 7 | | | 0 | | | — | | | 30 | |
| | | | | | | | | |
Total | $ | 357 | | | $ | 809 | | | $ | 0 | | | $ | — | | | $ | 1,166 | |
Liabilities: | | | | | | | | | |
Energy-related derivatives | $ | 0 | | | $ | 8 | | | $ | 0 | | | $ | — | | | $ | 8 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using: | | |
As of June 30, 2020: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| (in millions) |
Alabama Power | | | | | | | | | |
Assets: | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 11 |
| | $ | — |
| | $ | — |
| | $ | 11 |
|
Nuclear decommissioning trusts:(b) | | | | | | | | |
|
|
Domestic equity | 442 |
| | 117 |
| | — |
| | — |
| | 559 |
|
Foreign equity | 65 |
| | 59 |
| | — |
| | — |
| | 124 |
|
U.S. Treasury and government agency securities | — |
| | 22 |
| | — |
| | — |
| | 22 |
|
Municipal bonds | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Corporate bonds | 19 |
| | 155 |
| | — |
| | — |
| | 174 |
|
Mortgage and asset backed securities | — |
| | 28 |
| | — |
| | — |
| | 28 |
|
Private equity | — |
| | — |
| | — |
| | 61 |
| | 61 |
|
Other | 8 |
| | — |
| | — |
| | — |
| | 8 |
|
Cash equivalents | 692 |
| | 13 |
| | — |
| | — |
| | 705 |
|
Other investments | — |
| | 21 |
| | — |
| | — |
| | 21 |
|
Total | $ | 1,226 |
| | $ | 427 |
| | $ | — |
| | $ | 61 |
| | $ | 1,714 |
|
Liabilities: | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 19 |
| | $ | — |
| | $ | — |
| | $ | 19 |
|
| | | | | | | | | |
Georgia Power | | | | | | | | | |
Assets: | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 10 |
| | $ | — |
| | $ | — |
| | $ | 10 |
|
Nuclear decommissioning trusts:(b)(c) | | | | | | | | | |
Domestic equity | 261 |
| | 1 |
| | — |
| | — |
| | 262 |
|
Foreign equity | — |
| | 141 |
| | — |
| | — |
| | 141 |
|
U.S. Treasury and government agency securities | — |
| | 246 |
| | — |
| | — |
| | 246 |
|
Municipal bonds | — |
| | 105 |
| | — |
| | — |
| | 105 |
|
Corporate bonds | — |
| | 214 |
| | — |
| | — |
| | 214 |
|
Mortgage and asset backed securities | — |
| | 47 |
| | — |
| | — |
| | 47 |
|
Other | 18 |
| | 3 |
| | — |
| | — |
| | 21 |
|
Cash equivalents | 349 |
| | — |
| | — |
| | — |
| | 349 |
|
Total | $ | 628 |
| | $ | 767 |
| | $ | — |
| | $ | — |
| | $ | 1,395 |
|
Liabilities: | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 40 |
| | $ | — |
| | $ | — |
| | $ | 40 |
|
| | | | | | | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using: | | |
As of March 31, 2021: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| (in millions) |
Mississippi Power | | | | | | | | | |
Assets: | | | | | | | | | |
Energy-related derivatives | $ | 0 | | | $ | 11 | | | $ | 0 | | | $ | — | | | $ | 11 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Liabilities: | | | | | | | | | |
Energy-related derivatives | $ | 0 | | | $ | 6 | | | $ | 0 | | | $ | — | | | $ | 6 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Southern Power | | | | | | | | | |
Assets: | | | | | | | | | |
Energy-related derivatives | $ | 0 | | | $ | 1 | | | $ | 0 | | | $ | — | | | $ | 1 | |
Foreign currency derivatives | 0 | | | 41 | | | 0 | | | — | | | 41 | |
Cash equivalents | 115 | | | 0 | | | 0 | | | — | | | 115 | |
Total | $ | 115 | | | $ | 42 | | | $ | 0 | | | $ | — | | | $ | 157 | |
Liabilities: | | | | | | | | | |
Energy-related derivatives | $ | 0 | | | $ | 1 | | | $ | 0 | | | $ | — | | | $ | 1 | |
Foreign currency derivatives | 0 | | | 23 | | | 0 | | | — | | | 23 | |
Contingent consideration | 0 | | | 0 | | | 16 | | | — | | | 16 | |
Total | $ | 0 | | | $ | 24 | | | $ | 16 | | | $ | — | | | $ | 40 | |
| | | | | | | | | |
Southern Company Gas | | | | | | | | | |
Assets: | | | | | | | | | |
Energy-related derivatives(a) | $ | 372 | | | $ | 138 | | | $ | 34 | | | $ | — | | | $ | 544 | |
| | | | | | | | | |
Non-qualified deferred compensation trusts: | | | | | | | | | |
Domestic equity | 0 | | | 8 | | | 0 | | | — | | | 8 | |
Foreign equity | 0 | | | 3 | | | 0 | | | — | | | 3 | |
Pooled funds – fixed income | 0 | | | 18 | | | 0 | | | — | | | 18 | |
| | | | | | | | | |
Cash equivalents and restricted cash | 284 | | | 0 | | | 0 | | | — | | | 284 | |
| | | | | | | | | |
Total | $ | 656 | | | $ | 167 | | | $ | 34 | | | $ | — | | | $ | 857 | |
Liabilities: | | | | | | | | | |
Energy-related derivatives(a) | $ | 359 | | | $ | 139 | | | $ | 6 | | | $ | — | | | $ | 504 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
(a)Excludes cash collateral of $27 million.
(b)Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
(c)Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of March 31, 2021, approximately $34 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
|
| | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements Using: | | |
As of June 30, 2020: | Quoted Prices in Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Net Asset Value as a Practical Expedient (NAV) | | Total |
| (in millions) |
Mississippi Power | | | | | | | | | |
Assets: | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | 6 |
|
Liabilities: | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 22 |
| | $ | — |
| | $ | — |
| | $ | 22 |
|
| | | | | | | | | |
Southern Power | | | | | | | | | |
Assets: | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
Liabilities: | | | | | | | | | |
Energy-related derivatives | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 3 |
|
Foreign currency derivatives | — |
| | 49 |
| | — |
| | — |
| | 49 |
|
Contingent consideration | — |
| | — |
| | 19 |
| | — |
| | 19 |
|
Total | $ | — |
|
| $ | 52 |
|
| $ | 19 |
|
| $ | — |
|
| $ | 71 |
|
| | | | | | | | | |
Southern Company Gas | | | | | | | | | |
Assets: | | | | | | | | | |
Energy-related derivatives(a) | $ | 388 |
| | $ | 152 |
| | $ | 143 |
| | $ | — |
| | $ | 683 |
|
Non-qualified deferred compensation trusts: | | | | | | | | | |
Domestic equity | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
Foreign equity | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Pooled funds – fixed income | — |
| | 16 |
| | — |
| | — |
| | 16 |
|
Cash equivalents and restricted cash | 40 |
| | — |
| | — |
| | — |
| | 40 |
|
Total | $ | 428 |
|
| $ | 180 |
|
| $ | 143 |
|
| $ | — |
|
| $ | 751 |
|
Liabilities: | | | | | | | | | |
Energy-related derivatives(a) | $ | 468 |
| | $ | 103 |
| | $ | 63 |
| | $ | — |
| | $ | 634 |
|
Interest rate derivatives | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
Total | $ | 468 |
|
| $ | 126 |
|
| $ | 63 |
|
| $ | — |
|
| $ | 657 |
|
| |
(a) | Energy-related derivatives exclude cash collateral of $114 million. |
| |
(b) | Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information. |
| |
(c) | Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of June 30, 2020, approximately $45 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds, including reinvested interest and dividends and excluding the funds' expenses, increased (decreased) by the amounts shown in the table below for the three and six months ended June 30, 2020March 31, 2021 and 2019.2020. The changes were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.
|
| | | | | | | | | | | | |
Fair value increases (decreases) | Three Months Ended June 30, 2020 | Three Months Ended June 30, 2019 | Six Months Ended June 30, 2020 | Six Months Ended June 30, 2019 |
| (in millions) |
Southern Company | $ | 223 |
| $ | 75 |
| $ | (23 | ) | $ | 227 |
|
Alabama Power | 124 |
| 38 |
| (42 | ) | 125 |
|
Georgia Power | 99 |
| 37 |
| 19 |
| 102 |
|
| | | | | | | | | | |
Fair value increases (decreases) | | | Three Months Ended March 31, 2021 | Three Months Ended March 31, 2020 |
| | | (in millions) |
Southern Company | | | $ | 39 | | $ | (247) | |
Alabama Power | | | 41 | | (167) | |
Georgia Power | | | (2) | | (80) | |
Valuation Methodologies
The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note (J) for additional information on how these derivatives are used.
For fair value measurements of the investments within the nuclear decommissioning trusts and the non-qualified deferred compensation trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available.
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. See Note 6 to the financial statements under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.
Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Powerit is primarily obligated to make generation-based payments to the seller, which commenced at the commercial operation of the respective facility and continue through 2026. The obligation isobligations are categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate. The fair value of
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.
"Other investments" include investments traded in the open market that have maturities greater than 90 days, which are categorized as Level 2 under Fair Value Measurements and are comprised of corporate bonds, bank certificates of deposit, treasury bonds, and/or agency bonds.
As of June 30, 2020,At March 31, 2021, the fair value measurements of private equity investments held in Alabama Power's nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient totaled $61$83 million and unfunded commitments related to the private equity investments totaled $72$68 million. Private equity investments include high-quality private equity funds across several market sectors and funds that invest in real estate assets. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.
As of June 30, 2020,At March 31, 2021, other financial instruments for which the carrying amount did not equal fair value were as follows:
| | | | | | | | | | | | | | | | | | | | |
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas(*) |
| (in millions) |
Long-term debt, including securities due within one year: | | | | |
Carrying amount | $ | 50,035 | | $ | 8,866 | | $ | 13,220 | | $ | 1,398 | | $ | 4,030 | | $ | 6,588 | |
Fair value | 54,113 | | 9,821 | | 14,291 | | 1,507 | | 4,347 | | 7,264 | |
|
| | | | | | | | | | | | | | | | | | |
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas(*) |
| (in millions) |
Long-term debt, including securities due within one year: | | | | |
Carrying amount | $ | 46,513 |
| $ | 8,519 |
| $ | 12,720 |
| $ | 1,404 |
| $ | 4,097 |
| $ | 5,827 |
|
Fair value | 53,079 |
| 10,008 |
| 15,092 |
| 1,571 |
| 4,423 |
| 6,817 |
|
(*)The long-term debt of Southern Company Gas is recorded at amortized cost, including the fair value adjustments at the effective date of the 2016 merger with Southern Company. Southern Company Gas amortizes the fair value adjustments over the remaining lives of the respective bonds, the latest being through 2043. | |
(*) | The long-term debt of Southern Company Gas is recorded at amortized cost, including the fair value adjustments at the effective date of the 2016 merger with Southern Company. Southern Company Gas amortizes the fair value adjustments over the lives of the respective bonds. |
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to the Registrants.
Commodity Contracts with Level 3 Valuation Inputs
As of June 30, 2020,March 31, 2021, the fair value of Southern Company Gas' Level 3 physical natural gas forward contracts was $80$28 million. Since commodity contracts classified as Level 3 typically include a combination of observable and unobservable components, the changes in fair value may include amounts due in part to observable market factors, or changes to assumptions on the unobservable components. The following table includes transfers to Level 3, which represent the fair value of Southern Company Gas' commodity derivative contracts that include a significant unobservable component for the first time during the period.
|
| | | | | | |
| Three Months Ended June 30, 2020 | Six Months Ended June 30, 2020 |
| (in millions) |
Beginning balance | $ | 76 |
| $ | 14 |
|
Transfers to Level 3 | — |
| 70 |
|
Transfers from Level 3 | — |
| (3 | ) |
Instruments realized or otherwise settled during period | (6 | ) | (7 | ) |
Changes in fair value | 10 |
| 6 |
|
Ending balance | $ | 80 |
| $ | 80 |
|
| | | | | | |
| | Three Months Ended March 31, 2021 |
| | (in millions) |
Beginning balance | | $ | 28 | |
| | |
| | |
Instruments realized or otherwise settled during period | | (2) | |
Changes in fair value | | 2 | |
Ending balance | | $ | 28 | |
Changes in fair value of Level 3 instruments represent changes in gains and losses for the periods that are reported on Southern Company Gas' statements of income in natural gas revenues.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
The valuation of certain commodity contracts requires the use of certain unobservable inputs. All forward pricing used in the valuation of such contracts is directly based on third-party market data, such as broker quotes and exchange settlements, when that data is available. If third-party market data is not available, then industry standard
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
methodologies are used to develop inputs that maximize the use of relevant observable inputs and minimize the use of unobservable inputs. Observable inputs, including some forward prices used for determining fair value, reflect the best available market information. Unobservable inputs are updated using industry standard techniques such as extrapolation, combining observable forward inputs supplemented by historical market and other relevant data. Level 3 physical natural gas forward contracts include unobservable forward price inputs (ranging from $(0.91)$(0.07) to $0.99$0.30 per mmBtu). Forward price increases (decreases) as of June 30, 2020March 31, 2021 would have resulted in higher (lower) values on a net basis.
(J) DERIVATIVES
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Southern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with the classification of the hedged interest or principal, respectively. See Note 1 to the financial statements under "Financial Instruments" in Item 8 of the Form 10-K for additional information.
Energy-Related Derivatives
The traditional electric operating companies, Southern Power, and Southern Company Gas enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which are expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.
Southern Company Gas also enters into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in operating revenues.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Energy-related derivative contracts are accounted for under one of three methods:
| |
• | Regulatory Hedges — Energy-related derivative contracts designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.
|
| |
• | Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in accumulated OCI before being recognized in the statements of income in the same period and in the same income statement line item as the earnings effect of the hedged transactions.
|
| |
• | Not Designated —•Regulatory Hedges – Energy-related derivative contracts designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through an approved cost recovery mechanism. •Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in accumulated OCI before being recognized in the statements of income in the same period and in the same income statement line item as the earnings effect of the hedged transactions. •Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. |
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
At June 30, 2020,March 31, 2021, the net volume of energy-related derivative contracts for natural gas positions, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:
| | | | | | | | | | | | | | | | | |
| Net Purchased mmBtu | | Longest Hedge Date | | Longest Non-Hedge Date |
| (in millions) | | | | |
Southern Company(*) | 907 | | 2030 | | 2031 |
Alabama Power | 73 | | 2024 | | — |
Georgia Power | 125 | | 2024 | | — |
Mississippi Power | 85 | | 2024 | | — |
Southern Power | 9 | | 2030 | | 2021 |
Southern Company Gas(*) | 615 | | 2023 | | 2031 |
|
| | | | | |
| Net Purchased mmBtu | | Longest Hedge Date | | Longest Non-Hedge Date |
| (in millions) | | | | |
Southern Company(*) | 944 | | 2024 | | 2031 |
Alabama Power | 85 | | 2024 | | — |
Georgia Power | 152 | | 2023 | | — |
Mississippi Power | 91 | | 2024 | | — |
Southern Power | 15 | | 2022 | | 2021 |
Southern Company Gas(*) | 601 | | 2022 | | 2031 |
| |
(*) | (*)Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 4.6 billion mmBtu and short natural gas positions of 4.0 billion mmBtu as of June 30, 2020, which is also included in Southern Company's total volume. |
At June 30, 2020, the net volume of long natural gas positions of 4.4 billion mmBtu and short natural gas positions of 3.8 billion mmBtu as of March 31, 2021, which is also included in Southern Power's energy-related derivative contracts for power to be sold was 1 million MWHs, all of which expire in 2020.Company's total volume.
In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess natural gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 1639 million mmBtu for Southern Company, which includes 410 million mmBtu for Alabama Power, 512 million mmBtu for Georgia Power, 25 million mmBtu for Mississippi Power, and 512 million mmBtu for Southern Power.
For cash flow hedges of energy-related derivatives, the estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to earnings for the 12-month period ending June 30, 2021March 31, 2022 are immaterial for all Registrants.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Interest Rate Derivatives
Southern Company and certain subsidiaries may enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
At June 30, 2020,March 31, 2021, the following interest rate derivatives were outstanding:
|
| | | | | | | | | | | |
| Notional Amount | | Interest Rate Received | Weighted Average Interest Rate Paid | Hedge Maturity Date | | Fair Value Gain (Loss) at June 30, 2020 |
| (in millions) | | | | | | (in millions) |
Cash Flow Hedges of Forecasted Debt | | | | | | |
Southern Company Gas | $ | 200 |
| | 3-month LIBOR | 1.81% | September 2030 | | $ | (23 | ) |
Cash Flow Hedges of Existing Debt | | | | | | |
Mississippi Power | 60 |
| | 1-month LIBOR | 0.58% | December 2021 | | — |
|
Fair Value Hedges of Existing Debt | | | | | | |
Southern Company parent | 1,500 |
| | 2.35% | 1-month LIBOR + 0.87% | July 2021 | | 23 |
|
Southern Company | $ | 1,760 |
| | | | | | $ | — |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Notional Amount | | Interest Rate Received | Weighted Average Interest Rate Paid | Hedge Maturity Date | | Fair Value Gain (Loss) at March 31, 2021 |
| (in millions) | | | | | | (in millions) |
| | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Cash Flow Hedges of Existing Debt | | | | | | |
Mississippi Power | $ | 60 | | | 1-month LIBOR | 0.58% | December 2021 | | $ | 0 | |
Fair Value Hedges of Existing Debt | | | | | | |
Southern Company parent | 1,500 | | | 2.35% | 1-month LIBOR + 0.87% | July 2021 | | 10 | |
| | | | | | | |
| | | | | | | |
Southern Company | $ | 1,560 | | | | | | | $ | 10 | |
TheFor cash flow hedge interest rate derivatives, the estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from accumulated OCI to interest expense for the 12-month period ending June 30, 2021March 31, 2022 total $(25) million for Southern Company and are immaterial for all other Registrants. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2046 for the Southern Company parent entity, 2035 for Alabama Power, 2044 for Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.
Foreign Currency Derivatives
Southern Company and certain subsidiaries, including Southern Power, may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
At June 30, 2020,March 31, 2021, the following foreign currency derivatives were outstanding:
|
| | | | | | | | | | | | |
| Pay Notional | Pay Rate | Receive Notional | Receive Rate | Hedge Maturity Date | Fair Value Gain (Loss) at June 30, 2020 |
| (in millions) | | (in millions) | | | (in millions) |
Cash Flow Hedges of Existing Debt | | | | | |
Southern Power | $ | 677 |
| 2.95% | € | 600 |
| 1.00% | June 2022 | $ | (18 | ) |
Southern Power | 564 |
| 3.78% | 500 |
| 1.85% | June 2026 | (31 | ) |
Total | $ | 1,241 |
| | € | 1,100 |
| | | $ | (49 | ) |
| | | | | | | | | | | | | | | | | | | | |
| Pay Notional | Pay Rate | Receive Notional | Receive Rate | Hedge Maturity Date | Fair Value Gain (Loss) at March 31, 2021 |
| (in millions) | | (in millions) | | | (in millions) |
Cash Flow Hedges of Existing Debt | | | | | |
Southern Power | $ | 677 | | 2.95% | € | 600 | | 1.00% | June 2022 | $ | 9 | |
Southern Power | 564 | | 3.78% | 500 | | 1.85% | June 2026 | 9 | |
Total | $ | 1,241 | | | € | 1,100 | | | | $ | 18 | |
The estimated pre-tax gains (losses) related to Southern Power's foreign currency derivatives expected to be reclassified from accumulated OCI to earnings for the 12-month period ending June 30, 2021March 31, 2022 are $(24)$2 million.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Derivative Financial Statement Presentation and Amounts
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas enter into derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. The fair value amounts of derivative assets and liabilities on the balance sheet are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:
| | | | | | | | | | | | | | |
| As of March 31, 2021 | As of December 31, 2020 |
Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) | (in millions) |
Southern Company | | | | |
Derivatives designated as hedging instruments for regulatory purposes | | | | |
Energy-related derivatives: | | | | |
Assets from risk management activities/Other current liabilities | $ | 30 | | $ | 4 | | $ | 24 | | $ | 11 | |
Other deferred charges and assets/Other deferred credits and liabilities | 16 | | 15 | | 18 | | 19 | |
| | | | |
| | | | |
Total derivatives designated as hedging instruments for regulatory purposes | $ | 46 | | $ | 19 | | $ | 42 | | $ | 30 | |
Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
Energy-related derivatives: | | | | |
Assets from risk management activities/Other current liabilities | $ | 2 | | $ | 1 | | $ | 3 | | $ | 5 | |
| | | | |
Interest rate derivatives: | | | | |
Assets from risk management activities/Other current liabilities | 10 | | 0 | | 20 | | 0 | |
| | | | |
Foreign currency derivatives: | | | | |
Assets from risk management activities/Other current liabilities | 0 | | 23 | | 0 | | 23 | |
Other deferred charges and assets/Other deferred credits and liabilities | 41 | | 0 | | 87 | | 0 | |
Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 53 | | $ | 24 | | $ | 110 | | $ | 28 | |
Derivatives not designated as hedging instruments | | | | |
Energy-related derivatives: | | | | |
Assets from risk management activities/Other current liabilities | $ | 265 | | $ | 265 | | $ | 388 | | $ | 331 | |
Other deferred charges and assets/Other deferred credits and liabilities | 272 | | 237 | | 270 | | 232 | |
Total derivatives not designated as hedging instruments | $ | 537 | | $ | 502 | | $ | 658 | | $ | 563 | |
Gross amounts recognized | $ | 636 | | $ | 545 | | $ | 810 | | $ | 621 | |
Gross amounts offset(a) | (450) | | (477) | | (529) | | (557) | |
Net amounts recognized in the Balance Sheets(b) | $ | 186 | | $ | 68 | | $ | 281 | | $ | 64 | |
| | | | |
|
| | | | | | | | | | | | |
| As of June 30, 2020 | As of December 31, 2019 |
Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) | (in millions) |
Southern Company | | | | |
Derivatives designated as hedging instruments for regulatory purposes | | | | |
Energy-related derivatives: | | | | |
Other current assets/Other current liabilities | $ | 19 |
| $ | 64 |
| $ | 3 |
| $ | 70 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 13 |
| 28 |
| 6 |
| 44 |
|
Total derivatives designated as hedging instruments for regulatory purposes | $ | 32 |
| $ | 92 |
| $ | 9 |
| $ | 114 |
|
Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
Energy-related derivatives: | | | | |
Other current assets/Other current liabilities | $ | 3 |
| $ | 6 |
| $ | 1 |
| $ | 6 |
|
Interest rate derivatives: | | | | |
Other current assets/Other current liabilities | 12 |
| 23 |
| 2 |
| 23 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 10 |
| — |
| — |
| 1 |
|
Foreign currency derivatives: | | | | |
Other current assets/Other current liabilities | — |
| 24 |
| — |
| 24 |
|
Other deferred charges and assets/Other deferred credits and liabilities | — |
| 25 |
| 16 |
| — |
|
Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 25 |
| $ | 78 |
| $ | 19 |
| $ | 54 |
|
Derivatives not designated as hedging instruments | | | | |
Energy-related derivatives: | | | | |
Other current assets/Other current liabilities | $ | 361 |
| $ | 367 |
| $ | 461 |
| $ | 358 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 316 |
| 253 |
| 207 |
| 225 |
|
Total derivatives not designated as hedging instruments | $ | 677 |
| $ | 620 |
| $ | 668 |
| $ | 583 |
|
Gross amounts recognized | $ | 734 |
| $ | 790 |
| $ | 696 |
| $ | 751 |
|
Gross amounts offset(a) | (520 | ) | (634 | ) | (463 | ) | (562 | ) |
Net amounts recognized in the Balance Sheets(b) | $ | 214 |
| $ | 156 |
| $ | 233 |
| $ | 189 |
|
| | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | |
| As of March 31, 2021 | As of December 31, 2020 |
Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) | (in millions) |
Alabama Power | | | | |
Derivatives designated as hedging instruments for regulatory purposes | | | | |
Energy-related derivatives: | | | | |
Other current assets/Other current liabilities | $ | 7 | | $ | 0 | | $ | 7 | | $ | 2 | |
Other deferred charges and assets/Other deferred credits and liabilities | 5 | | 4 | | 5 | | 5 | |
Total derivatives designated as hedging instruments for regulatory purposes | $ | 12 | | $ | 4 | | $ | 12 | | $ | 7 | |
Gross amounts recognized | $ | 12 | | $ | 4 | | $ | 12 | | $ | 7 | |
Gross amounts offset | (4) | | (4) | | (7) | | (7) | |
Net amounts recognized in the Balance Sheets | $ | 8 | | $ | 0 | | $ | 5 | | $ | 0 | |
| | | | |
Georgia Power | | | | |
Derivatives designated as hedging instruments for regulatory purposes | | | | |
Energy-related derivatives: | | | | |
Other current assets/Other current liabilities | $ | 11 | | $ | 2 | | $ | 7 | | $ | 5 | |
Other deferred charges and assets/Other deferred credits and liabilities | 6 | | 6 | | 8 | | 8 | |
Total derivatives designated as hedging instruments for regulatory purposes | $ | 17 | | $ | 8 | | $ | 15 | | $ | 13 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
Gross amounts recognized | $ | 17 | | $ | 8 | | $ | 15 | | $ | 13 | |
Gross amounts offset | (7) | | (7) | | (12) | | (12) | |
Net amounts recognized in the Balance Sheets | $ | 10 | | $ | 1 | | $ | 3 | | $ | 1 | |
| | | | |
Mississippi Power | | | | |
Derivatives designated as hedging instruments for regulatory purposes | | | | |
Energy-related derivatives: | | | | |
Other current assets/Other current liabilities | $ | 6 | | $ | 1 | | $ | 4 | | $ | 3 | |
Other deferred charges and assets/Other deferred credits and liabilities | 5 | | 5 | | 5 | | 6 | |
Total derivatives designated as hedging instruments for regulatory purposes | $ | 11 | | $ | 6 | | $ | 9 | | $ | 9 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
Gross amounts recognized | $ | 11 | | $ | 6 | | $ | 9 | | $ | 9 | |
Gross amounts offset | (5) | | (5) | | (7) | | (7) | |
Net amounts recognized in the Balance Sheets | $ | 6 | | $ | 1 | | $ | 2 | | $ | 2 | |
| | | | |
|
| | | | | | | | | | | | |
| As of June 30, 2020 | As of December 31, 2019 |
Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) | (in millions) |
Alabama Power | | | | |
Derivatives designated as hedging instruments for regulatory purposes | | | | |
Energy-related derivatives: | | | | |
Other current assets/Other current liabilities | $ | 7 |
| $ | 12 |
| $ | 2 |
| $ | 14 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 4 |
| 7 |
| 2 |
| 10 |
|
Total derivatives designated as hedging instruments for regulatory purposes | $ | 11 |
| $ | 19 |
| $ | 4 |
| $ | 24 |
|
Gross amounts recognized | $ | 11 |
| $ | 19 |
| $ | 4 |
| $ | 24 |
|
Gross amounts offset | (8 | ) | (8 | ) | (2 | ) | (2 | ) |
Net amounts recognized in the Balance Sheets | $ | 3 |
| $ | 11 |
| $ | 2 |
| $ | 22 |
|
| | | | |
Georgia Power | | | | |
Derivatives designated as hedging instruments for regulatory purposes | | | | |
Energy-related derivatives: | | | | |
Other current assets/Other current liabilities | $ | 5 |
| $ | 28 |
| $ | 1 |
| $ | 32 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 5 |
| 12 |
| 3 |
| 21 |
|
Total derivatives designated as hedging instruments for regulatory purposes | $ | 10 |
| $ | 40 |
| $ | 4 |
| $ | 53 |
|
Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
Interest rate derivatives: | | | | |
Other current assets/Other current liabilities | $ | — |
| $ | — |
| $ | — |
| $ | 17 |
|
Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | — |
| $ | — |
| $ | — |
| $ | 17 |
|
Gross amounts recognized | $ | 10 |
| $ | 40 |
| $ | 4 |
| $ | 70 |
|
Gross amounts offset | (10 | ) | (10 | ) | (3 | ) | (3 | ) |
Net amounts recognized in the Balance Sheets | $ | — |
| $ | 30 |
| $ | 1 |
| $ | 67 |
|
| | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | | | | | |
| As of March 31, 2021 | As of December 31, 2020 |
Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) | (in millions) |
Southern Power | | | | |
Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
Energy-related derivatives: | | | | |
Other current assets/Other current liabilities | $ | 1 | | $ | 0 | | $ | 2 | | $ | 2 | |
| | | | |
Foreign currency derivatives: | | | | |
Other current assets/Other current liabilities | 0 | | 23 | | 0 | | 23 | |
Other deferred charges and assets/Other deferred credits and liabilities | 41 | | 0 | | 87 | | 0 | |
Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 42 | | $ | 23 | | $ | 89 | | $ | 25 | |
Derivatives not designated as hedging instruments | | | | |
Energy-related derivatives: | | | | |
Other current assets/Other current liabilities | $ | 0 | | $ | 0 | | $ | 0 | | $ | 1 | |
| | | | |
| | | | |
| | | | |
Total derivatives not designated as hedging instruments | $ | 0 | | $ | 0 | | $ | 0 | | $ | 1 | |
| | | | |
| | | | |
Net amounts recognized in the Balance Sheets | $ | 42 | | $ | 23 | | $ | 89 | | $ | 26 | |
| | | | |
Southern Company Gas | | | | |
Derivatives designated as hedging instruments for regulatory purposes | | | | |
Energy-related derivatives: | | | | |
Assets from risk management activities/Other current liabilities | $ | 6 | | $ | 1 | | $ | 6 | | $ | 1 | |
| | | | |
Total derivatives designated as hedging instruments for regulatory purposes | $ | 6 | | $ | 1 | | $ | 6 | | $ | 1 | |
Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
Energy-related derivatives: | | | | |
Assets from risk management activities/Other current liabilities | $ | 1 | | $ | 1 | | $ | 1 | | $ | 3 | |
| | | | |
| | | | |
| | | | |
| | | | |
Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 1 | | $ | 1 | | $ | 1 | | $ | 3 | |
Derivatives not designated as hedging instruments | | | | |
Energy-related derivatives: | | | | |
Assets from risk management activities/Other current liabilities | $ | 265 | | $ | 265 | | $ | 388 | | $ | 330 | |
Other deferred charges and assets/Other deferred credits and liabilities | 272 | | 237 | | 270 | | 232 | |
Total derivatives not designated as hedging instruments | $ | 537 | | $ | 502 | | $ | 658 | | $ | 562 | |
Gross amounts of recognized | $ | 544 | | $ | 504 | | $ | 665 | | $ | 566 | |
Gross amounts offset(a) | (434) | | (461) | | (503) | | (531) | |
Net amounts recognized in the Balance Sheets(b) | $ | 110 | | $ | 43 | | $ | 162 | | $ | 35 | |
(a)Gross amounts offset include cash collateral held on deposit in broker margin accounts of $27 million and $28 million as of March 31, 2021 and December 31, 2020, respectively.
(b)Net amounts of derivative instruments outstanding exclude immaterial premium and intrinsic value associated with weather derivatives for both periods presented.
|
| | | | | | | | | | | | |
| As of June 30, 2020 | As of December 31, 2019 |
Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) | (in millions) |
Mississippi Power | | | | |
Derivatives designated as hedging instruments for regulatory purposes | | | | |
Energy-related derivatives: | | | | |
Other current assets/Other current liabilities | $ | 3 |
| $ | 13 |
| $ | — |
| $ | 15 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 3 |
| 9 |
| 1 |
| 12 |
|
Total derivatives designated as hedging instruments for regulatory purposes | $ | 6 |
| $ | 22 |
| $ | 1 |
| $ | 27 |
|
Gross amounts recognized | $ | 6 |
| $ | 22 |
| $ | 1 |
| $ | 27 |
|
Gross amounts offset | (6 | ) | (6 | ) | (1 | ) | (1 | ) |
Net amounts recognized in the Balance Sheets | $ | — |
| $ | 16 |
| $ | — |
| $ | 26 |
|
| | | | |
Southern Power | | | | |
Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
Energy-related derivatives: | | | | |
Other current assets/Other current liabilities | $ | 2 |
| $ | 3 |
| $ | 1 |
| $ | 2 |
|
Foreign currency derivatives: | | | | |
Other current assets/Other current liabilities | — |
| 24 |
| — |
| 24 |
|
Other deferred charges and assets/Other deferred credits and liabilities | — |
| 25 |
| 16 |
| — |
|
Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 2 |
| $ | 52 |
| $ | 17 |
| $ | 26 |
|
Derivatives not designated as hedging instruments | | | | |
Energy-related derivatives: | | | | |
Other current assets/Other current liabilities | $ | — |
| $ | — |
| $ | 2 |
| $ | 1 |
|
Total derivatives not designated as hedging instruments | $ | — |
| $ | — |
| $ | 2 |
| $ | 1 |
|
Gross amounts recognized | $ | 2 |
| $ | 52 |
| $ | 19 |
| $ | 27 |
|
Gross amounts offset | (1 | ) | (1 | ) | — |
| — |
|
Net amounts recognized in the Balance Sheets | $ | 1 |
| $ | 51 |
| $ | 19 |
| $ | 27 |
|
| | | | |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
|
| | | | | | | | | | | | |
| As of June 30, 2020 | As of December 31, 2019 |
Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities |
| (in millions) | (in millions) |
Southern Company Gas | | | | |
Derivatives designated as hedging instruments for regulatory purposes | | | | |
Energy-related derivatives: | | | | |
Assets from risk management activities/Liabilities from risk management activities-current | $ | 4 |
| $ | 11 |
| $ | — |
| $ | 9 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 1 |
| — |
| — |
| 1 |
|
Total derivatives designated as hedging instruments for regulatory purposes | $ | 5 |
| $ | 11 |
| $ | — |
| $ | 10 |
|
Derivatives designated as hedging instruments in cash flow and fair value hedges | | | | |
Energy-related derivatives: | | | | |
Assets from risk management activities/Liabilities from risk management activities-current | $ | 1 |
| $ | 3 |
| $ | — |
| $ | 4 |
|
Interest rate derivatives: | | | | |
Assets from risk management activities/Liabilities from risk management activities-current | — |
| 23 |
| 2 |
| — |
|
Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 1 |
| $ | 26 |
| $ | 2 |
| $ | 4 |
|
Derivatives not designated as hedging instruments | | | | |
Energy-related derivatives: | | | | |
Assets from risk management activities/Liabilities from risk management activities-current | $ | 361 |
| $ | 367 |
| $ | 459 |
| $ | 357 |
|
Other deferred charges and assets/Other deferred credits and liabilities | 316 |
| 253 |
| 207 |
| 225 |
|
Total derivatives not designated as hedging instruments | $ | 677 |
| $ | 620 |
| $ | 666 |
| $ | 582 |
|
Gross amounts of recognized | $ | 683 |
| $ | 657 |
| $ | 668 |
| $ | 596 |
|
Gross amounts offset(a) | (495 | ) | (609 | ) | (456 | ) | (555 | ) |
Net amounts recognized in the Balance Sheets(b) | $ | 188 |
| $ | 48 |
| $ | 212 |
| $ | 41 |
|
| |
(a) | Gross amounts offset include cash collateral held on deposit in broker margin accounts of $114 million and $99 million as of June 30, 2020 and December 31, 2019, respectively. |
| |
(b) | Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $4 million as of December 31, 2019. |
Energy-relatedThe traditional electric operating companies had immaterial energy-related derivatives not designated as hedging instruments were immaterial for the traditional electric operating companies at June 30, 2020March 31, 2021 and no such instruments at December 31, 2020.
At March 31, 2021 and December 31, 2019.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
At June 30, 2020, and December 31, 2019, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:
| | Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet | Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet | Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet |
Derivative Category and Balance Sheet Location | Southern Company(*) | Alabama Power | Georgia Power | Mississippi Power | Southern Company Gas(*) | Derivative Category and Balance Sheet Location | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Company Gas |
| (in millions) | | (in millions) |
At June 30, 2020: | | |
At March 31, 2021: | | At March 31, 2021: | |
Energy-related derivatives: | | Energy-related derivatives: | |
Other regulatory assets, current | $ | (42 | ) | $ | (8 | ) | $ | (23 | ) | $ | (10 | ) | $ | (1 | ) | |
| Other regulatory assets, deferred | | Other regulatory assets, deferred | $ | (2) | | $ | 0 | | $ | (1) | | $ | (1) | | $ | 0 | |
| Other regulatory liabilities, current | | Other regulatory liabilities, current | 24 | | 7 | | 9 | | 5 | | 3 | |
Other regulatory liabilities, deferred | | Other regulatory liabilities, deferred | 3 | | 1 | | 1 | | 1 | | 0 | |
Total energy-related derivative gains (losses) | | Total energy-related derivative gains (losses) | $ | 25 | | $ | 8 | | $ | 9 | | $ | 5 | | $ | 3 | |
| At December 31, 2020: | | At December 31, 2020: | |
Energy-related derivatives: | | Energy-related derivatives: | |
| Other regulatory assets, deferred | (16 | ) | (3 | ) | (7 | ) | (6 | ) | — |
| Other regulatory assets, deferred | $ | (2) | | $ | 0 | | $ | (1) | | $ | (1) | | $ | 0 | |
Other regulatory liabilities, current | 10 |
| 3 |
| — |
| — |
| 7 |
| Other regulatory liabilities, current | 12 | | 5 | | 2 | | 1 | | 4 | |
Other regulatory liabilities, deferred | | Other regulatory liabilities, deferred | 2 | | 1 | | 1 | | 0 | | 0 | |
Total energy-related derivative gains (losses) | $ | (48 | ) | $ | (8 | ) | $ | (30 | ) | $ | (16 | ) | $ | 6 |
| Total energy-related derivative gains (losses) | $ | 12 | | $ | 6 | | $ | 2 | | $ | 0 | | $ | 4 | |
| | |
At December 31, 2019: | | |
Energy-related derivatives: | | |
Other regulatory assets, current | $ | (63 | ) | $ | (14 | ) | $ | (31 | ) | $ | (15 | ) | $ | (3 | ) | |
Other regulatory assets, deferred | (37 | ) | (8 | ) | (18 | ) | (11 | ) | — |
| |
Other regulatory liabilities, current | 6 |
| 2 |
| — |
| — |
| 4 |
| |
Total energy-related derivative gains (losses) | $ | (94 | ) | $ | (20 | ) | $ | (49 | ) | $ | (26 | ) | $ | 1 |
| |
| |
(*) | Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $12 million and $11 million at June 30, 2020 and December 31, 2019, respectively. |
For the three and six months ended June 30,March 31, 2021 and 2020, and 2019, the pre-tax effects of cash flow hedge accounting on accumulated OCI were as follows:
|
| | | | | | | | | | | | |
Gain (Loss) Recognized in OCI on Derivative | For the Three Months Ended June 30, | For the Six Months Ended June 30, |
2020 | 2019 | 2020 | 2019 |
| (in millions) | (in millions) |
Southern Company | | | | |
Energy-related derivatives | $ | (2 | ) | $ | (6 | ) | $ | (6 | ) | $ | (6 | ) |
Interest rate derivatives | (1 | ) | (37 | ) | (28 | ) | (37 | ) |
Foreign currency derivatives | 17 |
| (1 | ) | (65 | ) | (39 | ) |
Total | $ | 14 |
| $ | (44 | ) | $ | (99 | ) | $ | (82 | ) |
Georgia Power | | | | |
Interest rate derivatives | $ | — |
| $ | (37 | ) | $ | (3 | ) | $ | (37 | ) |
Southern Power | | | | |
Energy-related derivatives | $ | (2 | ) | $ | (2 | ) | $ | (2 | ) | $ | (2 | ) |
Foreign currency derivatives | $ | 17 |
| $ | (1 | ) | (65 | ) | (39 | ) |
Total | $ | 15 |
| $ | (3 | ) | $ | (67 | ) | $ | (41 | ) |
Southern Company Gas | | | | |
Energy-related derivatives | $ | — |
| $ | (4 | ) | $ | (4 | ) | $ | (4 | ) |
Interest rate derivatives | (1 | ) | — |
| (25 | ) | — |
|
Total | $ | (1 | ) | $ | (4 | ) | $ | (29 | ) | $ | (4 | ) |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
| | | | | | | | | | |
Gain (Loss) Recognized in OCI on Derivative | For the Three Months Ended March 31, | |
2021 | 2020 | | |
| (in millions) | |
Southern Company | | | | |
Energy-related derivatives | $ | 5 | | $ | (4) | | | |
Interest rate derivatives | 3 | | (26) | | | |
Foreign currency derivatives | (47) | | (83) | | | |
Total | $ | (39) | | $ | (113) | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
Southern Power | | | | |
Energy-related derivatives | $ | 4 | | $ | 0 | | | |
| | | | |
Foreign currency derivatives | (47) | | (83) | | | |
Total | $ | (43) | | $ | (83) | | | |
Southern Company Gas | | | | |
Energy-related derivatives | $ | 1 | | $ | (4) | | | |
Interest rate derivatives | 0 | | (23) | | | |
Total | $ | 1 | | $ | (27) | | | |
For the three and six months ended June 30,March 31, 2021 and 2020, and 2019, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for the other Registrants.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
For the three
and six months ended
June 30,March 31, 2021 and 2020,
and 2019, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows:
|
| | | | | | | | | | | | | |
| Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships | For the Three Months Ended June 30, | For the Six Months Ended June 30, |
|
| 2020 | 2019 | 2020 | 2019 |
| | (in millions) | (in millions) |
| Southern Company | | | | |
| Total cost of natural gas | $ | 144 |
| $ | 191 |
| $ | 583 |
| $ | 877 |
|
| Gain (loss) on energy-related cash flow hedges(a) | (1 | ) | — |
| (8 | ) | — |
|
| Total depreciation and amortization | 873 |
| 755 |
| 1,730 |
| 1,506 |
|
| Gain (loss) on energy-related cash flow hedges(a) | (1 | ) | (1 | ) | (2 | ) | (4 | ) |
| Total interest expense, net of amounts capitalized | (444 | ) | (429 | ) | (900 | ) | (859 | ) |
| Gain (loss) on interest rate cash flow hedges(a) | (6 | ) | (5 | ) | (13 | ) | (9 | ) |
| Gain (loss) on foreign currency cash flow hedges(a) | (6 | ) | (6 | ) | (12 | ) | (12 | ) |
| Gain (loss) on interest rate fair value hedges(b) | 1 |
| 19 |
| 30 |
| 33 |
|
| Total other income (expense), net | 101 |
| 99 |
| 204 |
| 176 |
|
| Gain (loss) on foreign currency cash flow hedges(a)(c) | 27 |
| 16 |
| (4 | ) | (8 | ) |
| Southern Power | | | | |
| Total depreciation and amortization | $ | 121 |
| $ | 119 |
| $ | 239 |
| $ | 237 |
|
| Gain (loss) on energy-related cash flow hedges(a) | (1 | ) | (1 | ) | (2 | ) | (4 | ) |
| Total interest expense, net of amounts capitalized | (38 | ) | (41 | ) | (77 | ) | (84 | ) |
| Gain (loss) on foreign currency cash flow hedges(a) | (6 | ) | (6 | ) | (12 | ) | (12 | ) |
| Total other income (expense), net | 1 |
| 40 |
| 4 |
| 41 |
|
| Gain (loss) on foreign currency cash flow hedges(a)(c) | 27 |
| 16 |
| (4 | ) | (8 | ) |
| | | | | | | | | | |
Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships | | For the Three Months Ended March 31, |
|
| | 2021 | 2020 |
| | (in millions) |
Southern Company | | | | |
Total cost of natural gas | | | $ | 583 | | $ | 439 | |
Gain (loss) on energy-related cash flow hedges(a) | | | (3) | | (7) | |
Total depreciation and amortization | | | 871 | | 857 | |
Gain (loss) on energy-related cash flow hedges(a) | | | 3 | | (1) | |
Total interest expense, net of amounts capitalized | | | (450) | | (456) | |
Gain (loss) on interest rate cash flow hedges(a) | | | (7) | | (6) | |
Gain (loss) on foreign currency cash flow hedges(a) | | | (6) | | (6) | |
Gain (loss) on interest rate fair value hedges(b) | | | (10) | | 29 | |
Total other income (expense), net | | | 58 | | 103 | |
Gain (loss) on foreign currency cash flow hedges(a)(c) | | | (60) | | (31) | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
Southern Power | | | | |
Total depreciation and amortization | | | $ | 119 | | $ | 117 | |
Gain (loss) on energy-related cash flow hedges(a) | | | 3 | | (1) | |
Total interest expense, net of amounts capitalized | | | (38) | | (39) | |
Gain (loss) on foreign currency cash flow hedges(a) | | | (6) | | (6) | |
Total other income (expense), net | | | 7 | | 2 | |
Gain (loss) on foreign currency cash flow hedges(a)(c) | | | (60) | | (31) | |
| | | | |
| | | | |
| | | | |
| |
(a) | Reclassified from accumulated OCI into earnings. |
| |
(b) | For fair value hedges, changes in the fair value of the derivative contracts are generally equal to changes in the fair value of the underlying debt and have no material impact on income. |
| |
(c) | The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes. |
(a)Reclassified from accumulated OCI into earnings.
(b)For fair value hedges, changes in the fair value of the derivative contracts are generally equal to changes in the fair value of the underlying debt and have no material impact on income.
(c)The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes.
For the three and six months ended June 30,March 31, 2021 and 2020, and 2019, the pre-tax effects of cash flow and fair value hedge accounting on income for energy-related derivatives and interest rate derivatives were immaterial for the traditional electric operating companies and Southern Company Gas.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
As of June 30, 2020March 31, 2021 and December 31, 2019,2020, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:
| | | | | | | | | | | | | | | | | |
| Carrying Amount of the Hedged Item | | Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item |
Balance Sheet Location of Hedged Items | As of March 31, 2021 | As of December 31, 2020 | | As of March 31, 2021 | As of December 31, 2020 |
| (in millions) | | (in millions) |
Southern Company | | | | | |
Securities due within one year | $ | (1,505) | | $ | (1,509) | | | $ | (5) | | $ | (10) | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
|
| | | | | | | | | | | | | |
| Carrying Amount of the Hedged Item | | Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item |
Balance Sheet Location of Hedged Items | As of June 30, 2020 | As of December 31, 2019 |
| As of June 30, 2020 | As of December 31, 2019 |
| (in millions) | | (in millions) |
Southern Company | | | | | |
Securities due within one year | $ | — |
| $ | (599 | ) | | $ | — |
| $ | — |
|
Long-term debt | (1,517 | ) | (1,494 | ) | | (20 | ) | 3 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
For the three and six months ended June 30,March 31, 2021 and 2020, and 2019, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas were as follows:
| | | | | | | | | | | | | | |
| | | | | Gain (Loss) |
| | | | Three Months Ended March 31, |
Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | | | | 2021 | 2020 |
| | | | (in millions) |
| | | | | | |
Energy-related derivatives: | Natural gas revenues(*) | | | | $ | (17) | | $ | 70 | |
| | | | | | |
| Cost of natural gas | | | | 7 | | 7 | |
Total derivatives in non-designated hedging relationships | | | | $ | (10) | | $ | 77 | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | |
|
| | | | | | | | | | | | | | |
| | Gain (Loss) |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | 2020 | 2019 | | 2020 | 2019 |
| | (in millions) | | (in millions) |
Energy-related derivatives: | Natural gas revenues(*) | $ | 14 |
| $ | 50 |
| | $ | 84 |
| $ | 83 |
|
| Cost of natural gas | 5 |
| (5 | ) | | 13 |
| 3 |
|
Total derivatives in non-designated hedging relationships | $ | 19 |
| $ | 45 |
| | $ | 97 |
| $ | 86 |
|
(*)Excludes immaterial gains (losses) recorded in natural gas revenues associated with weather derivatives for all periods presented. | |
(*) | Excludes immaterial gains (losses) recorded in natural gas revenues associated with weather derivatives for all periods presented. |
For the three and six months ended June 30,March 31, 2021 and 2020, and 2019, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for all other Registrants.
Contingent Features
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At June 30, 2020,March 31, 2021, the Registrants had 0 collateral posted with derivative counterparties to satisfy these arrangements.
ForAt March 31, 2021, the Registrants with interest rate derivatives at June 30, 2020, the fair value ofhad no interest rate derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, was immaterial.features. At June 30, 2020,March 31, 2021, the fair value of energy-related derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial for all Registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade. Following the sale of Gulf Power to NextEra Energy, Inc., Gulf Power is continuing to participate in the Southern Company power pool for a defined transition period that, subject to certain potential adjustments, is scheduled to end on January 1, 2024.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.
Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions. Basedtransactions and they may be required to post collateral based on the value of the positions in these accounts and the associated margin requirements, Alabama Power and Southern Power may be required to post collateral.requirements. At June 30, 2020,March 31, 2021, cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At June 30, 2020,March 31, 2021, cash collateral held on deposit in broker margin accounts was $114$27 million.
The Registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Registrants only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Registrants have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Southern Company Gas uses established credit policies to determine and monitor the creditworthiness of counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or U.S. government securities held by a trustee. Prior to entering into a physical transaction, Southern Company Gas assigns physical wholesaleits counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.
In addition, Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for the counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern Company Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.
Southern Company Gas also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Southern Company Gas is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Southern Company Gas' credit risk. Southern Company Gas also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master nettingNetting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty. Southern Company Gas also netscounterparty across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. Southern Company Gas may requireWhile the amounts due from, or owed to, counterparties to pledge additional collateral when deemed necessary.are settled net, they are recorded on a gross basis on the balance sheet as energy marketing receivables and energy marketing payables.
The Registrants do not anticipate a material adverse effect on their respective financial statements as a result of counterparty nonperformance.
(K) ACQUISITIONS AND DISPOSITIONS
See Note 15 to the financial statements in Item 8 of the Form 10-K for additional information, including detailsinformation.
Southern Company
The following table provides Southern Company's major classes of assets and liabilitiesclassified as held for sale at March 31, 2021 and December 31, 2019 for 2020:
| | | | | | | | |
| Southern Company |
| At March 31, | At December 31, |
| 2021 | 2020 |
| (in millions) |
Assets Held for Sale: | | |
Total property, plant, and equipment | $ | 7 | | $ | 8 | |
Leveraged leases | 52 | | 52 | |
Total Assets Held for Sale | $ | 59 | | $ | 60 | |
Southern Company, Southern Power,Company's asset sales, both individually and Southern Company Gas. The Registrants had no material assetscombined, do not represent a strategic shift in operations that has, or liabilities held for sale at June 30, 2020.
Alabama Power
On April 22, 2020 and June 9, 2020, the FERC and the Alabama PSC, respectively, approved the Autauga Combined Cycle Acquisition, which is expected to close by September 1, 2020. See Note (B) under "Alabama Power"have, a major effect on operations and financial results; therefore, none of the assets have been classified as discontinued operations for additional information. The ultimate outcomeany of this matter cannot be determined at this time.the periods presented.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Southern Power
Asset AcquisitionsAcquisition
During the sixthree months ended June 30, 2020,March 31, 2021, Southern Power acquired a controlling membership interest in the wind facility listed below. Acquisition-related costs were expensed as incurred and were not material.
|
| | | | | | | | | | | | | | | | | | | | | | |
Project Facility | Resource | Seller | Approximate Nameplate Capacity (MW) | Location | Southern Power Ownership Percentage | COD | PPA Contract Period |
Beech Ridge IIDeuel Harvest(*) | Wind | Invenergy Renewables, LLC | 56300 | Deuel County, SD | Greenbrier County,100% of
West VirginiaClass B
| 100% of Class AFebruary 2021 | (*)25 years
| May 2020 | 12and 15 years |
| |
(*) | In May 2020, Southern Power purchased 100% of the Class A membership interests and now owns the controlling interest in the project, with the Class B member, Invenergy Renewables LLC, owning the noncontrolling interest. |
In(*)On March 2020,26, 2021, Southern Power entered into an agreement to acquireacquired a controlling membership interest in an approximately 300-MW wind facility located in South Dakota. The acquisition is subject to FERC approval and certain other customary conditions to closing, including commercial operation of the facility and consolidates the project's operating results in its financial statements. On March 30, 2021, Southern Power completed a tax equity transaction whereby it received $220 million. The tax equity partner, which is expectedthe Class A member, and Invenergy Renewables, LLC each own a noncontrolling interest.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Construction Projects
During the sixthree months ended June 30, 2020,March 31, 2021, Southern Power completed construction of and placed in service the Reading wind facility, continued construction of the Skookumchuck wind facility, and commenced construction of the Garland and Tranquillity battery energy storage facilities.facilities and the Glass Sands wind facility. Total aggregate construction costs, excluding acquisition costs, are expected to be between $475$392 million and $545$460 million for the facilities under construction. At June 30, 2020,March 31, 2021, total costs of construction incurred for these projects were $232$158 million and are included in CWIP. The ultimate outcome of these matters cannot be determined at this time.
|
| | | | | | | | | | | | | | | | |
Project Facility | Resource | Approximate Nameplate Capacity (MW) | Location | Actual/Expected COD | PPA Contract Period |
Projects Completed During the Six Months Ended June 30, 2020 |
Reading(a)
| Wind | 200 | Osage and Lyon Counties, KS | May 2020 | 12 years |
Projects Under Construction as of June 30, 2020 |
Skookumchuckat March 31, 2021(b)
| Wind | 136 | Lewis and Thurston Counties, WA | Fourth quarter 2020 | 20 years |
Garland Solar Storage(c)(a) | Battery energy storage system | 88 | Kern County, CA | SecondThird quarter 2021 | 20 years |
Tranquillity Solar Storage(c)(a) | Battery energy storage system | 72 | Fresno County, CA | SecondFourth quarter 2021 | 20 years |
Glass Sands(b) | Wind | 118 | Murray County, OK | Fourth quarter 2021 | 12 years |
(a)In December 2020, Southern Power restructured its ownership of the project by contributing the Class A membership interests to an existing partnership and selling 100% of the Class B membership interests while retaining the controlling interest. Prior to commercial operation, Southern Power may restructure the project ownership again and enter into additional partnerships, but expects to retain the controlling interest. The ultimate outcome of this matter cannot be determined at this time.
| |
(a) | In 2018, Southern Power purchased 100% of the membership interests of the Reading facility pursuant to a joint development arrangement. At the time the facility was placed in service, Southern Power recorded an operating lease right-of-use asset and an operating lease liability, each in the amount of $24 million. In June 2020, Southern Power completed a tax equity transaction whereby it received $156 million and now owns 100% of the Class B membership interests.
|
| |
(b) | In October 2019, Southern Power purchased 100% of the membership interests of the Skookumchuck facility pursuant to a joint development arrangement. Southern Power expects to complete a tax equity transaction upon commercial operation and retain the Class B membership interests. Shortly after commercial operation, Southern Power may sell a noncontrolling interest in these Class B membership interests to another partner. The ultimate outcome of these matters cannot be determined at this time. |
| |
(c) | Prior to commercial operation, Southern Power may enter into one or more partnerships, in which case it would ultimately own less than 100% of the Class B membership interests, but would retain ownership of the controlling interest. The PPAs for these facilities are pending approval from the California Public Utilities Commission. The ultimate outcome of these matters cannot be determined at this time. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Development Projects
Southern Power continues to evaluate and refine the deployment of the remaining wind turbine equipment purchased in 2016 and 2017 to development and construction projects. During the sixthree months ended June 30, 2020, certainMarch 31, 2021, gains on wind turbine equipment was sold, resulting incontributed to various equity method investments totaled approximately $37 million.
Southern Company Gas
Sale of Sequent
On April 28, 2021, certain affiliates of Southern Company Gas entered into an immaterial gain.
Sales of Natural Gas and Biomass Plants
On January 17, 2020, Southern Power completedagreement for the sale of its equity interests in Plant Mankato (including the 385-MW expansion unit completed in May 2019) to a subsidiary of XcelSequent for a purchase price of approximately $663$50 million,, including final plus working capital and certain other adjustments. The net book value of Sequent at March 31, 2021, excluding working capital, was $46 million; however, any potential gain or loss on the sale resultedwill be based, in a gainlarge part, on the fair value of approximately $39 million ($23 million after tax). The assetsthe open derivative positions as of the date of closing. See Notes (I) and liabilities of Plant Mankato were classified as held(J) for saleinformation on Southern Company'sfair value and Southern Power's balance sheetsderivatives outstanding at DecemberMarch 31, 2019.
Plants Nacogdoches (sold in June 2019) and Mankato represented individually significant components of Southern Power; therefore, pre-tax income for these components for the three months ended June 30, 2019 and the six months ended June 30, 2020 and 2019 is presented below:
|
| | | | | | | | | |
| Three Months Ended June 30, 2019 | Six Months Ended June 30, |
| 2020 | 2019 |
| (in millions) |
Southern Power's earnings before income taxes:(*) | | | |
Plant Nacogdoches | $ | 9 |
| N/A |
| $ | 16 |
|
Plant Mankato | $ | 6 |
| $ | 2 |
| $ | 8 |
|
| |
(*) | Earnings before income taxes for components reflect the cessation of depreciation and amortization on the long-lived assets being sold upon classification as held for sale in November 2018 and April 2019 for Plant Mankato and Plant Nacogdoches, respectively. |
Southern Company Gas
On March 24, 2020, has existing agreements in place in which it guarantees the payment performance of Sequent. Southern Company Gas will continue to guarantee payment performance for Sequent after the transaction closes for a period of time as the buyer obtains releases from these obligations. As of March 31, 2021, the obligations subject to the payment performance guarantee totaled $279 million. Changes in the price of natural gas, market conditions, and the number of open contracts will change the amount that Southern Company Gas is required to guarantee for Sequent each month. The maximum potential exposure over the period of the payment performance guarantee generally is capped at $1 billion. At closing, the buyer (an investment-grade entity) will issue a payment performance guarantee to Southern Company Gas, equal to the outstanding guarantee obligation throughout this period. Further, Southern Company Gas will retain responsibility for certain potential obligations that may arise from transactions during Winter Storm Uri. The completion of the transaction is subject to the satisfaction or waiver of certain conditions, including, among other customary closing conditions, the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. The transaction is expected to be completed during the third quarter 2021; however, the ultimate outcome of this matter cannot be determined at this time.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Sale of Pivotal LNG
In connection with its March 2020 sale of its interests in Pivotal LNG, and Atlantic Coast PipelineSouthern Company Gas was entitled to 2 $5 million payments contingent upon Dominion Modular LNG Holdings, Inc. and Dominion Atlantic Coast Pipeline, LLC, respectively, with aggregate proceeds of $178 million, including working capital adjustments. The preliminary loss associated with the transactions was immaterial. Southern Company Gas may also receive 2 future payments of $5 million each, contingent uponmeeting certain milestones related to Pivotal LNG being met by Dominion Modular LNG Holdings, Inc. The assets and liabilities of Pivotal LNG and the interest in Atlantic Coast Pipeline were classified as held for sale at December 31, 2019. See Notes 3 and 7 under "Other Matters –LNG. Southern Company Gas – Gas Pipeline Projects"received the first payment on April 22, 2021 and "Southern Company Gas – Equity Method Investments," respectively,expects to receive the second payment in Item 8 of the Form 10-K and Notes (C) and (E) under "Other Matters – Southern Company Gas" and "Southern Company Gas," respectively.August 2021.
(L) SEGMENT AND RELATED INFORMATION
Southern Company
The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The traditional electric operating companies – Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service in 3 Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy and battery energy storage projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through its natural gas distribution utilities and is involved in several other complementary businesses including gas pipeline investments, wholesale gas services, and gas marketing services.
Southern Company's reportable business segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $92 million and $178$81 million for the three and six months ended June 30, 2020, respectively,March 31, 2021 and $117 million and $204$86 million for the three and six months ended June 30, 2019, respectively.March 31, 2020. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were immaterial for all periods presented.the three months ended March 31, 2021 and 2020. Revenues from sales of natural gas from Southern Company Gas to Southern Power were $3 million and $13$12 million for the three and six months ended June 30, 2020, respectively,March 31, 2021 and $16 million and $33$10 million for the three and six months ended June 30, 2019, respectively.March 31, 2020. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing energy solutions to electric utilities and their customers in the areas of distributed generation, energy storage and renewables, and energy efficiency, as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Financial data for business segments and products and services for the three and six months ended June 30,March 31, 2021 and 2020 and 2019 was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric Utilities | | | | |
| Traditional Electric Operating Companies | Southern Power | Eliminations | Total | Southern Company Gas | All Other | Eliminations | Consolidated |
| (in millions) |
| | | | | | | |
| | | | | | | | |
| | | | | | | | |
Three Months Ended March 31, 2021 | | | | | | | |
Operating revenues | $ | 3,764 | | $ | 440 | | $ | (87) | | $ | 4,117 | | $ | 1,694 | | $ | 134 | | $ | (35) | | $ | 5,910 | |
Segment net income (loss)(a)(b)(c) | 756 | | 97 | | 0 | | 853 | | 398 | | (108) | | (8) | | 1,135 | |
At March 31, 2021 | | | | | | | | |
Goodwill | $ | 0 | | $ | 2 | | $ | 0 | | $ | 2 | | $ | 5,015 | | $ | 263 | | $ | 0 | | $ | 5,280 | |
Total assets | 86,053 | | 13,995 | | (637) | | 99,411 | | 23,377 | | 3,392 | | (787) | | 125,393 | |
| | | | | | | |
| | | | | | | | |
| | | | | | | | |
Three Months Ended March 31, 2020 | | | | | | | |
Operating revenues | $ | 3,407 | | $ | 375 | | $ | (87) | | $ | 3,695 | | $ | 1,249 | | $ | 114 | | $ | (40) | | $ | 5,018 | |
Segment net income (loss)(a)(d) | 642 | | 75 | | 0 | | 717 | | 275 | | (121) | | (3) | | 868 | |
At December 31, 2020 | | | | | | | | |
Goodwill | $ | 0 | | $ | 2 | | $ | 0 | | $ | 2 | | $ | 5,015 | | $ | 263 | | $ | 0 | | $ | 5,280 | |
Total assets | 85,486 | | 13,235 | | (680) | | 98,041 | | 22,630 | | 3,168 | | (904) | | 122,935 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Electric Utilities | | | | |
| Traditional Electric Operating Companies | Southern Power | Eliminations | Total | Southern Company Gas | All Other | Eliminations | Consolidated |
| (in millions) |
Three Months Ended June 30, 2020 | | | | | | | |
Operating revenues | $ | 3,539 |
| $ | 439 |
| $ | (94 | ) | $ | 3,884 |
| $ | 636 |
| $ | 135 |
| $ | (35 | ) | $ | 4,620 |
|
Segment net income (loss)(a)(b)(c) | 645 |
| 63 |
| — |
| 708 |
| 71 |
| (177 | ) | 10 |
| 612 |
|
Six Months Ended June 30, 2020 | | | |
|
| | | |
Operating revenues | $ | 6,946 |
| $ | 814 |
| $ | (181 | ) | $ | 7,579 |
| $ | 1,885 |
| $ | 248 |
| $ | (74 | ) | $ | 9,638 |
|
Segment net income (loss)(a)(b)(c)(d) | 1,287 |
| 138 |
| — |
| 1,425 |
| 346 |
| (299 | ) | 8 |
| 1,480 |
|
At June 30, 2020 | | | | | | | | |
Goodwill | $ | — |
| $ | 2 |
| $ | — |
| $ | 2 |
| $ | 5,015 |
| $ | 263 |
| $ | — |
| $ | 5,280 |
|
Total assets | 83,158 |
| 13,557 |
| (713 | ) | 96,002 |
| 21,500 |
| 3,325 |
| (1,096 | ) | 119,731 |
|
Three Months Ended June 30, 2019 | | | | | | | |
Operating revenues | $ | 3,899 |
| $ | 510 |
| $ | (119 | ) | $ | 4,290 |
| $ | 689 |
| $ | 186 |
| $ | (67 | ) | $ | 5,098 |
|
Segment net income (loss)(a)(e)(f) | 782 |
| 174 |
| — |
| 956 |
| 106 |
| (154 | ) | (9 | ) | 899 |
|
Six Months Ended June 30, 2019 | | | | | | | |
Operating revenues | $ | 7,343 |
| $ | 953 |
| $ | (211 | ) | $ | 8,085 |
| $ | 2,163 |
| $ | 368 |
| $ | (106 | ) | $ | 10,510 |
|
Segment net income (loss)(a)(e)(f) | 1,346 |
| 230 |
| — |
| 1,576 |
| 376 |
| 1,041 |
| (11 | ) | 2,982 |
|
At December 31, 2019 | | | | | | | | |
Goodwill | $ | — |
| $ | 2 |
| $ | — |
| $ | 2 |
| $ | 5,015 |
| $ | 263 |
| $ | — |
| $ | 5,280 |
|
Total assets | 81,063 |
| 14,300 |
| (713 | ) | 94,650 |
| 21,687 |
| 3,511 |
| (1,148 | ) | 118,700 |
|
(a)Attributable to Southern Company. | |
(a) | Attributable to Southern Company. |
| |
(b) | Segment net income (loss) for the traditional electric operating companies includes a pre-tax charge of $149 million ($111 million after tax) related to Plant Vogtle Units 3 and 4 for the three and six months ended June 30, 2020. See Note (B) under "Georgia Power – Nuclear Construction"(b)For the traditional electric operating companies, includes a $48 million pre-tax charge ($36 million after tax) at Georgia Power for estimated loss on Plant Vogtle Units 3 and 4. See Note (B) under "Georgia Power – Nuclear Construction" for additional information. (c)For Southern Power, includes gains on wind turbine equipment contributed to various equity method investments totaling approximately $37 million pre-tax ($28 million after tax). See Notes (E) and (K) under "Southern Power" for additional information. (d)For Southern Power, includes a $39 million pre-tax gain ($23 million gain after tax) on the sale of Plant Mankato. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power" for additional information. |
| |
(c) | Segment net income (loss) for the "All Other" column includes a pre-tax impairment charge of $154 million ($74 million after tax) related to a leveraged lease investment for the three and six months ended June 30, 2020. See Note (C) under "Other Matters – Southern Company" for additional information. |
| |
(d) | Segment net income (loss) for Southern Power includes a $39 million pre-tax gain ($23 million gain after tax) on the sale of Plant Mankato for the six months ended June 30, 2020. See Note (K) under "Southern Power" for additional information.
|
| |
(e) | Segment net income (loss) for the "All Other" column includes the preliminary pre-tax gain associated with the sale of Gulf Power of $2.5 billion ($1.3 billion after tax) for the six months ended June 30, 2019, of which $(15) million ($(11) million after tax) was recorded in the three months ended June 30, 2019, as well as a goodwill impairment charge of $32 million for the three and six months ended June 30, 2019 in contemplation of the sale of 1 of PowerSecure's business units. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company" for additional information. |
| |
(f) | Segment net income (loss) for Southern Power includes a $23 million pre-tax gain ($88 million gain after tax) on the sale of Plant Nacogdoches for the three and six months ended June 30, 2019. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power – Sale of Natural Gas and Biomass Plants" for additional information. |
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
Products and Services
| | | | | | | | | | | | | | |
| Electric Utilities' Revenues |
| Retail | Wholesale | Other | Total |
| (in millions) |
| | | | |
| | | | |
Three Months Ended March 31, 2021 | $ | 3,342 | | $ | 545 | | $ | 230 | | $ | 4,117 | |
Three Months Ended March 31, 2020 | 3,078 | | 418 | | 199 | | 3,695 | |
| | | | | | | | | | | | | | | | | |
| Southern Company Gas' Revenues |
| Gas Distribution Operations | Wholesale Gas Services(*) | Gas Marketing Services | Other | Total |
| (in millions) |
| | | | | |
| | | | | |
Three Months Ended March 31, 2021 | $ | 1,192 | | $ | 298 | | $ | 195 | | $ | 9 | | $ | 1,694 | |
Three Months Ended March 31, 2020 | 1,013 | | 51 | | 177 | | 8 | | 1,249 | |
(*)The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. See "Southern Company Gas" herein for additional information.
|
| | | | | | | | | | | | |
| Electric Utilities' Revenues |
| Retail | Wholesale | Other | Total |
| (in millions) |
Three Months Ended June 30, 2020 | $ | 3,182 |
| $ | 472 |
| $ | 230 |
| $ | 3,884 |
|
Three Months Ended June 30, 2019 | 3,540 |
| 542 |
| 208 |
| 4,290 |
|
Six Months Ended June 30, 2020 | $ | 6,260 |
| $ | 889 |
| $ | 430 |
| $ | 7,579 |
|
Six Months Ended June 30, 2019 | 6,623 |
| 1,041 |
| 421 |
| 8,085 |
|
|
| | | | | | | | | | | | | | | |
| Southern Company Gas' Revenues |
| Gas Distribution Operations | Wholesale Gas Services(*) | Gas Marketing Services | Other | Total |
| (in millions) |
Three Months Ended June 30, 2020 | $ | 583 |
| $ | (19 | ) | $ | 56 |
| $ | 16 |
| $ | 636 |
|
Three Months Ended June 30, 2019 | 563 |
| 48 |
| 58 |
| 20 |
| 689 |
|
Six Months Ended June 30, 2020 | $ | 1,596 |
| $ | 32 |
| $ | 233 |
| $ | 24 |
| $ | 1,885 |
|
Six Months Ended June 30, 2019 | 1,724 |
| 134 |
| 287 |
| 18 |
| 2,163 |
|
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued) | |
(*) | The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. See "Southern Company Gas" herein for additional information. |
Southern Company Gas
Southern Company Gas manages its business through 4 reportable segments – gas distribution operations, gas pipeline investments, wholesale gas services, and gas marketing services. The non-reportable segments are combined and presented as all other. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information on the disposition activities described herein.
Gas distribution operations is the largest component of Southern Company Gas' business and includes natural gas local distribution utilities that construct, manage, and maintain intrastate natural gas pipelines and gas distribution facilities in 4 states.
Gas pipeline investments consists of joint ventures in natural gas pipeline investments including a 50% interest in SNG, a 20% ownership interest in the PennEast Pipeline construction project, and a 50% joint ownership interest in the Dalton Pipeline, and a 5% ownership interest in the Atlantic Coast Pipeline construction project through its sale on March 24, 2020.Pipeline. These natural gas pipelines enable the provision of diverse sources of natural gas supplies to the customers of Southern Company Gas. Gas pipeline investments also included a 5% ownership interest in the Atlantic Coast Pipeline construction project prior to its sale on March 24, 2020.
Wholesale gas services provides natural gas asset management and/or related logistics services for each of Southern Company Gas' utilities except Nicor Gas as well as for non-affiliated companies. The Virginia Natural Gas asset management agreement ended on March 31, 2021 and was not extended. Additionally, wholesale gas services engages in natural gas storage and gas pipeline arbitrage and related activities. See Note (K) under "Southern Company Gas" for information regarding the sale of Sequent, which is expected to be completed during the third quarter 2021.
Gas marketing services provides natural gas marketing to end-use customers primarily in Georgia and Illinois through SouthStar.
The all other column includes segments below the quantitative threshold for separate disclosure, including natural gas storage businesses, fuels operations through the sale of Southern Company Gas' interest in Pivotal LNG on March 24, 2020, the investment in Triton through its sale on May 29, 2019, and other subsidiaries that fall below the quantitative threshold for separate disclosure. See Notes (E)disclosure, including storage and (K) under "Southern Company Gas" for additional information.
NOTES TO THE CONDENSED FINANCIAL STATEMENTS (Continued)
(UNAUDITED)
fuels operations. The all other column included Jefferson Island through its sale on December 1, 2020 and Pivotal LNG through its sale on March 24, 2020.
Business segment financial data for the three and six months ended June 30,March 31, 2021 and 2020 and 2019 was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services(*) | Gas Marketing Services | Total | All Other | Eliminations | Consolidated |
| (in millions) |
| | | | | | |
| | | | | | | | |
| | | | | | | | |
Three Months Ended March 31, 2021 | | | | | | |
Operating revenues | $ | 1,200 | | $ | 8 | | $ | 298 | | $ | 195 | | $ | 1,701 | | $ | 7 | | $ | (14) | | $ | 1,694 | |
Segment net income (loss) | 183 | | 29 | | 126 | | 56 | | 394 | | 4 | | 0 | | 398 | |
Total assets at March 31, 2021 | 20,161 | | 1,596 | | 939 | | 1,553 | | 24,249 | | 11,477 | | (12,349) | | 23,377 | |
| | | | | | |
| | | | | | | | |
| | | | | | | | |
Three Months Ended March 31, 2020 | | | | | | | |
Operating revenues | $ | 1,020 | | $ | 8 | | $ | 51 | | $ | 177 | | $ | 1,256 | | $ | 8 | | $ | (15) | | $ | 1,249 | |
Segment net income (loss) | 164 | | 30 | | 23 | | 57 | | 274 | | 1 | | 0 | | 275 | |
Total assets at December 31, 2020 | 19,090 | | 1,597 | | 850 | | 1,503 | | 23,040 | | 11,336 | | (11,746) | | 22,630 | |
(*)The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table.
| | | | | | | | | | | | | | | | | |
| Third Party Gross Revenues | Intercompany Revenues | Total Gross Revenues | Less Gross Gas Costs | Operating Revenues |
| (in millions) |
| | | | | |
| | | | | |
Three Months Ended March 31, 2021 | $ | 2,588 | | $ | 63 | | $ | 2,651 | | $ | 2,353 | | $ | 298 | |
Three Months Ended March 31, 2020 | 1,185 | | 29 | | 1,214 | | 1,163 | | 51 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services(*) | Gas Marketing Services | Total | All Other | Eliminations | Consolidated |
| (in millions) |
Three Months Ended June 30, 2020 | | | | | | |
Operating revenues | $ | 587 |
| $ | 8 |
| $ | (19 | ) | $ | 56 |
| $ | 632 |
| $ | 8 |
| $ | (4 | ) | $ | 636 |
|
Segment net income (loss) | 74 |
| 21 |
| (23 | ) | 5 |
| 77 |
| (6 | ) | — |
| 71 |
|
Six Months Ended June 30, 2020 | | | | | | |
Operating revenues | $ | 1,607 |
| $ | 16 |
| $ | 32 |
| $ | 233 |
| $ | 1,888 |
| $ | 16 |
| $ | (19 | ) | $ | 1,885 |
|
Segment net income (loss) | 238 |
| 51 |
| — |
| 62 |
| 351 |
| (5 | ) | — |
| 346 |
|
Total assets at June 30, 2020 | 18,276 |
| 1,617 |
| 637 |
| 1,480 |
| 22,010 |
| 10,645 |
| (11,155 | ) | 21,500 |
|
Three Months Ended June 30, 2019 | | | | | | |
Operating revenues | $ | 568 |
| $ | 8 |
| $ | 48 |
| $ | 58 |
| $ | 682 |
| $ | 13 |
| $ | (6 | ) | $ | 689 |
|
Segment net income (loss) | 58 |
| 25 |
| 23 |
| (3 | ) | 103 |
| 3 |
| — |
| 106 |
|
Six Months Ended June 30, 2019 | | | | | | | |
Operating revenues | $ | 1,740 |
| $ | 16 |
| $ | 134 |
| $ | 287 |
| $ | 2,177 |
| $ | 24 |
| $ | (38 | ) | $ | 2,163 |
|
Segment net income (loss) | 191 |
| 57 |
| 70 |
| 58 |
| 376 |
| — |
| — |
| 376 |
|
Total assets at December 31, 2019 | 18,204 |
| 1,678 |
| 850 |
| 1,496 |
| 22,228 |
| 10,759 |
| (11,300 | ) | 21,687 |
|
| |
(*) | The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table. |
|
| | | | | | | | | | | | | | | |
| Third Party Gross Revenues | Intercompany Revenues | Total Gross Revenues | Less Gross Gas Costs | Operating Revenues |
| (in millions) |
Three Months Ended June 30, 2020 | $ | 854 |
| $ | 18 |
| $ | 872 |
| $ | 891 |
| $ | (19 | ) |
Three Months Ended June 30, 2019 | 1,223 |
| 63 |
| 1,286 |
| 1,238 |
| 48 |
|
Six Months Ended June 30, 2020 | $ | 2,039 |
| $ | 47 |
| $ | 2,086 |
| $ | 2,054 |
| $ | 32 |
|
Six Months Ended June 30, 2019 | 3,148 |
| 151 |
| 3,299 |
| 3,165 |
| 134 |
|
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.
| | | | | |
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| Page |
Combined Management's Discussion and Analysis of Financial Condition and Results of Operations | |
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The following Management's Discussion and Analysis of Financial Condition and Results of Operations is a combined presentation; however, information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf and each Registrant makes no representation as to information related to the other Registrants.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
OVERVIEW
Southern Company is a holding company that owns all of the common stock of three traditional electric operating companies (Alabama Power, Georgia Power, and Mississippi Power), as well as Southern Power and Southern Company Gas, and owns other direct and indirect subsidiaries. The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. Southern Company's reportable segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Southern Company Gas' reportable segments are gas distribution operations, gas pipeline investments, wholesale gas services, and gas marketing services. See Note (L) to the Condensed Financial Statements herein for additional information on segment reporting. For additional information on the Registrants' primary business activities, see BUSINESS – "The Southern Company System" in Item 1 of the Form 10-K.
The Registrants continue to focus on several key performance indicators. For the traditional electric operating companies and Southern Company Gas, these indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, and execution of major construction projects. For Southern Power, these indicators include, but are not limited to, the equivalent forced outage rate and contract availability to evaluate operating results and help ensure its ability to meet its contractual commitments to customers. In addition, Southern Company and the Subsidiary Registrants focus on earnings per share and net income, respectively, as a key performance indicator.
Recent Developments
COVID-19
During March 2020, COVID-19 was declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention and has spread globally, including throughout the United States. The Southern Company system provides a critical service to its customers; therefore, it is essential that Southern Company system employees are able to continue to perform their critical duties safely and effectively. The Southern Company system has implemented applicable business continuity plans, including teleworking, canceling non-essential business travel, increasing cleaning frequency at business locations, implementing applicable safety and health guidelines issued by federal and state officials, and establishing protocols for required work on customer premises. To date, these procedures have been effective in maintaining the Southern Company system's critical operations. As a result of the COVID-19 pandemic, there have been economic disruptions in the Registrants' operating territories. The traditional electric operating companies and the natural gas distribution utilities temporarily suspended disconnections for non-payment by customers and waived late fees for certain periods. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters" herein for information regarding deferral of certain incremental COVID-19-related costs, including bad debt, to a regulatory asset by certain of the traditional electric operating companies and the natural gas distribution utilities. In addition, the COVID-19 pandemic has resulted in a reduction in workforce at Plant Vogtle Units 3 and 4, as discussed further herein. Additional information regarding COVID-19 and its potential impacts on the Registrants is provided throughout Management's Discussion and Analysis of Financial Condition and Results of Operations and in Item 1A herein.
Alabama Power
On June 9, 2020, the Alabama PSC approved in part Alabama Power's petition for a certificate of convenience and necessity (CCN) filed in September 2019 to procure additional capacity. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Alabama Power" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Georgia Power
Plant Vogtle Units 3 and 4 Status
In 2009, the Georgia PSC certified construction ofConstruction continues on Plant Vogtle Units 3 and 4 (with electric generating capacity of approximately 1,100 MWs each), in which Georgia Power holds a 45.7% ownership interest. Georgia Power's share of the total project capital cost forecast to complete Plant Vogtle Units 3 and 4 by December 2021 and November 2022, respectively, is $8.76 billion.
DuringGeorgia Power estimates the secondproductivity impacts of the COVID-19 pandemic have consumed approximately three to four months of schedule margin previously embedded in the site work plan for Unit 3 and Unit 4. In addition, throughout 2020, the project continued to face challenges as described in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein. As a result of these factors, in January 2021, Southern Nuclear further extended certain milestone dates, including the start of hot functional testing and fuel load for Unit 3, from those established in October 2020.
Following the January 2021 milestone extensions, Southern Nuclear has been performing additional construction remediation work, primarily related to electrical commodity installations, necessary to ensure quality and design standards are met as system turnovers are completed to support hot functional testing and fuel load for Unit 3. Hot functional testing commenced in late April 2021 and the site work plan currently targets fuel load for Unit 3 in the third quarter 2021 and an in-service date of December 2021. As the site work plan includes minimal margin to these milestone dates, any delay could result in an in-service date in the first quarter 2022 for Unit 3. Achievement of the extended milestone dates established in January 2021 for Unit 4, which are expected to support a regulatory-approved in-service date of November 2022, primarily depends on overall construction productivity and production levels significantly improving as well as appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, being added and maintained.
Considering the factors above, during the first quarter 2021, approximately $84 million of the construction contingency established in the fourth quarter 2020 approximately $194 million of construction contingency was assigned to the base capital cost forecast which exceededfor costs primarily associated with the schedule extension for Unit 3 to December 2021, construction productivity, support resources,
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
and construction remediation work. Georgia Power increased its total capital cost forecast as of March 31, 2021 by adding $48 million to the remaining balance of the construction contingency originally established in the second quarter 2018. As a result, Southern Nuclear recommended establishing additional construction contingency, of which Georgia Power's share is $115 million, for potential risks including, among other factors, construction productivity and expected impacts of the COVID-19 pandemic; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement.contingency.
After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $149$48 million ($11136 million after tax) for the increase in the total project capital cost forecast as of June 30, 2020.March 31, 2021. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.
In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site. In April 2020, Georgia Power, acting for itself and as agent for the other Vogtle Owners, announced a reduction in workforce at Plant Vogtle Units 3 and 4, which totaled approximately 20% of the then-existing site workforce. This workforce reduction lowered absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing. From the initial peak in April 2020, the number of active cases at the site declined significantly during May and early June, but began increasing again in mid-June and continues to impact productivity levels and pace of activity completion. As a result, overall production improvements have not been achieved at the levels anticipated, contributing to the allocation of, and increase in, construction contingency described above.
To address these issues, in July 2020, Southern Nuclear updated its aggressive site work plan for both Unit 3 and Unit 4. While Southern Nuclear's July 2020 aggressive site work plan extended milestone dates from its February 2020 aggressive site work plan, Georgia Power still expects to achieve the regulatory-approved in-service dates of November 2021 and November 2022 for Plant Vogtle Units 3 and 4, respectively.
The continuing effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4. Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be between $70 million and $115 million. However, the ultimate impact of the COVID-19 pandemic and other factors on the construction schedule and budget for Plant Vogtle Units 3 and 4 cannot be determined at this time.
See FUTURE EARNINGS POTENTIALNote (B) to the Condensed Financial Statements under "Georgia Power – "Construction Programs – Nuclear Construction"Construction" herein for additional information.
Mississippi Power
On March 17, 2020,15, 2021, Mississippi Power submitted its annual retail PEP filing for 2021 to the Mississippi PSC, approvedwhich requested a settlement agreement between Mississippi Power and1.8%, or approximately $16 million, annual increase in revenues. In accordance with the Mississippi Public Utilities Staff related to Mississippi Power's basePEP rate case filed in November 2019 (Mississippi Power Rate Case Settlement Agreement). Underschedule, the terms of the Mississippi Power Rate Case Settlement Agreement, annual retail rates decreased approximately $16.7 million, or 1.85%,rate increase became effective forwith the first billing cycle of April 2020. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Mississippi Power – 2019 Base Rate Case" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Power
During the six months ended June 30, 2020, Southern Power completed construction of and placed in service the 200-MW Reading wind facility, continued construction of the 136-MW Skookumchuck wind facility, and commenced construction of the Garland and Tranquillity battery energy storage facilities. See FUTURE EARNINGS POTENTIAL – "Construction Programs – Southern Power" herein for additional information.
On January 17, 2020, Southern Power completed the sale of its equity interests in Plant Mankato (including the 385-MW expansion unit completed in May 2019) to a subsidiary of Xcel for a purchase price of approximately $663 million, including final working capital adjustments.
In March 2020, Southern Power entered into an agreement to acquire a controlling membership interest in an approximately 300-MW wind facility located in South Dakota. The acquisition is2021, subject to FERC approval and certain other customary conditions to closing, including commercial operation of the facility, whichrefund.The Mississippi PSC is expected to occurrule on this request later in late 2020 or earlythe second quarter 2021. The facility's output is contracted under two long-term PPAs.ultimate outcome of this matter cannot be determined at this time.
On April 6, 2021, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment filing for 2021, which requested an annual increase in revenues of approximately $28 million. The rate became effective with the first billing cycle of May 2021.
On April 15, 2021, Mississippi Power filed its 2021 IRP with the Mississippi PSC. The filing includes a schedule to retire Plant Watson Unit 4 (268 MWs) and Mississippi Power's 40% ownership interest in Plant Greene County Units 1 and 2 (103 MWs each) in December 2023, 2025, and 2026, respectively, consistent with each unit's remaining useful life in the most recent approved depreciation studies. In addition, the schedule reflects the early retirement of Mississippi Power's 50% undivided ownership interest in Plant Daniel Units 1 and 2 (502 MWs) by the end of 2027. The ultimate outcome of this matter cannot be determined at this time.
See Note (B) to the Condensed Financial Statements under "Mississippi Power" herein for additional information.
Southern Power
During the three months ended March 31, 2021, Southern Power continued construction of the 88-MW Garland and 72-MW Tranquillity battery energy storage facilities and the 118-MW Glass Sands wind facility. On May 1, 2020,March 26, 2021, Southern Power purchased a controlling membership interest in the 56-MW Beech Ridge IIapproximately 300-MW Deuel Harvest wind facility located in GreenbrierDeuel County, West VirginiaSouth Dakota from Invenergy Renewables, LLC. The facility's output is contracted under a 12-year PPA. See Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.
At June 30, 2020,March 31, 2021, Southern Power's average investment coverage ratio for its generating assets, including those owned with various partners, based on the ratio of investment under contract to total investment using the respective generation facilities' net book value (or expected in-service value for facilities under construction) as the investment amount was 94%93% through 20242025 and 92%90% through 2029,2030, with an average remaining contract duration of approximately 14 years.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Company Gas
On March 24, 2020,April 28, 2021, Atlanta Gas Light filed its first Integrated Capacity and Delivery Plan (i-CDP) with the Georgia PSC, which includes a series of ongoing and proposed pipeline safety, reliability, and growth programs for the next 10 years, as well as the required capital investments and related costs to implement the programs. The i-CDP is subject to a five-month review period, which may be extended. See Note (B) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
Also on April 28, 2021, certain affiliates of Southern Company Gas completedentered into an agreement for the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline with aggregate proceeds of $178 million, including working capital adjustments.Sequent. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
On June 1, 2020, Virginia Natural Gas filed a general rate case with the Virginia Commission seeking an increase in rates ofapproximately $49.6 million based on a ROE of 10.35% and an equity ratio of 54%. The Virginia Commission is expected to rule on the requested increase in the second quarter 2021.
On July 1, 2020, Atlanta Gas Light filed its 2020 GRAM filing with the Georgia PSC requesting an increase in annual base rates of $37.6 million. Resolution of the 2020 GRAM filing is expected by December 31, 2020, with rates effective January 1, 2021.
See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Southern Company Gas" herein for additional information regarding Southern Company Gas' regulatory filings. The ultimate outcome of these matters cannot be determined at this time.
RESULTS OF OPERATIONS
Southern Company
Net Income
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(287) | | (31.9) | | $(1,502) | | (50.4) |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $267 | | 30.8 |
Consolidated net income attributable to Southern Company was $612 million$1.1 billion ($0.581.07 per share) forin the secondfirst quarter 20202021 compared to $899 million$0.9 billion ($0.860.82 per share) for the corresponding period in 2019.2020. The decreaseincrease was primarily due to increases in both natural gas revenues and retail electric revenues primarily associated with colder weather in the first quarter 2021 as compared to the first quarter 2020, partially offset by higher cost of natural gas.
Retail Electric Revenues
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $264 | | 8.6 |
In the first quarter 2021, retail electric revenues were $3.3 billion compared to $3.1 billion for the corresponding period in 2020.
Details of the changes in retail electric revenues were as follows:
| | | | | | | | | | | | | | | |
| | | First Quarter 2021 |
| | | | | (in millions) | | (% change) |
Retail electric – prior year | | | | | $ | 3,078 | | | |
Estimated change resulting from – | | | | | | | |
Rates and pricing | | | | | 25 | | | 0.8 | % |
Sales decline | | | | | (15) | | | (0.5) | |
Weather | | | | | 89 | | | 2.9 | |
Fuel and other cost recovery | | | | | 165 | | | 5.4 | |
Retail electric – current year | | | | | $ | 3,342 | | | 8.6 | % |
Revenues associated with changes in rates and pricing increased in the first quarter 2021 when compared to the corresponding period in 2020 primarily due to an increase in Alabama Power's Rate RSE effective January 1, 2021, partially offset by decreases in Georgia Power's NCCR tariff effective January 1, 2021 and in Mississippi Power's base rates effective in April 2020. See Note 2 to the financial statements under "Alabama Power – Rate RSE" and
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
primarily due to decreases in retail revenues associated with milder weather and lower customer usage in the second quarter 2020 compared to the corresponding period in 2019, a $111 million after-tax charge in the second quarter 2020 related to Georgia Power's construction of Plant Vogtle Units 3 and 4, an $88 million after-tax gain on the sale of Plant Nacogdoches in the second quarter 2019, higher depreciation and amortization, and a $74 million after-tax leveraged lease impairment in the second quarter 2020. These decreases to net income were partially offset by increases in retail revenues associated with rates and pricing and lower other operations and maintenance expenses. See Note 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K for additional information regarding the disposition of Plant Nacogdoches, Note (B) to the Condensed Financial Statements under "Georgia"Mississippi Power – Nuclear Construction" herein for additional information on the construction of Plant Vogtle Units 3 and 4, and Note (C) to the Condensed Financial Statements under "Other Matters – Southern Company" herein for additional information on the leveraged lease impairment.
Consolidated net income attributable to Southern Company was $1.5 billion ($1.40 per share) for year-to-date 2020 compared to $3.0 billion ($2.86 per share) for the corresponding period in 2019. The decrease was primarily due to the $2.5 billion ($1.3 billion after tax) gain on the sale of Gulf Power recorded in 2019. See Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K for additional information regarding the sale of Gulf Power.
Retail Electric Revenues
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(358) | | (10.1) | | $(363) | | (5.5) |
In the second quarter 2020, retail electric revenues were $3.2 billion compared to $3.5 billion for the corresponding period in 2019. For year-to-date 2020, retail electric revenues were $6.3 billion compared to $6.6 billion for the corresponding period in 2019.
Details of the changes in retail electric revenues were as follows:
|
| | | | | | | | | | | | | |
| Second Quarter 2020 | | Year-to-Date 2020 |
| (in millions) | | (% change) | | (in millions) | | (% change) |
Retail electric – prior year | $ | 3,540 |
| | | | $ | 6,623 |
| | |
Estimated change resulting from – | | | | | | | |
Rates and pricing | 124 |
| | 3.5 | % | | 267 |
| | 4.0 | % |
Sales decline | (107 | ) | | (3.0 | ) | | (99 | ) | | (1.5 | ) |
Weather | (132 | ) | | (3.7 | ) | | (159 | ) | | (2.4 | ) |
Fuel and other cost recovery | (243 | ) | | (6.9 | ) | | (372 | ) | | (5.6 | ) |
Retail electric – current year | $ | 3,182 |
| | (10.1 | )% | | $ | 6,260 |
| | (5.5 | )% |
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2020 when compared to the corresponding periods in 2019 primarily due to an increase in revenue at Georgia Power and Alabama Power related to the recovery of environmental compliance costs andBase Rate CNP Compliance costs, respectively, as well as the impacts of Georgia Power accruals for customer refunds in the first quarter and year-to-date 2019 related to Tax Reform and the rate pricing effects of decreased customer usage at Georgia Power. Partially offsetting these increases were lower contributions from commercial and industrial customers with variable demand-driven pricing at Georgia Power. Additionally, the year-to-date increase was due to Alabama Power customer bill credits in the first quarter 2019 related to Tax Reform. See Note 2 to the financial statements under "Alabama Power" and "Georgia Power"Case" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction – Regulatory Matters" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Revenues attributable to changes in sales decreased in the secondfirst quarter and year-to-date 20202021 when compared to the corresponding periodsperiod in 2019 largely due to social distancing and shelter-in-place guidelines related to2020 primarily driven by continued impacts of the COVID-19 pandemic. Weather-adjusted residential KWH sales increased 4.7% and 3.8%1.1% in the secondfirst quarter and year-to-date 2020, respectively,2021 when compared to the corresponding periodsperiod in 20192020 primarily due to customer growth and an increase in average customer usage, primarily due to the temporary suspension of customer disconnections for nonpayment and shelter-in-place orders.growth. Weather-adjusted commercial KWH sales decreased 11.5% and 6.3%3.1% in the secondfirst quarter and year-to-date 2020, respectively,2021 when compared to the corresponding periodsperiod in 20192020 primarily due to lower customer usage resulting from shelter-in-place orderschanges in consumer and restrictions on business operationsbehavior in response to the COVID-19 pandemic. Industrial KWH sales decreased 14.0% and 8.0%3.0% in the secondfirst quarter and year-to-date 2020, respectively,2021 when compared to the corresponding periodsperiod in 20192020 primarily as a result of disruptions in supply chain and business operations related to the COVID-19 pandemic, non-pandemic related customer closures, and the overall decrease in business activity due to the resulting recession.maintenance outages.
Fuel and other cost recovery revenues decreased $243 million and $372increased $165 million in the secondfirst quarter and year-to-date 2020, respectively,2021 compared to the corresponding periodsperiod in 20192020 primarily due to decreases in generation and the average cost ofhigher fuel and purchased power.power costs. Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses,expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs.
Wholesale Electric Revenues
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(70) | | (12.9) | | $(152) | | (14.6) |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $127 | | 30.4 |
Wholesale electric revenues consist of revenues from PPAs and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a result, the ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales under cost-based tariffs as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.
In the secondfirst quarter 2020,2021, wholesale electric revenues were $472$545 million compared to $542$418 million for the corresponding period in 2019. For year-to-date 2020, wholesale electric2020. The increase reflects an increase of $102 million in energy revenues were $889 millionprimarily resulting from higher natural gas prices when compared to $1.0 billion for the corresponding period in 2019. These decreases reflect decreases of $46 million and $103 million in energy revenues for the second quarter and year-to-date 2020, respectively, and $24 million and $49 million2020. In addition, an increase in capacity revenues for the second quarterof $25 million was primarily due to a power sales agreement at Alabama Power which began in September 2020 and year-to-date 2020, respectively. The decreases in energy revenues include $24 million and $67 million for the second quarter and year-to-date 2020, respectively, from Southern Power, with the remainder from the traditional electric operating companies. These decreases primarily result from lowernew natural gas prices and a net decrease in the volume of KWHs sold, primarily as a result of milder weather inPPAs at Southern Power.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Electric Revenues
the Southeast U.S. when compared to the corresponding periods in 2019. The decrease in capacity revenues was primarily related to Southern Power's sales of Plant Nacogdoches in the second quarter 2019 and Plant Mankato in | | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $19 | | 12.6 |
In the first quarter 2020. See Note (K) to the Condensed Financial Statements under "Southern Power" herein and Note 15 to the financial statements under "Southern Power – Sales of Natural Gas and Biomass Plants" in Item 8 of the Form 10-K for additional information.
Natural Gas Revenues
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(53) | | (7.7) | | $(278) | | (12.9) |
In the second quarter 2020, natural gas2021, other electric revenues were $636$170 million compared to $689$151 million for the corresponding period in 2019. For year-to-date 2020,2020. The increase was primarily due to increases of $9 million in transmission services, $3 million in customer fees at the traditional electric operating companies, and $3 million in outdoor lighting at Georgia Power.
Natural Gas Revenues
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $445 | | 35.6 |
In the first quarter 2021, natural gas revenues were $1.9$1.7 billion compared to $2.2$1.2 billion for the corresponding period in 2019.2020.
Details of the changes in natural gas revenues were as follows:
| | | Second Quarter 2020 | | Year-to-Date 2020 | | | First Quarter 2021 |
| (in millions) | | (% change) | | (in millions) | | (% change) | | | (in millions) | | (% change) |
Natural gas revenues – prior year | $ | 689 |
| | | | $ | 2,163 |
| | | Natural gas revenues – prior year | | $ | 1,249 | | |
Estimated change resulting from – | | | | | | | | Estimated change resulting from – | | |
Infrastructure replacement programs and base rate changes | 43 |
| | 6.2 | % | | 119 |
| | 5.5 | % | Infrastructure replacement programs and base rate changes | | 38 | | | 3.0 | % |
Gas costs and other cost recovery | (38 | ) | | (5.5 | ) | | (287 | ) | | (13.3 | ) | Gas costs and other cost recovery | | 152 | | | 12.2 | |
Weather | 3 |
| | 0.4 |
| | (8 | ) | | (0.4 | ) | |
| Wholesale gas services | (67 | ) | | (9.7 | ) | | (102 | ) | | (4.7 | ) | Wholesale gas services | | 247 | | | 19.8 | |
Other | 6 |
| | 0.9 |
| | — |
| | — |
| Other | | 8 | | | 0.6 | |
Natural gas revenues – current year | $ | 636 |
| | (7.7 | )% | | $ | 1,885 |
| | (12.9 | )% | Natural gas revenues – current year | | $ | 1,694 | | | 35.6 | % |
Revenues attributable tofrom infrastructure replacement programs and base rate changes at the natural gas distribution utilities increased in the secondfirst quarter and year-to-date 20202021 compared to the corresponding periodsperiod in 20192020 primarily due to base rate increases at Nicor Gas and Atlanta Gas Light, Virginia Natural Gas, and Chattanooga Gas and continued investments recovered throughinvestment in infrastructure replacement programs.replacement. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K for additional information.
Revenues attributable toassociated with gas costs and other cost recovery decreasedincreased in the secondfirst quarter and year-to-date 20202021 compared to the corresponding periodsperiod in 20192020 primarily due to lower naturalhigher volumes sold and higher gas prices and decreased volumes of natural gas sold.cost recovery. Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities.
Revenues attributable tofrom Southern Company Gas' wholesale gas services business decreasedincreased in the secondfirst quarter and year-to-date 20202021 compared to the corresponding periodsperiod in 2019 primarily2020 due to decreasedhigher commercial activityactivities as a result of warmer weather and a decrease inWinter Storm Uri, partially offset by derivative gains.losses. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for information regarding the sale of Sequent, which is expected to be completed during the third quarter 2021.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Revenues
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(4) | | (2.4) | | $(68) | | (19.3) |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $37 | | 30.3 |
In the secondfirst quarter 2020,2021, other revenues were $162$159 million compared to $166$122 million for the corresponding period in 2019. For year-to-date 2020, other revenues were $2842020. The increase primarily relates to a $24 million compared to $352 million for the corresponding periodincrease in 2019. These decreases primarily relate to changes in PowerSecure's business, including the sale of its utility infrastructure services business in June 2019 and the wind-down of a segment of its distributed infrastructure businessand energy efficiency projects at PowerSecure and an increase of $10 million in the first quarter 2020, partially offset by unregulated sales at Georgia Power largely associated with power delivery construction and maintenance contracts. See Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K for additional information.contracts at Georgia Power.
Fuel and Purchased Power Expenses
| | | Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | | First Quarter 2021 vs. First Quarter 2020 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) | | | (change in millions) | | (% change) |
Fuel | $ | (293 | ) | | (32.1) | | $ | (507 | ) | | (28.7) | Fuel | | $ | 212 | | | 33.3 |
Purchased power | (1 | ) | | (0.5) | | 10 |
| | 2.7 | Purchased power | | 26 | | | 14.4 |
Total fuel and purchased power expenses | $ | (294 | ) | | $ | (497 | ) | | Total fuel and purchased power expenses | | $ | 238 | | |
In the secondfirst quarter 2020,2021, total fuel and purchased power expenses were $0.8$1.1 billion compared to $1.1$0.8 billion for the corresponding period in 2019.2020. The decreaseincrease was primarily the result of a $118$159 million decreaseincrease in the average cost of fuel and purchased power and a $176$79 million net decrease in the volume of KWHs generated and purchased.
For year-to-date 2020, total fuel and purchased power expenses were $1.6 billion compared to $2.1 billion for the corresponding period in 2019. The decrease was primarily the result of a $285 million decrease in the average cost of fuel and purchased power and a $212 million net decreaseincrease in the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters" hereinNote 2 to the financial statements in Item 8 of the Form 10-K for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.
Details of the Southern Company system's generation and purchased power were as follows:
| | | | | | | | | | |
| | | First Quarter 2021 | First Quarter 2020 |
Total generation (in billions of KWHs)(a) | | | 43 | 42 |
Total purchased power (in billions of KWHs) | | | 4 | 5 |
Sources of generation (percent)(a) — | | | | |
Gas | | | 46 | 53 |
Coal | | | 24 | 14 |
Nuclear | | | 17 | 18 |
Hydro | | | 5 | 8 |
Wind, Solar, and Other | | | 8 | 7 |
Cost of fuel, generated (in cents per net KWH)— | | | | |
Gas(a) | | | 2.55 | 1.95 |
Nuclear | | | 0.75 | 0.78 |
Coal | | | 2.82 | 2.88 |
Average cost of fuel, generated (in cents per net KWH)(a) | | | 2.26 | 1.86 |
Average cost of purchased power (in cents per net KWH)(b) | | | 5.10 | 3.90 |
(a)First quarter 2021 excludes Central Alabama Generating Station KWHs and associated cost of fuel as its fuel is provided by the purchaser under a power sales agreement. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
(b)Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of the Southern Company system's generation and purchased power were as follows:
|
| | | | |
| Second Quarter 2020 | Second Quarter 2019 | Year-to-Date 2020 | Year-to-Date 2019 |
Total generation (in billions of KWHs) | 41 | 46 | 82 | 90 |
Total purchased power (in billions of KWHs) | 4 | 4 | 9 | 8 |
Sources of generation (percent) — | | | | |
Gas | 55 | 52 | 54 | 50 |
Nuclear | 19 | 22 | 19 | 22 |
Coal | 12 | 16 | 13 | 16 |
Hydro | 5 | 3 | 6 | 5 |
Other | 9 | 7 | 8 | 7 |
Cost of fuel, generated (in cents per net KWH)— | | | | |
Gas | 1.89 | 2.39 | 1.92 | 2.47 |
Nuclear | 0.78 | 0.80 | 0.78 | 0.80 |
Coal | 2.96 | 3.04 | 2.92 | 2.98 |
Average cost of fuel, generated (in cents per net KWH) | 1.79 | 2.26 | 1.82 | 2.29 |
Average cost of purchased power (in cents per net KWH)(*) | 4.74 | 4.81 | 4.30 | 4.73 |
| |
(*) | Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider. |
Fuel
In the secondfirst quarter 2020,2021, fuel expense was $621$848 million compared to $914$636 million for the corresponding period in 2019.2020. The decreaseincrease was primarily due to a 49.3% decrease79.2% increase in the volume of KWHs generated by coal, a 20.9%43.4% decrease in the volume of KWHs generated by hydro, and a 30.8% increase in the average cost of natural gas per KWH generated, partially offset by a 2.6%9.1% decrease in the volume of KWHs generated by natural gas and a 2.1% decrease in the average cost of coal per KWH generated, andgenerated.
Purchased Power
In the first quarter 2021, purchased power expense was $207 million compared to $181 million for the corresponding period in 2020. The increase was primarily due to a 5.2%30.8% increase in the average cost per KWH purchased primarily due to higher natural gas prices, partially offset by an 8.4% decrease in the volume of KWHs generated by natural gas.purchased.
For year-to-date 2020, fuel expense was $1.3 billionEnergy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to $1.8 billion for the corresponding period in 2019. The decrease was primarily due to a 44.1% decrease in the volume of KWHs generated by coal, a 22.3% decrease in the average cost of natural gas per KWH generated, a 2.0% decrease in the average costSouthern Company system's generation, and the availability of coal per KWH generated, and a 0.5% decrease in the volume of KWHs generated by natural gas.Southern Company system's generation.
Cost of Natural Gas
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(47) | | (24.6) | | $(294) | | (33.5) |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $144 | | 32.8 |
Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities. Cost of natural gas at the natural gas distribution utilities represented 86% of total cost of natural gas for both the secondfirst quarter and year-to-date 2020.2021.
In the secondfirst quarter 2020, cost of natural gas was $144 million compared to $191 million for the corresponding period in 2019. The decrease reflects a 34.9% decrease in natural gas prices in the second quarter 2020 compared to the corresponding period in 2019.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
For year-to-date 2020,2021, cost of natural gas was $583 million compared to $877$439 million for the corresponding period in 2019.2020. The decreaseincrease reflects a 36.6% decreasehigher volumes sold due to colder weather and higher gas cost recovery in natural gas prices compared to 2019 and decreased volumes primarily as a result of warmer weather, as determined by Heating Degree Days, for year-to-date 2020the first quarter 2021 compared to the corresponding period in 2019.2020. The increase also reflects a 38% increase in natural gas prices in the first quarter 2021 compared to the corresponding period in 2020.
Cost of Other Sales
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(10) | | (11.9) | | $(74) | | (36.5) |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $27 | | 49.1 |
In the secondfirst quarter 2020,2021, cost of other sales was $74$82 million compared to $84$55 million for the corresponding period in 2019. For year-to-date 2020, cost of other sales was $1292020. The increase primarily relates to a $14 million compared to $203 million for the corresponding periodincrease in 2019. These decreases primarily relate to changes in PowerSecure's business, including the sale of its utility infrastructure services business in June 2019 and the wind-down of a segment of its distributed infrastructure business in the first quarter 2020, partially offset byand energy efficiency projects at PowerSecure and an increase of $8 million in expenses related to unregulated sales at Georgia Power largely associated with power delivery construction and maintenance contracts. See Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K for additional information.contracts at Georgia Power.
Other Operations and Maintenance Expenses
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(117) | | (8.9) | | $(136) | | (5.2) |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $76 | | 5.9 |
In the secondfirst quarter 2020,2021, other operations and maintenance expenses were $1.2$1.37 billion compared to $1.3$1.30 billion for the corresponding period in 2019.2020. The decreaseincrease reflects the impacts of cost containment activities implemented in 2020 to help offset the effects of the recessionary economy resulting from the COVID-19 pandemic, as well as a $32 million goodwill impairment charge in the second quarter 2019 associated with the sale of PowerSecure's utility infrastructure services business unit. The decrease primarily results from decreases of $82 million in scheduled generation outage and maintenance expenses and $17 million in compliance and environmental expenses at the traditional electric operating companies. The decrease also reflects decreases of $14 million in transmission and distribution maintenance expenses, primarily at Alabama Power and Georgia Power, including $11 million of reliability NDR credits at Alabama Power, partially offset by a $46$55 million increase in storm damage recovery at Georgia Power as authorized in its 2019 ARP.employee compensation and
For year-to-date 2020, other operations and maintenance expenses were $2.5 billion compared to $2.6 billion for the corresponding period in 2019. The decrease reflects the impacts of cost containment activities implemented in 2020 to help offset the effects of the recessionary economy resulting from the COVID-19 pandemic, as well as a $32 million goodwill impairment charge in the second quarter 2019 associated with the sale of PowerSecure's utility infrastructure services business unit. The decrease primarily results from decreases of $111 million in scheduled generation outage and maintenance expenses and $42 million in transmission and distribution expenses at the traditional electric operating companies, including $22 million of reliability NDR credits at Alabama Power, partially offset by a $92 million increase in storm damage recovery at Georgia Power as authorized in its 2019 ARP.92
See Note 2 to the financial statements under "Alabama Power – Rate NDR" and " – Rate CNP Compliance" and "Georgia Power – Storm Damage Recovery" and Note 15 to the financial statements under "Southern Company" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
benefit expenses, primarily at Southern Company Gas, and a $15 million decrease in nuclear property insurance refunds at Alabama Power and Georgia Power.
Depreciation and Amortization
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$118 | | 15.6 | | $224 | | 14.9 |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $14 | | 1.6 |
In the secondfirst quarter 2020,2021, depreciation and amortization was $873$871 million compared to $755$857 million for the corresponding period in 2019. For year-to-date 2020,2020. The increase primarily reflects a $37 million increase in depreciation and amortization was $1.7 billion compared to $1.5 billion for the corresponding periodassociated with additional plant in 2019. These increases primarily reflect increasedservice, partially offset by decreased amortization of regulatory assets related to CCR AROs of $63$22 million and $127 million forunder the second quarter and year-to-date 2020, respectively, and higher depreciationterms of $44 million and $89 million for the second quarter and year-to-date 2020, respectively, as authorized in Georgia Power's 2019 ARP. See Note (B) to the Condensed Financial Statements under "Georgia Power – Rate Plan" herein and Note 2 to the financial statements under "Georgia Power – Rate Plans" and "Plans – Integrated Resource Plan"2019 ARP" in Item 8 of the Form 10-K for additional information.information regarding Georgia Power's recovery of costs associated with CCR AROs.
Taxes Other Than Income Taxes
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $15 | | 4.5 |
In the first quarter 2021, taxes other than income taxes were $345 million compared to $330 million for the corresponding period in 2020. The increase primarily reflects increased property taxes and an increase in revenue tax expenses as a result of higher natural gas revenues at Southern Company Gas.
Estimated Loss on Plant Vogtle Units 3 and 4
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$149 | | N/M | | $149 | | N/M |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $48 | | N/M |
N/M - Not meaningful
In the secondfirst quarter 2020,2021, an estimated probable loss of $149$48 million was recorded at Georgia Power to reflect its revised total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under ""Georgia Power – Nuclear Construction"Construction" herein for additional information.
(Gain) Loss on Dispositions, Net
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $5 | | 12.8 |
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(8) | | N/M | | $(2,467) | | N/M |
N/M - Not meaningful
For year-to-date 2020, gainIn the first quarter 2021, (gain) loss on dispositions, net was $39$44 million compared to $2.5 billion$39 million for the corresponding period in 2019.2020. The decrease wasfirst quarter 2021 amount includes $39 million in gains at Southern Power, primarily duefrom contributions of wind turbine equipment to various equity method investments, and $4 million in gains from property sales at Alabama Power. In the $2.5 billion ($1.3 billion after tax) preliminaryfirst quarter 2020, Southern Power recorded a $39 million gain onrelated to the sale of Gulf Power recorded inPlant Mankato. See Notes (E) and (K) to the first quarter 2019. SeeCondensed Financial Statements under "Southern Power" herein and Note 15 to the financial statements under "Southern Company"Power – Sales of Natural Gas and Biomass Plants" in Item 8 of the Form 10-K for additional information.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$15 | | 3.5 | | $41 | | 4.8 |
In the second quarter 2020, interest expense, net of amounts capitalized was $444 million compared to $429 million for the corresponding period in 2019. For year-to-date 2020, interest expense, net of amounts capitalized was $900 million compared to $859 million for the corresponding period in 2019. These increases were primarily due to an increase in average outstanding long-term borrowings primarily at the parent company. Additionally, the year-to-date 2020 increase was due to an increase in average outstanding long-term borrowings primarily at Georgia Power. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein and Note 8 to the financial statements in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Allowance for Equity Funds Used During Construction
Impairment of Leveraged Lease | | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $12 | | 35.3 |
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$154 | | N/M | | $154 | | N/M |
N/M - Not meaningful
In the secondfirst quarter 2020,2021, allowance for equity funds used during construction was $46 million compared to $34 million for the corresponding period in 2020. The increase was primarily due to an impairment chargeincrease in AFUDC equity associated with the construction of $154 million was recorded related to a leveraged lease investment at Southern Holdings.Plant Vogtle Units 3 and 4. See Note (C)(B) to the Condensed Financial Statements under "Other Matters"Georgia Power – Southern Company"Nuclear Construction" herein for additional information.information regarding Plant Vogtle Units 3 and 4.
Other Income (Expense), Net
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$2 | | 2.0 | | $28 | | 15.9 |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $(45) | | (43.7) |
In the secondfirst quarter 2020,2021, other income (expense), net was $101$58 million compared to $99$103 million for the corresponding period in 2019. For year-to-date 2020, other income (expense), net2020. The decrease was $204primarily due to $75 million compared to $176in charitable contributions at Southern Company Gas in the first quarter 2021, partially offset by a $27 million for the corresponding period in 2019. These increases were primarily related to an increase in non-service cost-related retirement benefits income, partially offset by a gain at Southern Power from a litigation settlement in the second quarter 2019.income. See Note 3 to the financial statements under "General Litigation Matters – Southern Power" in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein for additional information.
Income Taxes
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $45 | | 31.0 |
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(140) | | (96.6) | | $(1,355) | | (90.0) |
In the secondfirst quarter 2020,2021, income taxes were $5$190 million compared to $145 million for the corresponding period in 2019. For year-to-date 2020, income taxes were $150 million compared to $1.5 billion for the corresponding period in 2019.2020. The second quarter 2020 decreaseincrease was primarily due to the tax impacts of charges associated with a leveraged lease impairment and the construction of Plant Vogtle Units 3 and 4, as well as the flowback of excess deferred income taxes in 2020 as authorized in Georgia Power's 2019 ARP,higher pre-tax earnings, partially offset by ITCs recognized upon$16 million in tax benefits resulting from new legislation that changed Southern Power's sale of Plant Nacogdoches in the second quarter 2019. The year-to-date 2020 decrease also reflects the tax impacts of the sale of Gulf Power in 2019.state apportionment methodology. See Notes 2 and 15 to the financial statements under "Georgia Power – Rate Plans – Tax Reform Settlement Agreement" and "Southern Company," respectively, in Item 8 of the Form 10-K and Notes (B), (C), andNote (G) to the Condensed Financial Statements under "Georgia Powerherein and MANAGEMENT'S DISCUSSION AND ANALYSIS – Nuclear Construction," "OtherFUTURE EARNINGS POTENTIAL – "Income Tax Matters – Southern Company," and "EffectiveAlabama State Tax Rate," respectively, hereinReform Legislation" in Item 7 of the Form 10-K for additional information.
Alabama Power
Net Income (Loss) Attributable to Noncontrolling Interests
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $79 | | 28.2 |
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(24) | | N/M | | $(26) | | N/M |
N/M - Not meaningful
In the second quarter 2020,Alabama Power's net income attributable to noncontrolling interestsafter dividends on preferred stock for the first quarter 2021 was $5$359 million compared to $29$280 million for the corresponding period in 2019. For year-to-date 2020, net loss attributable2020. The increase was primarily due to noncontrolling interestsan increase in retail revenues associated with an increase in Rate RSE effective in January 2021 and colder weather in Alabama Power's service territory in the first quarter 2021 compared to the corresponding period in 2020.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Retail Revenues
was $26 million | | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $147 | | 12.2 |
In the first quarter 2021, retail revenues were $1.35 billion compared to an immaterial amount$1.21 billion for the corresponding period in 2019. The2020.
Details of the changes in retail revenues were primarily due to an allocation of approximately $26 million of income to the noncontrolling interest partner related to a litigation settlement at Southern Poweras follows:
| | | | | | | | | | | | | | | |
| | | First Quarter 2021 |
| | | | | (in millions) | | (% change) |
Retail – prior year | | | | | $ | 1,205 | | | |
Estimated change resulting from – | | | | | | | |
Rates and pricing | | | | | 50 | | | 4.1 | % |
Sales decline | | | | | (4) | | | (0.3) | |
Weather | | | | | 39 | | | 3.2 | |
Fuel and other cost recovery | | | | | 62 | | | 5.2 | |
Retail – current year | | | | | $ | 1,352 | | | 12.2 | % |
Revenues associated with changes in rates and pricing increased in the secondfirst quarter 2019. See Note 3 to the financial statements in Item 8 of the Form 10-K under "General Litigation Matters – Southern Power" for additional information.
Alabama Power
Net Income
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) |
| (% change) |
| (change in millions) |
| (% change) |
$2 | | 0.7 | | $65 | | 12.7 |
Alabama Power's net income after dividends on preferred stock for the second quarter 2020 was $298 million2021 when compared to $296 million for the corresponding period in 2019. This increase was2020 primarily due to a decrease in operations and maintenance expenses and anRate RSE increase in Rate CNP Compliance-related revenues associated with increased capital investments. These increases to income were partially offset by decreases in retail revenues associated with milder weather in the second quarter 2020 compared to the same period in 2019 and lower customer usage.
Alabama Power's net income after dividends on preferred stock for year-to-date 2020 was $578 million compared to $513 million for the corresponding period in 2019. This increase was primarily due to a decrease in operations and maintenance expenses and an increase in retail revenues associated with the impact of customer bill credits issued in 2019 related to Tax Reform. These increases to income were partially offset by decreases in retail revenues associated with milder weather in the first and second quarters 2020 compared to the same periods in 2019 and lower customer usage.effective January 1, 2021. See Note 2 to the financial statements under "Alabama Power – Rate RSE" in Item 8 of the Form 10-K for additional information.
Retail Revenues
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(155) | | (11.2) | | $(165) | | (6.4) |
In the second quarter 2020, retail revenues were $1.22 billion compared to $1.38 billion for the corresponding period in 2019. For year-to-date 2020, retail revenues were $2.43 billion compared to $2.59 billion for the corresponding period in 2019.
Details of the changes in retail revenues were as follows:
|
| | | | | | | | | | | | | |
| Second Quarter 2020 |
| Year-to-Date 2020 |
| (in millions) |
| (% change) |
| (in millions) |
| (% change) |
Retail – prior year | $ | 1,378 |
| | | | $ | 2,592 |
| | |
Estimated change resulting from – | | | | | | | |
Rates and pricing | 12 |
| | 0.9 | % | | 63 |
| | 2.4 | % |
Sales decline | (39 | ) | | (2.8 | ) | | (46 | ) | | (1.8 | ) |
Weather | (39 | ) | | (2.8 | ) | | (53 | ) | | (2.0 | ) |
Fuel and other cost recovery | (89 | ) | | (6.5 | ) | | (129 | ) | | (5.0 | ) |
Retail – current year | $ | 1,223 |
| | (11.2 | )% | | $ | 2,427 |
| | (6.4 | )% |
Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2020 when compared to the corresponding periods in 2019. The second quarter increase was primarily due to an increase in
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Rate CNP Compliance-related revenue. The year-to-date increase was primarily due to customer bill credits issued in the first quarter 2019 related to Tax Reform and Rate CNP Compliance-related revenue.
Revenues attributable to changes in sales decreased in the secondfirst quarter and year-to-date 20202021 when compared to the corresponding periodsperiod in 2019 largely due to social distancing and shelter-in-place guidelines related to the COVID-19 pandemic.2020. Weather-adjusted residential KWH sales increased 4.6% and 3.5%were relatively flat in the secondfirst quarter and year-to-date 2020, respectively,2021 when compared to the corresponding periodsperiod in 2019 primarily due to customer growth and an increase in average customer usage as a result of shelter-in-place orders and the temporary suspension of customer disconnections.2020. Weather-adjusted commercial KWH sales decreased 12.2% and 7.3%2.1% in the secondfirst quarter and year-to-date 2020, respectively,2021 when compared to the corresponding periodsperiod in 20192020 primarily due to lower customer usage resulting from shelter-in-place orderschanges in consumer and restrictions on business operationsbehavior in response to the COVID-19 pandemic. Industrial KWH sales decreased 15.5% and 8.7%5.4% in the secondfirst quarter and year-to-date 2020, respectively,2021 when compared to the corresponding periodsperiod in 20192020 primarily as a result of disruptions in supply chaincustomer closures and business operations driven bymaintenance outages, as well as continued consumer responses to the COVID-19 pandemic and the overall decrease in business activity due to the resulting recession.pandemic.
Fuel and other cost recovery revenues decreasedincreased in the secondfirst quarter and year-to-date 20202021 when compared to the corresponding periodsperiod in 20192020 primarily due to decreasesincreases in generation and the average cost of fuel.
Electric rates include provisions to recognize the recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
Wholesale Revenues – Non-Affiliates
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(8) | | (12.9) | | $(12) | | (9.8) |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $36 | | 64.3 |
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale
energy compared to the cost of Alabama Power's and the Southern Company system's generation, demand for
energy within the Southern Company system's electric service territory, and the availability of the Southern Company
system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by
an increase or decrease in fuel costs and do not affect net income. Short-term opportunity energy sales are also
included in wholesale energy sales to non-affiliates. These opportunity sales are made at market-based rates that
generally provide a margin above Alabama Power's variable cost to produce the energy.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
In the secondfirst quarter 2020,2021, wholesale revenues from sales to non-affiliates were $54$92 million compared to $62$56 million for the corresponding period in 2019. For year-to-date 2020, wholesale2020. The increase consisted of a $19 million increase in energy revenues from sales to non-affiliates were $111 million compared to $123 million for the corresponding period in 2019. These decreases were primarily due to decreases of 16.0% and 9.8% in the price of energy in the second quarter and year-to-date 2020, respectively, primarily due to lowerhigher natural gas prices and a $17 million increase in 2020 comparedcapacity revenues primarily related to the corresponding periodsa power sales agreement that began in 2019. Also contributing to the increase for the second quarter 2020 was a 3.2% decrease in KWH sales as a result of lower market demand.September 2020.
Wholesale Revenues – Affiliates
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$3 | | 75.0 | | $(37) | | (58.7) |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $13 | | 68.4 |
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.
For year-to-date 2020,In the first quarter 2021, wholesale revenues from sales to affiliates were $26$32 million compared to $63$19 million for the corresponding period in 2019.2020. The decreaseincrease was primarily due to a 46.6% decrease in KWH sales as a result of decreased coal generation largely due to lower natural gas prices and a 25.9% decrease40.5% increase in the price of energy and an 18.7% increase in KWH sales due to lowerincreased coal generation as the result of higher natural gas prices in 2020the first quarter 2021 compared to the corresponding period in 2019.2020.
Other Revenues
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$12 | | 17.4 | | $9 | | 6.3 |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $12 | | 16.9 |
In the secondfirst quarter 2020,2021, other revenues were $81$83 million compared to $69$71 million for the corresponding period in 2019. This2020. The increase was primarily due to an increaseincreases of $7 million in transmission and energy service revenues associated with the timing ofand $2 million in customer refunds and an increase in unregulated sales of products and services associated with energy efficiency and equipment upgrade projects.fees.
Fuel and Purchased Power Expenses
| | | Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | | First Quarter 2021 vs. First Quarter 2020 |
| (change in millions) |
| (% change) | | (change in millions) | | (% change) | | | (change in millions) | | (% change) |
Fuel | $ | (53 | ) | | (21.0 | ) | | $ | (138 | ) | | (25.0 | ) | Fuel | | $ | 76 | | | 35.3 | |
Purchased power – non-affiliates | 2 |
| | 4.3 |
| | 5 |
| | 6.0 |
| Purchased power – non-affiliates | | 10 | | | 25.0 | |
Purchased power – affiliates | (39 | ) | | (56.5 | ) | | (41 | ) | | (45.6 | ) | Purchased power – affiliates | | 12 | | | 66.7 | |
Total fuel and purchased power expenses | $ | (90 | ) | | | | $ | (174 | ) | | | Total fuel and purchased power expenses | | $ | 98 | | |
In the secondfirst quarter 2020,2021, total fuel and purchased power expenses were $278$371 million compared to $368$273 million for the corresponding period in 2019.2020. The decreaseincrease was primarily due to a $77$59 million decrease inincrease related to the volume of KWHs generated (excluding hydro) and purchased and a $13$39 million net decreaseincrease in the average cost of generation and purchased power.
For year-to-date 2020, fuel and purchased power expenses were $553 million compared to $727 million for the corresponding period in 2019. The decrease was primarily due to a $140 million decrease in the volume of KWHs generated (excluding hydro) and purchased and a $34 million net decrease in the average cost of generation and purchased power.
Fuel and purchased power energy transactions do not have a significant impact on earnings, since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. See Note 2 to the financial statements under "Alabama Power – Rate ECR" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of Alabama Power's generation and purchased power were as follows:
| | | | | | | | | | | | | | | |
| | | | | First Quarter 2021 | | First Quarter 2020 |
Total generation (in billions of KWHs)(a) | | | | | 15 | | 14 |
Total purchased power (in billions of KWHs) | | | | | 1 | | 1 |
Sources of generation (percent)(a) — | | | | | | | |
Coal | | | | | 46 | | 34 |
Nuclear | | | | | 25 | | 28 |
Gas | | | | | 19 | | 20 |
Hydro | | | | | 10 | | 18 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
Coal | | | | | 2.75 | | 2.64 |
Nuclear | | | | | 0.72 | | 0.76 |
Gas(a) | | | | | 2.51 | | 2.19 |
Average cost of fuel, generated (in cents per net KWH)(a) | | | | | 2.14 | | 1.88 |
Average cost of purchased power (in cents per net KWH)(b) | | | | | 6.52 | | 4.86 |
|
| | | | | | | |
| Second Quarter 2020 | | Second Quarter 2019 | | Year-to-Date 2020 |
| Year-to-Date 2019 |
Total generation (in billions of KWHs) | 12 | | 12 | | 26 | | 29 |
Total purchased power (in billions of KWHs) | 2 | | 3 | | 3 | | 4 |
Sources of generation (percent) — | | | | | | | |
Coal | 33 | | 43 | | 33 | | 43 |
Nuclear | 32 | | 26 | | 30 | | 24 |
Gas | 24 | | 23 | | 22 | | 21 |
Hydro | 11 | | 8 | | 15 | | 12 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
Coal | 2.82 | | 2.86 | | 2.72 | | 2.82 |
Nuclear | 0.75 | | 0.78 | | 0.75 | | 0.78 |
Gas | 1.95 | | 2.48 | | 2.07 | | 2.53 |
Average cost of fuel, generated (in cents per net KWH) | 1.85 | | 2.18 | | 1.86 | | 2.19 |
Average cost of purchased power (in cents per net KWH)(*) | 4.29 | | 4.01 | | 4.51 | | 4.45 |
(a)First quarter 2021 excludes Central Alabama Generating Station KWHs and associated cost of fuel as its fuel is provided by the purchaser under a power sales agreement. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information. | |
(*) | Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider. |
(b)Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.
Fuel
In the secondfirst quarter 2020,2021, fuel expense was $199$291 million compared to $252$215 million for the corresponding period in 2019.2020. The decreaseincrease was primarily due to a 25.6% decrease44.6% increase in the volume of KWHs generated by coal, a 21.4%44.0% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, and increases of 23.5% and 18.9% in the volume of KWHs generated by hydro, and nuclear, respectively.a 14.6% increase in the average cost of KWHs generated by natural gas, which excludes tolling agreements.
For year-to-date 2020, fuelPurchased Power – Non-Affiliates
In the first quarter 2021, purchased power expense from non-affiliates was $415$50 million compared to $553$40 million for the corresponding period in 2019.2020. The decreaseincrease was primarily due to a 29.6% decrease31.1% increase in the average cost per KWH purchased as a result of higher natural gas prices and a 12.9% increase in the volume of KWHs generated by coal, an 18.2% decreasepurchased due to a PPA which began in September 2020.
Energy purchases from non-affiliates will vary depending on the averagemarket prices of wholesale energy as compared to
the cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements,the Southern Company system's generation, demand for energy within the Southern Company system's
electric service territory, and increasesthe availability of 11.9% and 11.0% in the volume of KWHs generated by nuclear and hydro, respectively.Southern Company system's generation.
Purchased Power – Affiliates
In the secondfirst quarter 2020,2021, purchased power expense from affiliates was $30 million compared to $69$18 million for the corresponding period in 2019. For year-to-date 2020,2020. The increase was primarily due to a 39.9% increase in the average cost per KWH purchased power expense from affiliates was $49 millionas a result of higher natural gas prices and a 17.9% increase in the volume of KWHs purchased due to colder weather in the first quarter 2021 when compared to $90 million for the corresponding period in 2019. The second quarter and year-to-date 2020 decreases were primarily due to reductions of 50.8% and 43.7%, respectively, in the amount of energy purchased due to milder weather during 2020 as compared to 2019 and decreases of 10.7% and 4.3%, respectively, in the average cost of purchased power per KWH as a result of lower natural gas prices in 2020 compared to the corresponding periods in 2019.2020.
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Operations and Maintenance Expenses
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(60) | | (14.9) | | $(122) | | (15.0) |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $11 | | 3.1 |
In the secondfirst quarter 2020,2021, other operations and maintenance expenses were $342$361 million compared to $402$350 million for the corresponding period in 2019. For year-to-date 2020, other operations and maintenance expenses were $690 million compared2020. The increase was primarily due to $812 million for the corresponding period in 2019. These decreases reflect the impactsan increase of cost containment activities implemented to help offset the effects of the recessionary economy resulting from the COVID-19 pandemic. The decreases primarily result from $43 million and $78 million decreases in generation expenses associated with scheduled outages and CNP Compliance-related expenses for the second quarter and year-to-date 2020, respectively, as well as $10 million and $29 million decreases in transmission and distribution maintenance expenses primarily related to reliability NDR credits for the second quarterapplied in 2020 and year-to-date 2020, respectively. Also contributing to the year-to-date 2020 decrease was a $12$6 million increasereduction in nuclear property insurance refunds.
These increases were partially offset by a $3 million decrease in Rate CNP Compliance-related expenses. See Note 2 to the financial statements under "Alabama Power – Rate NDR" and " – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.
Depreciation and Amortization
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $11 | | 5.5 |
In the first quarter 2021, depreciation and amortization was $211 million compared to $200 million for the corresponding period in 2020. The increase was primarily due to additional plant in service, including the purchase of the Central Alabama Generating Station in August 2020. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
Other Income (Expense), Net
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$15 | | 136.4 | | $23 | | 92.0 |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $8 | | 33.3 |
In the secondfirst quarter 2020,2021, other income (expense), net was $26$32 million compared to $11$24 million for the corresponding period in 2019. For year-to-date 2020, other income (expense), net2020. The increase was $48 million compared to $25 million for the corresponding period in 2019. These increases were primarily due to an increase in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.
Income Taxes
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $26 | | 31.0 |
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$4 | | 4.5 | | $26 | | 17.2 |
For year-to-date 2020,In the first quarter 2021, income taxes were $177$110 million compared to $151$84 million for the corresponding period in 2019. This2020. The increase was primarily due to higher pre-tax earnings.
Georgia Power
Net Income
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(140) | | (31.3) | | $(121) | | (15.9) |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $20 | | 6.0 |
Georgia Power's net income for the secondfirst quarter 20202021 was $308$351 million compared to $448$331 million for the corresponding period in 2019. For year-to-date 2020, net income2020. The increase was $638 millionprimarily due to higher retail revenues associated with colder weather in the first quarter 2021 compared to $759 million for the corresponding period in 2019. These decreases were primarily due to2020, partially offset by a $111$36 million after-tax charge in the secondfirst quarter 20202021 related to the construction of Plant Vogtle Units 3 and 4 and impacts of the 2019 ARP effective January4. See Note (B) to
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
1, 2020, including higher depreciation and amortization, largely offset by increased retail rates and lower income tax expense. Also contributing to the decreases were lower retail revenues associated with milder weather as compared to the corresponding periods in 2019 and decreased customer usage resulting from the COVID-19 pandemic, partially offset by related cost containment activities. See Note (B) to the Condensed Financial Statements under ""Georgia Power – Nuclear Construction"Construction" herein for additional information on the construction ofregarding Plant Vogtle Units 3 and 4 and Note 2 to the financial statements under "Georgia Power" in Item 8 of the Form 10-K for additional information on the 2019 ARP.4.
Retail Revenues
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(186) | | (9.6) | | $(179) | | (5.0) |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $112 | | 6.7 |
In the secondfirst quarter 2020,2021, retail revenues were $1.76$1.79 billion compared to $1.95$1.68 billion for the corresponding period in 2019. For year-to-date 2020, retail revenues were $3.44 billion compared to $3.61 billion for the corresponding period in 2019.2020.
Details of the changes in retail revenues were as follows:
| | | Second Quarter 2020 | | Year-to-Date 2020 | | | First Quarter 2021 |
| (in millions) | | (% change) | | (in millions) | | (% change) | | | (in millions) | | (% change) |
Retail – prior year | $ | 1,946 |
| | | | $ | 3,614 |
| | | Retail – prior year | | $ | 1,675 | | |
Estimated change resulting from – | | | | | | | | Estimated change resulting from – | | |
Rates and pricing | 116 |
| | 5.9 | % | | 209 |
| | 5.8 | % | Rates and pricing | | (18) | | | (1.1) | % |
Sales decline | (63 | ) | | (3.2 | ) | | (47 | ) | | (1.3 | ) | Sales decline | | (6) | | | (0.4) | |
Weather | (88 | ) | | (4.5 | ) | | (107 | ) | | (3.0 | ) | Weather | | 42 | | | 2.5 | |
Fuel cost recovery | (151 | ) | | (7.8 | ) | | (234 | ) | | (6.5 | ) | Fuel cost recovery | | 94 | | | 5.7 | |
Retail – current year | $ | 1,760 |
| | (9.6 | )% | | $ | 3,435 |
| | (5.0 | )% | Retail – current year | | $ | 1,787 | | | 6.7 | % |
Revenues associated with changes in rates and pricing increaseddecreased in the secondfirst quarter and year-to-date 2020,2021 when compared to the corresponding periodsperiod in 2019. These increases were2020. The decrease was primarily due to an increasea decrease in revenue recognized under the ECCRNCCR tariff effective January 1, 2020 as authorized in the 2019 ARP, the impacts of accruals in 2019 for customer refunds related to Tax Reform, and the rate pricing effects of decreased customer usage in 2020. Partially offsetting these increases were lower contributions from commercial and industrial customers with variable demand-driven pricing.2021. See Note 2(B) to the financial statementsCondensed Financial Statements under "Georgia Power" in Item 8 of the Form 10-KPower – Nuclear Construction – Regulatory Matters" herein for additional information.
Revenues attributable to changes in sales decreased in the secondfirst quarter and year-to-date 20202021 when compared to the corresponding periodsperiod in 2019 largely2020 primarily due to social distancing and shelter-in-place guidelines related tocontinued impacts of the COVID-19 pandemic.pandemic, partially offset by customer growth. Weather-adjusted residential KWH sales increased 4.7% and 4.1%2.0% in the secondfirst quarter and year-to-date 2020, respectively,2021 when compared to corresponding periodsperiod in 20192020 primarily due to customer growth and an increase in average customer usage, primarily due to the temporary suspension of customer disconnections for nonpayment and shelter-in-place orders.growth. Weather-adjusted commercial KWH sales decreased 11.3% and 5.8%3.3% in the secondfirst quarter and year-to-date 2020, respectively,2021 when compared to the corresponding periodsperiod in 20192020 primarily due to lower customer usage resulting from shelter-in-place orderschanges in consumer and restrictions on business operationsbehavior in response to the COVID-19 pandemic.pandemic, partially offset by customer growth. Weather-adjusted industrial KWH sales decreased 13.4% and 8.4%increased 1.1% in the secondfirst quarter and year-to-date 2020, respectively,2021 when compared to the corresponding periodsperiod in 20192020 primarily as a result of increases in the pipeline and lumber segments, partially offset by reductions in the textiles, transportation, and chemicals segments as a result of disruptions in supply chain and business operations related to the COVID-19 pandemic and the overall decrease in business activity due to the resulting recession.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
pandemic.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreasedincreased in the secondfirst quarter and year-to-date 20202021 when compared to the corresponding periodsperiod in 20192020 due to lowerhigher fuel and purchased power costs. Electric rates include provisions to periodically adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – GeorgiaNote 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" in Item 78 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Wholesale RevenuesPurchased Power
In the first quarter 2021, purchased power expense was $207 million compared to $181 million for the corresponding period in 2020. The increase was primarily due to a 30.8% increase in the average cost per KWH purchased primarily due to higher natural gas prices, partially offset by an 8.4% decrease in the volume of KWHs purchased. |
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(11) | | (30.6) | | $(16) | | (23.9) |
Energy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.WholesaleCost of Natural Gas
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $144 | | 32.8 |
Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities. Cost of natural gas at the natural gas distribution utilities represented 86% of total cost of natural gas for the first quarter 2021.
In the first quarter 2021, cost of natural gas was $583 million compared to $439 million for the corresponding period in 2020. The increase reflects higher volumes sold due to colder weather and higher gas cost recovery in the first quarter 2021 compared to the corresponding period in 2020. The increase also reflects a 38% increase in natural gas prices in the first quarter 2021 compared to the corresponding period in 2020.
Cost of Other Sales
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $27 | | 49.1 |
In the first quarter 2021, cost of other sales was $82 million compared to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity$55 million for the corresponding period in 2020. The increase primarily relates to a $14 million increase in distributed infrastructure and energy components. Wholesale capacity revenues from PPAs are recognized either onefficiency projects at PowerSecure and an increase of $8 million in unregulated power delivery construction and maintenance contracts at Georgia Power.
Other Operations and Maintenance Expenses
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $76 | | 5.9 |
In the first quarter 2021, other operations and maintenance expenses were $1.37 billion compared to $1.30 billion for the corresponding period in 2020. The increase reflects a levelized basis over$55 million increase in employee compensation and
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
benefit expenses, primarily at Southern Company Gas, and a $15 million decrease in nuclear property insurance refunds at Alabama Power and Georgia Power.
Depreciation and Amortization
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $14 | | 1.6 |
In the appropriate contractfirst quarter 2021, depreciation and amortization was $871 million compared to $857 million for the corresponding period or the amounts billablein 2020. The increase primarily reflects a $37 million increase in depreciation associated with additional plant in service, partially offset by decreased amortization of regulatory assets related to CCR AROs of $22 million under the contract terms of Georgia Power's 2019 ARP. See Note (B) to the Condensed Financial Statements under "Georgia Power – Rate Plan" herein and provideNote 2 to the financial statements under "Georgia Power – Rate Plans – 2019 ARP" in Item 8 of the Form 10-K for additional information regarding Georgia Power's recovery of fixed costs associated with CCR AROs.
Taxes Other Than Income Taxes
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $15 | | 4.5 |
In the first quarter 2021, taxes other than income taxes were $345 million compared to $330 million for the corresponding period in 2020. The increase primarily reflects increased property taxes and an increase in revenue tax expenses as a returnresult of higher natural gas revenues at Southern Company Gas.
Estimated Loss on investment. Plant Vogtle Units 3 and 4
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $48 | | N/M |
N/M - Not meaningful
In the first quarter 2021, an estimated probable loss of $48 million was recorded at Georgia Power to reflect its revised total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information.
(Gain) Loss on Dispositions, Net
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $5 | | 12.8 |
In the first quarter 2021, (gain) loss on dispositions, net was $44 million compared to $39 million for the corresponding period in 2020. The first quarter 2021 amount includes $39 million in gains at Southern Power, primarily from contributions of wind turbine equipment to various equity method investments, and $4 million in gains from property sales at Alabama Power. In the first quarter 2020, Southern Power recorded a $39 million gain related to the sale of Plant Mankato. See Notes (E) and (K) to the Condensed Financial Statements under "Southern Power" herein and Note 15 to the financial statements under "Southern Power – Sales of Natural Gas and Biomass Plants" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Allowance for Equity Funds Used During Construction
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $12 | | 35.3 |
In the first quarter 2021, allowance for equity funds used during construction was $46 million compared to $34 million for the corresponding period in 2020. The increase was primarily due to an increase in AFUDC equity associated with the construction of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
Other Income (Expense), Net
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $(45) | | (43.7) |
In the first quarter 2021, other income (expense), net was $58 million compared to $103 million for the corresponding period in 2020. The decrease was primarily due to $75 million in charitable contributions at Southern Company Gas in the first quarter 2021, partially offset by a $27 million increase in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.
Income Taxes
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $45 | | 31.0 |
In the first quarter 2021, income taxes were $190 million compared to $145 million for the corresponding period in 2020. The increase was primarily due to higher pre-tax earnings, partially offset by $16 million in tax benefits resulting from new legislation that changed Southern Power's state apportionment methodology. See Note (G) to the Condensed Financial Statements herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Alabama State Tax Reform Legislation" in Item 7 of the Form 10-K for additional information.
Alabama Power
Net Income
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $79 | | 28.2 |
Alabama Power's net income after dividends on preferred stock for the first quarter 2021 was $359 million compared to $280 million for the corresponding period in 2020. The increase was primarily due to an increase in retail revenues associated with an increase in Rate RSE effective in January 2021 and colder weather in Alabama Power's service territory in the first quarter 2021 compared to the corresponding period in 2020.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Retail Revenues
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $147 | | 12.2 |
In the first quarter 2021, retail revenues were $1.35 billion compared to $1.21 billion for the corresponding period in 2020.
Details of the changes in retail revenues were as follows:
| | | | | | | | | | | | | | | |
| | | First Quarter 2021 |
| | | | | (in millions) | | (% change) |
Retail – prior year | | | | | $ | 1,205 | | | |
Estimated change resulting from – | | | | | | | |
Rates and pricing | | | | | 50 | | | 4.1 | % |
Sales decline | | | | | (4) | | | (0.3) | |
Weather | | | | | 39 | | | 3.2 | |
Fuel and other cost recovery | | | | | 62 | | | 5.2 | |
Retail – current year | | | | | $ | 1,352 | | | 12.2 | % |
Revenues associated with changes in rates and pricing increased in the first quarter 2021 when compared to the corresponding period in 2020 primarily due to a Rate RSE increase effective January 1, 2021. See Note 2 to the financial statements under "Alabama Power – Rate RSE" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales decreased in the first quarter 2021 when compared to the corresponding period in 2020. Weather-adjusted residential KWH sales were relatively flat in the first quarter 2021 when compared to the corresponding period in 2020. Weather-adjusted commercial KWH sales decreased 2.1% in the first quarter 2021 when compared to the corresponding period in 2020 primarily due to changes in consumer and business behavior in response to the COVID-19 pandemic. Industrial KWH sales decreased 5.4% in the first quarter 2021 when compared to the corresponding period in 2020 primarily as a result of customer closures and maintenance outages, as well as continued consumer responses to the COVID-19 pandemic.
Fuel and other cost recovery revenues increased in the first quarter 2021 when compared to the corresponding period in 2020 primarily due to increases in generation and the average cost of fuel. Electric rates include provisions to recognize the recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
Wholesale Revenues – Non-Affiliates
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $36 | | 64.3 |
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of GeorgiaAlabama Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact onaffect net income. Short-term opportunity energy sales are also included in wholesale energy sales to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin above GeorgiaAlabama Power's variable cost to produce the energy.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
In the first quarter 2021, wholesale revenues from sales to non-affiliates were $92 million compared to $56 million for the corresponding period in 2020. The increase consisted of a $19 million increase in energy revenues primarily due to higher natural gas prices and a $17 million increase in capacity revenues primarily related to a power sales agreement that began in September 2020.
Wholesale Revenues – Affiliates
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $13 | | 68.4 |
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal costs.cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.
In the secondfirst quarter 2020,2021, wholesale revenues from sales to affiliates were $25$32 million compared to $36$19 million for the corresponding period in 2019. For year-to-date 2020, wholesale2020. The increase was primarily due to a 40.5% increase in the price of energy and an 18.7% increase in KWH sales due to increased coal generation as the result of higher natural gas prices in the first quarter 2021 compared to the corresponding period in 2020.
Other Revenues
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $12 | | 16.9 |
In the first quarter 2021, other revenues were $51$83 million compared to $67$71 million for the corresponding period in 2019. These decreases were primarily due to lower market demand largely resulting from the expiration of a non-affiliate PPA and lower energy prices.
Other Revenues
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$8 | | 5.9 | | $(2) | | (0.7) |
In the second quarter 2020, other revenues were $143 million compared to $135 million for the corresponding period in 2019.2020. The increase was primarily due to an increase of $14 million in unregulated sales associated with power delivery construction and maintenance contracts, partially offset by a decreaseincreases of $7 million in pole attachment revenues.
For year-to-date 2020, other revenues were $268 million compared to $270 million for the corresponding period in 2019. The decrease was primarily due to a $13 million decrease in pole attachmenttransmission and energy service revenues and an $8 million decrease in retail customer fees largely resulting from the temporary suspension of customer disconnections and late fees related to the COVID-19 pandemic, substantially offset by an increase of $20$2 million in unregulated sales associated with power delivery construction and maintenance contracts and outdoor lighting.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
customer fees.
Fuel and Purchased Power Expenses
| | | Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | | First Quarter 2021 vs. First Quarter 2020 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) | | | (change in millions) | | (% change) |
Fuel | $ | (164 | ) | | (42.1 | ) | | $ | (231 | ) | | (33.5 | ) | Fuel | | $ | 76 | | | 35.3 | |
Purchased power – non-affiliates | 9 |
| | 7.3 |
| | 20 |
| | 8.3 |
| Purchased power – non-affiliates | | 10 | | | 25.0 | |
Purchased power – affiliates | (12 | ) | | (9.0 | ) | | (59 | ) | | (19.0 | ) | Purchased power – affiliates | | 12 | | | 66.7 | |
Total fuel and purchased power expenses | $ | (167 | ) | | | | $ | (270 | ) | | | Total fuel and purchased power expenses | | $ | 98 | | |
In the secondfirst quarter 2020,2021, total fuel and purchased power expenses were $481$371 million compared to $648$273 million for the corresponding period in 2019. For year-to-date 2020, total fuel and purchased power expenses were $971 million compared to $1.24 billion for the corresponding period in 2019. These decreases were2020. The increase was primarily due to decreases of $101a $59 million and $193 million related to the average cost of fuel and purchased power and net decreases of $66 million and $77 millionincrease related to the volume of KWHs generated and purchased and a $39 million increase in second quarterthe average cost of fuel and year-to-date 2020, respectively.purchased power.
Fuel and purchased power energy transactions do not have a significant impact on earnings, since these fuelenergy expenses are generally offset by fuelenergy revenues through GeorgiaAlabama Power's fuelenergy cost recovery mechanism.clause. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – GeorgiaNote 2 to the financial statements under "Alabama Power – Fuel Cost Recovery"Rate ECR" in Item 78 of the Form 10-K for additional information.
Details of Georgia Power's generation and purchased power were as follows:
|
| | | | | | | |
| Second Quarter 2020 | | Second Quarter 2019 | | Year-to-Date 2020 | | Year-to-Date 2019 |
Total generation (in billions of KWHs) | 13 | | 16 | | 25 | | 29 |
Total purchased power (in billions of KWHs) | 8 | | 6 | | 16 | | 15 |
Sources of generation (percent) — | | | | | | | |
Gas | 56 | | 45 | | 57 | | 47 |
Nuclear | 32 | | 26 | | 30 | | 26 |
Coal | 7 | | 26 | | 7 | | 23 |
Hydro and other | 5 | | 3 | | 6 | | 4 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
Gas | 2.11 | | 2.48 | | 2.11 | | 2.53 |
Nuclear | 0.81 | | 0.81 | | 0.80 | | 0.81 |
Coal | 3.37 | | 3.18 | | 3.60 | | 3.20 |
Average cost of fuel, generated (in cents per net KWH) | 1.76 | | 2.23 | | 1.82 | | 2.22 |
Average cost of purchased power (in cents per net KWH)(*) | 3.58 | | 4.59 | | 3.36 | | 4.23 |
| |
(*) | Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider. |
Fuel
In the second quarter 2020, fuel expense was $226 million compared to $390 million for the corresponding period in 2019. For year-to-date 2020, fuel expense was $458 million compared to $689 million for the corresponding period in 2019. The decreases for the second quarter and year-to-date 2020 were primarily due to decreases of 21.1% and 18.0%, respectively, in the average cost of fuel primarily related to lower cost of natural gas and decreases of 9.2% and 6.9%, respectively, in the volume of KWHs generated largely due to lower customer demand.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of Alabama Power's generation and purchased power were as follows:
| | | | | | | | | | | | | | | |
| | | | | First Quarter 2021 | | First Quarter 2020 |
Total generation (in billions of KWHs)(a) | | | | | 15 | | 14 |
Total purchased power (in billions of KWHs) | | | | | 1 | | 1 |
Sources of generation (percent)(a) — | | | | | | | |
Coal | | | | | 46 | | 34 |
Nuclear | | | | | 25 | | 28 |
Gas | | | | | 19 | | 20 |
Hydro | | | | | 10 | | 18 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
Coal | | | | | 2.75 | | 2.64 |
Nuclear | | | | | 0.72 | | 0.76 |
Gas(a) | | | | | 2.51 | | 2.19 |
Average cost of fuel, generated (in cents per net KWH)(a) | | | | | 2.14 | | 1.88 |
Average cost of purchased power (in cents per net KWH)(b) | | | | | 6.52 | | 4.86 |
(a)First quarter 2021 excludes Central Alabama Generating Station KWHs and associated cost of fuel as its fuel is provided by the purchaser under a power sales agreement. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
(b)Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.
Fuel
In the first quarter 2021, fuel expense was $291 million compared to $215 million for the corresponding period in 2020. The increase was primarily due to a 44.6% increase in the volume of KWHs generated by coal, a 44.0% decrease in the volume of KWHs generated by hydro, and a 14.6% increase in the average cost of KWHs generated by natural gas, which excludes tolling agreements.
Purchased Power – Non-Affiliates
In the secondfirst quarter 2020,2021, purchased power expense from non-affiliates was $133$50 million compared to $124$40 million for the corresponding period in 2019. For year-to-date 2020, purchased power expense from non-affiliates2020. The increase was $262 million compared to $242 million for the corresponding period in 2019. The increases for the second quarter and year-to-date 2020 were primarily due to increases of 11.0% and 24.6%, respectively, in the volume of KWHs purchased primarily due to the availability of lower cost market resources, largely offset by decreases of 6.0% and 12.4%, respectively,a 31.1% increase in the average cost per KWH purchased primarilyas a result of higher natural gas prices and a 12.9% increase in the volume of KWHs purchased due to lower energy prices.a PPA which began in September 2020.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to
the cost of the Southern Company system's generation, demand for energy within the Southern Company system's
electric service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the secondfirst quarter 2020,2021, purchased power expense from affiliates was $122$30 million compared to $134$18 million for the corresponding period in 2019. For year-to-date 2020, purchased power expense from affiliates2020. The increase was $251 million compared to $310 million for the corresponding period in 2019. The decreases for the second quarter and year-to-date 2020 were primarily due to decreases of 32.8% and 29.0%, respectively,a 39.9% increase in the average cost per KWH purchased primarily resulting from lower energyas a result of higher natural gas prices and the expiration of a PPA. Partially offsetting the decrease in the second quarter 2020 was a 10.4%17.9% increase in the volume of KWHs purchased as Georgia Power units generally dispatched at a higher cost than other Southern Company system resources.due to colder weather in the first quarter 2021 when compared to the corresponding period in 2020.
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$— | | — | | $15 | | 1.6 |
In the second quarter 2020 and 2019, other operations and maintenance expenses were $463 million. Increases of $46 million in storm damage recovery as authorized in the 2019 ARP and $10 million in expenses from unregulated sales associated with power delivery construction and maintenance contracts were substantially offset by decreases of $22 million associated with generation maintenance and scheduled outages, $8 million associated with generation environmental projects, $7 million in customer accounts and sales costs, and $7 million in transmission-related expenses. These decreases reflect the impacts of cost containment activities implemented to help offset the effects of the recessionary economy resulting from the COVID-19 pandemic. Also contributing to the offset was a decrease of $8 million related to an adjustment in 2019 for FERC fees following the conclusion of a multi-year audit of headwater benefits associated with hydro facilities.
For year-to-date 2020, other operations and maintenance expenses were $928 million compared to $913 million for the corresponding period in 2019. The increase was primarily due to increases of $92 million in storm damage recovery as authorized in the 2019 ARP and $9 million in expenses from unregulated sales associated with power delivery construction and maintenance contracts, partially offset by decreases of $26 million associated with generation maintenance and scheduled outages, $18 million in distribution- and transmission-related expenses, and $9 million associated with generation environmental projects. These decreases reflect the impacts of cost containment activities implemented to help offset the effects of the recessionary economy resulting from the COVID-19 pandemic. Other expense reductions include a decrease of $15 million related to an adjustment in 2019 for FERC fees following the conclusion of a multi-year audit of headwater benefits associated with hydro facilities and an $11 million increase in nuclear property insurance refunds.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Operations and Maintenance Expenses
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $11 | | 3.1 |
In the first quarter 2021, other operations and maintenance expenses were $361 million compared to $350 million for the corresponding period in 2020. The increase was primarily due to an increase of $10 million related to reliability NDR credits applied in 2020 and a $6 million reduction in nuclear property insurance refunds. These increases were partially offset by a $3 million decrease in Rate CNP Compliance-related expenses. See Note 2 to the financial statements under "Georgia"Alabama Power – Storm Damage Recovery"Rate NDR" and " – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.
Depreciation and Amortization
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$110 | | 45.1 | | $224 | | 46.4 |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $11 | | 5.5 |
In the secondfirst quarter 2020,2021, depreciation and amortization was $354$211 million compared to $244$200 million for the corresponding period in 2019. For year-to-date 2020, depreciation and amortization2020. The increase was $707 million comparedprimarily due to $483 million foradditional plant in service, including the corresponding periodpurchase of the Central Alabama Generating Station in 2019. These increases primarily reflect increased amortization of regulatory assets of $63 million and $127 million for the second quarter and year-to-date 2020, respectively, and higher depreciation of $44 million and $89 million for the second quarter and year-to-date 2020, respectively, as authorized in the 2019 ARP.August 2020. See Note 215 to the financial statements under "Georgia Power – Rate Plans" and " – Integrated Resource Plan""Alabama Power" in Item 8 of the Form 10-K for additional information.
Estimated Loss on Plant Vogtle Units 3 and 4Other Income (Expense), Net
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $8 | | 33.3 |
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$149 | | N/M | | $149 | | N/M |
N/M - Not meaningful
In the secondfirst quarter 2020,2021, other income (expense), net was $32 million compared to $24 million for the corresponding period in 2020. The increase was primarily due to an estimated probable loss of $149increase in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.
Income Taxes
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $26 | | 31.0 |
In the first quarter 2021, income taxes were $110 million compared to $84 million for the corresponding period in 2020. The increase was recordedprimarily due to reflect higher pre-tax earnings.
Georgia Power
Net Income
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $20 | | 6.0 |
Georgia Power's revised total project capital cost forecastnet income for the first quarter 2021 was $351 million compared to complete$331 million for the corresponding period in 2020. The increase was primarily due to higher retail revenues associated with colder weather in the first quarter 2021 compared to the corresponding period in 2020, partially offset by a $36 million after-tax charge in the first quarter 2021 related to the construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information.
Interest Expense, Net of Amounts Capitalized
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$— | | — | | $15 | | 7.5 |
In the second quarter 2020 and 2019, interest expense, net of amounts capitalized was $105 million. For year-to-date 2020, interest expense, net of amounts capitalized was $216 million compared to $201 million for the corresponding period in 2019. The increase for year-to-date 2020 was primarily due to a $25 million increase in interest expense associated with an increase in average outstanding long-term borrowings, partially offset by an $11 million increase in amounts capitalized in connection with the construction of Plant Vogtle Units 3 and 4. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings and Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
Other Income (Expense), Net
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$16 | | 45.7 | | $26 | | 33.8 |
In the second quarter 2020, other income (expense), net was $51 million compared to $35 million for the corresponding period in 2019. For year-to-date 2020, other income (expense), net was $103 million compared to $77 million for the corresponding period in 2019. The second quarter and year-to-date 2020 increases were
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
primarily due to increases of $11 million and $21 million, respectively, in non-service cost-related retirement benefits income and increases in AFUDC equity of $5 million and $9 million, respectively, primarily associated with the construction of Plant Vogtle Units 3 and 4. See Note (H) to the Condensed Financial Statements herein for additional information on retirement benefits and Note (B) to the Condensed Financial Statements under ""Georgia Power – Nuclear Construction"Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
Income TaxesRetail Revenues
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $112 | | 6.7 |
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(118) | | (91.5) | | $(184) | | (87.2) |
In the secondfirst quarter 2020, income taxes2021, retail revenues were $11 million$1.79 billion compared to $129 million$1.68 billion for the corresponding period in 2019. For year-to-date 2020, income taxes were $27 million compared to $211 million for the corresponding period in 2019. These decreases were primarily due to the flowback of excess deferred income taxes in 2020 as authorized in the 2019 ARP and lower pre-tax earnings primarily due to the second quarter 2020 charge associated with the construction of Plant Vogtle Units 3 and 4. See Note (B) under "Nuclear Construction" and Note (G) to the Condensed Financial Statements herein and Note 2 to the financial statements under "Georgia Power – Rate Plans – Tax Reform Settlement Agreement" in Item 8 of the Form 10-K for additional information.
Mississippi Power
Net Income
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$2 | | 5.4 | | $(3) | | (4.1) |
Mississippi Power's net income for the second quarter 2020 was $39 million compared to $37 million for the corresponding period in 2019. The increase was primarily due to a decrease in amortization associated with ECO Plan regulatory assets and a decrease in scheduled generation outage costs, partially offset by a decrease in base rates that became effective for the first billing cycle of April 2020 and a decrease in revenues due to the COVID-19 pandemic.
For year-to-date 2020, net income was $71 million compared to $74 million for the corresponding period in 2019. The decrease was primarily due to a decrease in base rates that became effective for the first billing cycle of April 2020, a decrease in revenues due to the COVID-19 pandemic, and an increase in scheduled generation outage costs, partially offset by a decrease in amortization associated with ECO Plan regulatory assets.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Mississippi Power – 2019 Base Rate Case" herein and Note 2 to the financial statements under "Mississippi Power – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information.
Retail Revenues
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(16) | | (7.4) | | $(20) | | (4.8) |
In the second quarter 2020, retail revenues were $199 million compared to $215 million for the corresponding period in 2019. For year-to-date 2020, retail revenues were $398 million compared to $418 million for the corresponding period in 2019.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
2020.
Details of the changes in retail revenues were as follows:
| | | | | | | | | | | | | | | |
| | | First Quarter 2021 |
| | | | | (in millions) | | (% change) |
Retail – prior year | | | | | $ | 1,675 | | | |
Estimated change resulting from – | | | | | | | |
Rates and pricing | | | | | (18) | | | (1.1) | % |
Sales decline | | | | | (6) | | | (0.4) | |
Weather | | | | | 42 | | | 2.5 | |
Fuel cost recovery | | | | | 94 | | | 5.7 | |
Retail – current year | | | | | $ | 1,787 | | | 6.7 | % |
|
| | | | | | | | | | | | | |
| Second Quarter 2020 | | Year-to-Date 2020 |
| (in millions) | | (% change) | | (in millions) | | (% change) |
Retail – prior year | $ | 215 |
| | | | $ | 418 |
| | |
Estimated change resulting from – | | | | | | | |
Rates and pricing | (4 | ) | | (1.9 | )% | | (5 | ) | | (1.2 | )% |
Sales decline | (5 | ) | | (2.3 | ) | | (7 | ) | | (1.7 | ) |
Weather | (4 | ) | | (1.9 | ) | | 1 |
| | 0.2 |
|
Fuel and other cost recovery | (3 | ) | | (1.3 | ) | | (9 | ) | | (2.1 | ) |
Retail – current year | $ | 199 |
| | (7.4 | )% | | $ | 398 |
| | (4.8 | )% |
Revenues associated with changes in rates and pricing decreased in the secondfirst quarter and year-to-date 20202021 when compared to the corresponding periodsperiod in 20192020. The decrease was primarily due to decreasesa decrease in PEP and ECO Plan rates that becamethe NCCR tariff effective forJanuary 1, 2021. See Note (B) to the first billing cycle of April 2020, partially offset by revenue associated with a tolling arrangement. See FUTURE EARNINGS POTENTIALCondensed Financial Statements under "Georgia Power – "Nuclear Construction – Regulatory Matters – Mississippi Power – 2019 Base Rate Case"Matters" herein for additional information.
Revenues attributable to changes in sales decreased in the secondfirst quarter and year-to-date 20202021 when compared to the corresponding periodsperiod in 2019 largely2020 primarily due to lower overall customer usage resulting from shelter-in-place orders and restrictions on business operations in response tocontinued impacts of the COVID-19 pandemic.
pandemic, partially offset by customer growth. Weather-adjusted residential KWH sales increased 5.4% and 2.3%2.0% in the secondfirst quarter and year-to-date2021 when compared to corresponding period in 2020 respectively, primarily due to customer growth and an increase in average customer usage as a result of shelter-in-place orders and the temporary suspension of customer disconnections.growth. Weather-adjusted commercial KWH sales decreased 11.6% and 7.9%3.3% in the secondfirst quarter and year-to-date2021 when compared to the corresponding period in 2020 respectively, primarily due to lower customer usage resulting from shelter-in-place orderschanges in consumer and restrictions on business operations, including the temporary closure of casinos,behavior in response to the COVID-19 pandemic. Industrialpandemic, partially offset by customer growth. Weather-adjusted industrial KWH sales decreased 7.0% and 1.3%increased 1.1% in the secondfirst quarter 2021 when compared to the corresponding period in 2020 primarily as a result of increases in the pipeline and year-to-date 2020, respectively,lumber segments, partially offset by reductions in the textiles, transportation, and chemicals segments as a result of disruptions in supply chain and business operations driven byrelated to the COVID-19 pandemic and the overall decrease in business activity due to the resulting recession.pandemic.
Fuel revenues and othercosts are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreasedincreased in the secondfirst quarter and year-to-date 20202021 when compared to the corresponding periodsperiod in 2019 primarily as a result of lower recoverable fuel costs. Recoverable fuel costs include2020 due to higher fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory.costs. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses including the energy component of purchased power costs, and do not affect net income.
Wholesale Revenues – Non-Affiliates
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(5) | | (8.8) | | $(11) | | (9.6) |
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared See Note 2 to the cost of Mississippi Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availabilityfinancial statements under "Georgia Power – Fuel Cost Recovery" in Item 8 of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. In addition, Mississippi Power provides service under long-term contracts with rural electric cooperative associationsForm 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
and municipalities located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Mississippi Power" in Item 7 of the Form 10-K for additional information.
In the second quarter 2020, wholesale revenues from sales to non-affiliates were $52 million compared to $57 million for the corresponding period in 2019. For year-to-date 2020, wholesale revenues from sales to non-affiliates were $103 million compared to $114 million for the corresponding period in 2019. These decreases were primarily due to decreases in revenue from MRA customers as a result of lower fuel costs and milder weather, as well as fewer opportunity sales.
Wholesale Revenues – Affiliates
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(12) | | (32.4) | | $(11) | | (19.0) |
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.
In the second quarter 2020, wholesale revenues from sales to affiliates were $25 million compared to $37 million for the corresponding period in 2019. For year-to-date 2020, wholesale revenues from sales to affiliates were $47 million compared to $58 million for the corresponding period in 2019. These decreases were primarily due to decreases of $18 million and $26 million in the second quarter and year-to-date 2020, respectively, associated with lower natural gas prices, partially offset by increases of $6 million and $14 million in the second quarter and year-to-date 2020, respectively, associated with higher KWH sales due to the dispatch of Mississippi Power's lower cost generation resources to serve the Southern Company system's territorial load.
Fuel and Purchased Power Expenses
|
| | | | | | | | | | | |
| Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) |
Fuel | $ | (22 | ) | | (21.0) | | $ | (36 | ) | | (18.2) |
Purchased power | 1 |
| | 16.7 | | 3 |
| | 33.3 |
Total fuel and purchased power expenses | $ | (21 | ) | | | | $ | (33 | ) | | |
In the second quarter 2020, total fuel and purchased power expenses were $90 million compared to $111 million for the corresponding period in 2019. The decrease was primarily due to a $20 million decrease related to the cost of fuel primarily due to the lower average cost of natural gas.
For year-to-date 2020, total fuel and purchased power expenses were $174 million compared to $207 million for the corresponding period in 2019. The decrease was primarily due to a $42 million decrease related to the cost of fuel and purchased power primarily due to the lower average cost of natural gas, partially offset by a $9 million increase associated with the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of Mississippi Power's generation and purchased power were as follows:
|
| | | | | | | |
| Second Quarter 2020 | | Second Quarter 2019 | | Year-to-Date 2020 | | Year-to-Date 2019 |
Total generation (in millions of KWHs) | 4,484 | | 4,621 | | 8,651 | | 8,570 |
Total purchased power (in millions of KWHs) | 208 | | 152 | | 396 | | 243 |
Sources of generation (percent) – | | | | | | | |
Coal | 4 | | 8 | | 4 | | 6 |
Gas | 96 | | 92 | | 96 | | 94 |
Cost of fuel, generated (in cents per net KWH) – | | | | | | | |
Coal | 3.82 | | 3.92 | | 4.02 | | 4.06 |
Gas | 1.88 | | 2.29 | | 1.92 | | 2.37 |
Average cost of fuel, generated (in cents per net KWH) | 1.97 | | 2.43 | | 2.00 | | 2.48 |
Average cost of purchased power (in cents per net KWH) | 3.27 | | 3.78 | | 2.97 | | 3.76 |
Fuel
In the second quarter 2020, fuel expense was $83 million compared to $105 million for the corresponding period in 2019. This decrease was due to a 19.0% decrease in the average cost of fuel per KWH generated and a 2.6% decrease in the volume of KWHs generated.
For year-to-date 2020, fuel expense was $162 million compared to $198 million for the corresponding period in 2019. This decrease was due to a 19.5% decrease in the average cost of fuel per KWH generated, partially offset by a 1.8% increase in the volume of KWHs generated.
Purchased Power
In the secondfirst quarter 2020,2021, purchased power expense was $7$207 million compared to $6$181 million for the corresponding period in 2019. For year-to-date 2020, purchased power expense2020. The increase was $12 million comparedprimarily due to $9 million for the corresponding period in 2019. These increases were primarily the result of 36.3% and 63.2% increases in the volume of KWHs purchased in the second quarter and year-to-date 2020, respectively, largely offset by 13.5% and 20.9% decreasesa 30.8% increase in the average cost per KWH purchased primarily due to higher natural gas prices, partially offset by an 8.4% decrease in the second quarter and year-to-date 2020, respectively.volume of KWHs purchased.
Energy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.
Cost of Natural Gas
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $144 | | 32.8 |
Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities. Cost of natural gas at the natural gas distribution utilities represented 86% of total cost of natural gas for the first quarter 2021.
In the first quarter 2021, cost of natural gas was $583 million compared to $439 million for the corresponding period in 2020. The increase reflects higher volumes sold due to colder weather and higher gas cost recovery in the first quarter 2021 compared to the corresponding period in 2020. The increase also reflects a 38% increase in natural gas prices in the first quarter 2021 compared to the corresponding period in 2020.
Cost of Other Sales
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $27 | | 49.1 |
In the first quarter 2021, cost of other sales was $82 million compared to $55 million for the corresponding period in 2020. The increase primarily relates to a $14 million increase in distributed infrastructure and energy efficiency projects at PowerSecure and an increase of $8 million in unregulated power delivery construction and maintenance contracts at Georgia Power.
Other Operations and Maintenance Expenses
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $76 | | 5.9 |
In the first quarter 2021, other operations and maintenance expenses were $1.37 billion compared to $1.30 billion for the corresponding period in 2020. The increase reflects a $55 million increase in employee compensation and
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
benefit expenses, primarily at Southern Company Gas, and a $15 million decrease in nuclear property insurance refunds at Alabama Power and Georgia Power.
Depreciation and Amortization
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $14 | | 1.6 |
In the first quarter 2021, depreciation and amortization was $871 million compared to $857 million for the corresponding period in 2020. The increase primarily reflects a $37 million increase in depreciation associated with additional plant in service, partially offset by decreased amortization of regulatory assets related to CCR AROs of $22 million under the terms of Georgia Power's 2019 ARP. See Note (B) to the Condensed Financial Statements under "Georgia Power – Rate Plan" herein and Note 2 to the financial statements under "Georgia Power – Rate Plans – 2019 ARP" in Item 8 of the Form 10-K for additional information regarding Georgia Power's recovery of costs associated with CCR AROs.
Taxes Other Than Income Taxes
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $15 | | 4.5 |
In the first quarter 2021, taxes other than income taxes were $345 million compared to $330 million for the corresponding period in 2020. The increase primarily reflects increased property taxes and an increase in revenue tax expenses as a result of higher natural gas revenues at Southern Company Gas.
Estimated Loss on Plant Vogtle Units 3 and 4
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $48 | | N/M |
N/M - Not meaningful
In the first quarter 2021, an estimated probable loss of $48 million was recorded at Georgia Power to reflect its revised total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information.
(Gain) Loss on Dispositions, Net
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $5 | | 12.8 |
In the first quarter 2021, (gain) loss on dispositions, net was $44 million compared to $39 million for the corresponding period in 2020. The first quarter 2021 amount includes $39 million in gains at Southern Power, primarily from contributions of wind turbine equipment to various equity method investments, and $4 million in gains from property sales at Alabama Power. In the first quarter 2020, Southern Power recorded a $39 million gain related to the sale of Plant Mankato. See Notes (E) and (K) to the Condensed Financial Statements under "Southern Power" herein and Note 15 to the financial statements under "Southern Power – Sales of Natural Gas and Biomass Plants" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Allowance for Equity Funds Used During Construction
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $12 | | 35.3 |
In the first quarter 2021, allowance for equity funds used during construction was $46 million compared to $34 million for the corresponding period in 2020. The increase was primarily due to an increase in AFUDC equity associated with the construction of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
Other Income (Expense), Net
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $(45) | | (43.7) |
In the first quarter 2021, other income (expense), net was $58 million compared to $103 million for the corresponding period in 2020. The decrease was primarily due to $75 million in charitable contributions at Southern Company Gas in the first quarter 2021, partially offset by a $27 million increase in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.
Income Taxes
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $45 | | 31.0 |
In the first quarter 2021, income taxes were $190 million compared to $145 million for the corresponding period in 2020. The increase was primarily due to higher pre-tax earnings, partially offset by $16 million in tax benefits resulting from new legislation that changed Southern Power's state apportionment methodology. See Note (G) to the Condensed Financial Statements herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Alabama State Tax Reform Legislation" in Item 7 of the Form 10-K for additional information.
Alabama Power
Net Income
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $79 | | 28.2 |
Alabama Power's net income after dividends on preferred stock for the first quarter 2021 was $359 million compared to $280 million for the corresponding period in 2020. The increase was primarily due to an increase in retail revenues associated with an increase in Rate RSE effective in January 2021 and colder weather in Alabama Power's service territory in the first quarter 2021 compared to the corresponding period in 2020.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Retail Revenues
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $147 | | 12.2 |
In the first quarter 2021, retail revenues were $1.35 billion compared to $1.21 billion for the corresponding period in 2020.
Details of the changes in retail revenues were as follows:
| | | | | | | | | | | | | | | |
| | | First Quarter 2021 |
| | | | | (in millions) | | (% change) |
Retail – prior year | | | | | $ | 1,205 | | | |
Estimated change resulting from – | | | | | | | |
Rates and pricing | | | | | 50 | | | 4.1 | % |
Sales decline | | | | | (4) | | | (0.3) | |
Weather | | | | | 39 | | | 3.2 | |
Fuel and other cost recovery | | | | | 62 | | | 5.2 | |
Retail – current year | | | | | $ | 1,352 | | | 12.2 | % |
Revenues associated with changes in rates and pricing increased in the first quarter 2021 when compared to the corresponding period in 2020 primarily due to a Rate RSE increase effective January 1, 2021. See Note 2 to the financial statements under "Alabama Power – Rate RSE" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales decreased in the first quarter 2021 when compared to the corresponding period in 2020. Weather-adjusted residential KWH sales were relatively flat in the first quarter 2021 when compared to the corresponding period in 2020. Weather-adjusted commercial KWH sales decreased 2.1% in the first quarter 2021 when compared to the corresponding period in 2020 primarily due to changes in consumer and business behavior in response to the COVID-19 pandemic. Industrial KWH sales decreased 5.4% in the first quarter 2021 when compared to the corresponding period in 2020 primarily as a result of customer closures and maintenance outages, as well as continued consumer responses to the COVID-19 pandemic.
Fuel and other cost recovery revenues increased in the first quarter 2021 when compared to the corresponding period in 2020 primarily due to increases in generation and the average cost of fuel. Electric rates include provisions to recognize the recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
Wholesale Revenues – Non-Affiliates
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $36 | | 64.3 |
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Alabama Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not affect net income. Short-term opportunity energy sales are also included in wholesale energy sales to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin above Alabama Power's variable cost to produce the energy.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
In the first quarter 2021, wholesale revenues from sales to non-affiliates were $92 million compared to $56 million for the corresponding period in 2020. The increase consisted of a $19 million increase in energy revenues primarily due to higher natural gas prices and a $17 million increase in capacity revenues primarily related to a power sales agreement that began in September 2020.
Wholesale Revenues – Affiliates
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $13 | | 68.4 |
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.
In the first quarter 2021, wholesale revenues from sales to affiliates were $32 million compared to $19 million for the corresponding period in 2020. The increase was primarily due to a 40.5% increase in the price of energy and an 18.7% increase in KWH sales due to increased coal generation as the result of higher natural gas prices in the first quarter 2021 compared to the corresponding period in 2020.
Other Revenues
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $12 | | 16.9 |
In the first quarter 2021, other revenues were $83 million compared to $71 million for the corresponding period in 2020. The increase was primarily due to increases of $7 million in transmission and energy service revenues and $2 million in customer fees.
Fuel and Purchased Power Expenses
| | | | | | | | | | | | | | | |
| | | First Quarter 2021 vs. First Quarter 2020 |
| | | | | (change in millions) | | (% change) |
Fuel | | | | | $ | 76 | | | 35.3 | |
Purchased power – non-affiliates | | | | | 10 | | | 25.0 | |
Purchased power – affiliates | | | | | 12 | | | 66.7 | |
Total fuel and purchased power expenses | | | | | $ | 98 | | | |
In the first quarter 2021, total fuel and purchased power expenses were $371 million compared to $273 million for the corresponding period in 2020. The increase was primarily due to a $59 million increase related to the volume of KWHs generated and purchased and a $39 million increase in the average cost of fuel and purchased power.
Fuel and purchased power energy transactions do not have a significant impact on earnings, since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. See Note 2 to the financial statements under "Alabama Power – Rate ECR" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of Alabama Power's generation and purchased power were as follows:
| | | | | | | | | | | | | | | |
| | | | | First Quarter 2021 | | First Quarter 2020 |
Total generation (in billions of KWHs)(a) | | | | | 15 | | 14 |
Total purchased power (in billions of KWHs) | | | | | 1 | | 1 |
Sources of generation (percent)(a) — | | | | | | | |
Coal | | | | | 46 | | 34 |
Nuclear | | | | | 25 | | 28 |
Gas | | | | | 19 | | 20 |
Hydro | | | | | 10 | | 18 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
Coal | | | | | 2.75 | | 2.64 |
Nuclear | | | | | 0.72 | | 0.76 |
Gas(a) | | | | | 2.51 | | 2.19 |
Average cost of fuel, generated (in cents per net KWH)(a) | | | | | 2.14 | | 1.88 |
Average cost of purchased power (in cents per net KWH)(b) | | | | | 6.52 | | 4.86 |
(a)First quarter 2021 excludes Central Alabama Generating Station KWHs and associated cost of fuel as its fuel is provided by the purchaser under a power sales agreement. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
(b)Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.
Fuel
In the first quarter 2021, fuel expense was $291 million compared to $215 million for the corresponding period in 2020. The increase was primarily due to a 44.6% increase in the volume of KWHs generated by coal, a 44.0% decrease in the volume of KWHs generated by hydro, and a 14.6% increase in the average cost of KWHs generated by natural gas, which excludes tolling agreements.
Purchased Power – Non-Affiliates
In the first quarter 2021, purchased power expense from non-affiliates was $50 million compared to $40 million for the corresponding period in 2020. The increase was primarily due to a 31.1% increase in the average cost per KWH purchased as a result of higher natural gas prices and a 12.9% increase in the volume of KWHs purchased due to a PPA which began in September 2020.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to
the cost of the Southern Company system's generation, demand for energy within the Southern Company system's
electric service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the first quarter 2021, purchased power expense from affiliates was $30 million compared to $18 million for the corresponding period in 2020. The increase was primarily due to a 39.9% increase in the average cost per KWH purchased as a result of higher natural gas prices and a 17.9% increase in the volume of KWHs purchased due to colder weather in the first quarter 2021 when compared to the corresponding period in 2020.
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Operations and Maintenance Expenses
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $11 | | 3.1 |
In the first quarter 2021, other operations and maintenance expenses were $361 million compared to $350 million for the corresponding period in 2020. The increase was primarily due to an increase of $10 million related to reliability NDR credits applied in 2020 and a $6 million reduction in nuclear property insurance refunds. These increases were partially offset by a $3 million decrease in Rate CNP Compliance-related expenses. See Note 2 to the financial statements under "Alabama Power – Rate NDR" and " – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.
Depreciation and Amortization
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $11 | | 5.5 |
In the first quarter 2021, depreciation and amortization was $211 million compared to $200 million for the corresponding period in 2020. The increase was primarily due to additional plant in service, including the purchase of the Central Alabama Generating Station in August 2020. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
Other Income (Expense), Net
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $8 | | 33.3 |
In the first quarter 2021, other income (expense), net was $32 million compared to $24 million for the corresponding period in 2020. The increase was primarily due to an increase in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.
Income Taxes
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $26 | | 31.0 |
In the first quarter 2021, income taxes were $110 million compared to $84 million for the corresponding period in 2020. The increase was primarily due to higher pre-tax earnings.
Georgia Power
Net Income
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $20 | | 6.0 |
Georgia Power's net income for the first quarter 2021 was $351 million compared to $331 million for the corresponding period in 2020. The increase was primarily due to higher retail revenues associated with colder weather in the first quarter 2021 compared to the corresponding period in 2020, partially offset by a $36 million after-tax charge in the first quarter 2021 related to the construction of Plant Vogtle Units 3 and 4. See Note (B) to
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
Retail Revenues
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $112 | | 6.7 |
In the first quarter 2021, retail revenues were $1.79 billion compared to $1.68 billion for the corresponding period in 2020.
Details of the changes in retail revenues were as follows:
| | | | | | | | | | | | | | | |
| | | First Quarter 2021 |
| | | | | (in millions) | | (% change) |
Retail – prior year | | | | | $ | 1,675 | | | |
Estimated change resulting from – | | | | | | | |
Rates and pricing | | | | | (18) | | | (1.1) | % |
Sales decline | | | | | (6) | | | (0.4) | |
Weather | | | | | 42 | | | 2.5 | |
Fuel cost recovery | | | | | 94 | | | 5.7 | |
Retail – current year | | | | | $ | 1,787 | | | 6.7 | % |
Revenues associated with changes in rates and pricing decreased in the first quarter 2021 when compared to the corresponding period in 2020. The decrease was primarily due to a decrease in the NCCR tariff effective January 1, 2021. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction – Regulatory Matters" herein for additional information.
Revenues attributable to changes in sales decreased in the first quarter 2021 when compared to the corresponding period in 2020 primarily due to continued impacts of the COVID-19 pandemic, partially offset by customer growth. Weather-adjusted residential KWH sales increased 2.0% in the first quarter 2021 when compared to corresponding period in 2020 primarily due to customer growth. Weather-adjusted commercial KWH sales decreased 3.3% in the first quarter 2021 when compared to the corresponding period in 2020 primarily due to lower customer usage resulting from changes in consumer and business behavior in response to the COVID-19 pandemic, partially offset by customer growth. Weather-adjusted industrial KWH sales increased 1.1% in the first quarter 2021 when compared to the corresponding period in 2020 primarily as a result of increases in the pipeline and lumber segments, partially offset by reductions in the textiles, transportation, and chemicals segments as a result of disruptions in supply chain and business operations related to the COVID-19 pandemic.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased in the first quarter 2021 when compared to the corresponding period in 2020 due to higher fuel and purchased power costs. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See Note 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Wholesale Revenues
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $17 | | 65.4 |
Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. Wholesale capacity revenues from PPAs are recognized in amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy.
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.
In the first quarter 2021, wholesale revenues were $43 million compared to $26 million for the corresponding period in 2020. The increase was primarily due to higher natural gas prices.
Other Revenues
| | | | | | | | |
First Quarter 2021 vs. First Quarter 2020 |
(change in millions) | | (% change) |
$16 | | 12.9 |
In the first quarter 2021, other revenues were $140 million compared to $124 million for the corresponding period in 2020. The increase was primarily due to an increase of $13 million in unregulated sales associated with power delivery construction and maintenance contracts and outdoor lighting.
Fuel and Purchased Power Expenses
| | | | | | | | | | | | | | | |
| | | First Quarter 2021 vs. First Quarter 2020 |
| | | | | (change in millions) | | (% change) |
Fuel | | | | | $ | 82 | | | 35.5 | |
Purchased power – non-affiliates | | | | | 15 | | | 11.6 | |
Purchased power – affiliates | | | | | 7 | | | 5.4 | |
Total fuel and purchased power expenses | | | | | $ | 104 | | | |
In the first quarter 2021, total fuel and purchased power expenses were $593 million compared to $489 million for the corresponding period in 2020. The increase was due to a $77 million increase related to the average cost of fuel and purchased power and a $27 million net increase related to the volume of KWHs generated and purchased.
Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues through Georgia Power's fuel cost recovery mechanism. See Note 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of Georgia Power's generation and purchased power were as follows:
| | | | | | | | | | | | | | | |
| | | | | First Quarter 2021 | | First Quarter 2020 |
Total generation (in billions of KWHs) | | | | | 14 | | 13 |
Total purchased power (in billions of KWHs) | | | | | 7 | | 9 |
Sources of generation (percent) — | | | | | | | |
Gas | | | | | 47 | | 58 |
Nuclear | | | | | 27 | | 27 |
Coal | | | | | 22 | | 8 |
Hydro and other | | | | | 4 | | 7 |
Cost of fuel, generated (in cents per net KWH) — | | | | | | | |
Gas | | | | | 2.58 | | 2.12 |
Nuclear | | | | | 0.78 | | 0.80 |
Coal | | | | | 2.91 | | 3.83 |
Average cost of fuel, generated (in cents per net KWH) | | | | | 2.15 | | 1.87 |
Average cost of purchased power (in cents per net KWH)(*) | | | | | 4.22 | | 3.17 |
(*)Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.
Fuel
In the first quarter 2021, fuel expense was $313 million compared to $231 million for the corresponding period in 2020. The increase was primarily due to an increase of 232.9% in the volume of KWHs generated by coal and an increase of 21.7% in the average cost of natural gas per KWH generated.
Purchased Power – Non-Affiliates
In the first quarter 2021, purchased power expense from non-affiliates was $144 million compared to $129 million in the corresponding period in 2020. The increase was primarily due to a 24.1% increase in the average cost per KWH purchased primarily due to higher natural gas prices, partially offset by a 9.8% decrease in the volume of KWHs purchased as Georgia Power units generally dispatched at a lower cost than available market resources.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(5) | | (6.9) | | $9 | | 6.8 |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $9 | | 1.9 |
In the secondfirst quarter 2020,2021, other operations and maintenance expenses were $67$474 million compared to $72$465 million for the corresponding period in 2019. The decrease was primarily due to a decrease of $5 million in scheduled generation outage costs.
For year-to-date 2020, other operations and maintenance expenses were $142 million compared to $133 million for the corresponding period in 2019.2020. The increase was primarily due to increasesa $9 million decrease in nuclear property insurance refunds and an increase in expenses of $5$8 million related to unregulated power delivery construction and maintenance contracts, partially offset by a decrease of $9 million in schedulednon-outage generation outagemaintenance costs $3 million in vegetation management expenses,primarily associated with coal generation and $2 million in certain employee compensation expenses previously deferred in 2019.the timing of maintenance activities.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Depreciation and Amortization
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(2) | | (4.2) | | $(7) | | (7.4) |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $(14) | | (4.0) |
In the secondfirst quarter 2020,2021, depreciation and amortization was $46$338 million compared to $48$352 million for the corresponding period in 2019. For year-to-date 2020,2020. The decrease primarily reflects decreased amortization of regulatory assets related to CCR AROs of $22 million under the terms of the 2019 ARP, partially offset by a $10 million increase in depreciation associated with additional plant in service. See Note (B) to the Condensed Financial Statements under "Georgia Power – Rate Plan" herein and amortizationNote 2 to the financial statements under "Georgia Power – Rate Plans – 2019 ARP" in Item 8 of the Form 10-K for additional information regarding recovery of costs associated with CCR AROs.
Estimated Loss on Plant Vogtle Units 3 and 4
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $48 | | N/M |
N/M - Not meaningful
In the first quarter 2021, an estimated probable loss of $48 million was $88recorded to reflect Georgia Power's revised total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information.
Other Income (Expense), Net
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $20 | | 38.5 |
In the first quarter 2021, other income (expense), net was $72 million compared to $95$52 million for the corresponding period in 2019. These decreases2020. The increase was primarily due to an increase of $12 million in non-service cost-related retirement benefits income and an increase of $7 million in AFUDC equity associated with the construction of Plant Vogtle Units 3 and 4. See Note (H) to the Condensed Financial Statements herein for additional information on retirement benefits and Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
Mississippi Power
Net Income
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $13 | | 40.6 |
In the first quarter 2021, net income was $45 million compared to $32 million for the corresponding period in 2020. The increase was primarily due to an increase in base revenues primarily due to colder weather in the first quarter 2021 compared to the corresponding period in 2020, partially offset by decreased customer usage as a result of the COVID-19 pandemic, and a decrease in operations and maintenance expenses, partially offset by an increase in depreciation and amortization.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Retail Revenues
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $5 | | 2.5 |
In the first quarter 2021, retail revenues were related$204 million compared to $199 million for the corresponding period in 2020.
Details of the changes in retail revenues were as follows:
| | | | | | | | | | | | | | | |
| | | First Quarter 2021 |
| | | | | (in millions) | | (% change) |
Retail – prior year | | | | | $ | 199 | | | |
Estimated change resulting from – | | | | | | | |
Rates and pricing | | | | | (7) | | | (3.5) | % |
Sales decline | | | | | (5) | | | (2.5) | |
Weather | | | | | 8 | | | 4.0 | |
Fuel and other cost recovery | | | | | 9 | | | 4.5 | |
Retail – current year | | | | | $ | 204 | | | 2.5 | % |
Revenues associated with changes in rates and pricing decreased in the first quarter 2021 when compared to the corresponding period in 2020 primarily due to decreases in amortizationbase rates that became effective in April 2020 in accordance with the Mississippi Power Rate Case Settlement Agreement. See Note 2 to the financial statements under "Mississippi Power – 2019 Base Rate Case" in Item 8 of $8 million and $14 millionthe Form 10-K for additional information.
Revenues attributable to changes in sales decreased in the secondfirst quarter 2021 when compared to the corresponding period in 2020 primarily due to continued impacts of the COVID-19 pandemic. Weather-adjusted residential KWH sales decreased 0.7% in the first quarter 2021 primarily due to decreased customer usage. Weather-adjusted commercial KWH sales decreased 4.3% in the first quarter 2021 primarily due to lower customer usage resulting from changes in consumer and year-to-datebusiness behavior in response to the COVID-19 pandemic. Industrial KWH sales decreased 10.7% in the first quarter 2021 as a result of disruptions in supply chain and business operations driven by the COVID-19 pandemic and non-pandemic related customer outages.
Fuel and other cost recovery revenues increased in the first quarter 2021 when compared to the corresponding period in 2020 respectively, primarily as a result of higher recoverable fuel costs. Recoverable fuel costs include fuel and purchased power expenses reduced by the ECO Plan regulatory assets being fully amortizedfuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in 2019,fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income.
Wholesale Revenues – Non-Affiliates
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $12 | | 23.5 |
Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. In addition, Mississippi Power provides service under long-term contracts with rural electric cooperative associations
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
and municipalities located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. See Note 2 to the financial statements under "Mississippi Power" in Item 8 of the Form 10-K for additional information.
In the first quarter 2021, wholesale revenues from sales to non-affiliates were $63 million compared to $51 million for the corresponding period in 2020. The increase was primarily due to increases in revenue from MRA customers as a result of colder weather and higher fuel costs in the first quarter 2021 compared to the corresponding period in 2020, partially offset by amortizationdecreased customer usage as a result of the COVID-19 pandemic.
Wholesale Revenues – Affiliates
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $12 | | 57.1 |
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a regulatory assetsignificant impact on earnings since this energy is generally sold at marginal cost.
In the first quarter 2021, wholesale revenues from sales to affiliates were $33 million compared to $21 million for the corresponding period in 2020. The increase was primarily associated with an ARO. These decreasesincrease in the average cost of fuel.
Fuel and Purchased Power Expenses
| | | | | | | | | | | | | | | |
| | | First Quarter 2021 vs. First Quarter 2020 |
| | | | | (change in millions) | | (% change) |
Fuel | | | | | $ | 22 | | | 27.8 |
Purchased power | | | | | — | | | — |
Total fuel and purchased power expenses | | | | | $ | 22 | | | |
In the first quarter 2021, total fuel and purchased power expenses were $106 million compared to $84 million for the corresponding period in 2020. The increase was primarily due to a higher average cost of fuel and an increase associated with the volume of KWHs generated.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause.
Details of Mississippi Power's generation and purchased power were as follows:
| | | | | | | | | | | | | | | |
| | | | | First Quarter 2021 | | First Quarter 2020 |
Total generation (in millions of KWHs) | | | | | 4,324 | | 4,167 |
Total purchased power (in millions of KWHs) | | | | | 121 | | 188 |
Sources of generation (percent) – | | | | | | | |
Coal | | | | | 9 | | 3 |
Gas | | | | | 91 | | 97 |
Cost of fuel, generated (in cents per net KWH) – | | | | | | | |
Coal | | | | | 3.17 | | 4.30 |
Gas | | | | | 2.41 | | 1.95 |
Average cost of fuel, generated (in cents per net KWH) | | | | | 2.49 | | 2.02 |
Average cost of purchased power (in cents per net KWH) | | | | | 4.08 | | 2.64 |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Fuel
In the first quarter 2021, fuel expense was $101 million compared to $79 million for the corresponding period in 2020. The increase was due to a 225.3% increase in the volume of KWHs generated by coal and a 23.6% increase in the average cost of natural gas per KWH generated, partially offset by increasesa 26.3% decrease in depreciationthe average cost of coal per KWH generated and a 3.4% decrease in the volume of KWHs generated by natural gas.
Other Operations and Maintenance Expenses
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $(8) | | (10.5) |
In the first quarter 2021, other operations and maintenance expenses were $68 million compared to $76 million for the corresponding period in 2020. The decrease was primarily due to decreases of $6 million related to planned generation outage costs and $7$4 million associated with the Kemper County energy facility primarily related to an increase in salvage proceeds and a decrease in ongoing period costs.
Depreciation and Amortization
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $5 | | 11.9 |
In the secondfirst quarter 2021, depreciation and year-to-date 2020, respectively,amortization was $47 million compared to $42 million for the corresponding period in 2020. The increase was primarily due to a $3 million increase in depreciation related to additional plant in service and an increase in depreciation rates in accordance with the Mississippi Power Rate Case Settlement Agreement and a $2 million increase due to amortization of a regulatory asset associated with an ARO in accordance with the Mississippi Power Rate Case Settlement Agreement. See Note (B) to the Condensed Financial Statements under "Mississippi Power – 2019 Base Rate Case" herein and Note 2 to the financial statements under "Mississippi Power – Environmental Compliance Overview Plan"2019 Base Rate Case" in Item 8 of the Form 10-K for additional information.
Income Taxes
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(3) | | (60.0) | | $(4) | | (33.3) |
In the second quarter 2020, income taxes were $2 million compared to $5 million for the corresponding period in 2019. For year-to-date 2020, income taxes were $8 million compared to $12 million for the corresponding period in 2019. These decreases were primarily due to a decrease of $3 million in both the second quarter and year-to-date 2020 associated with the flowback of excess deferred income taxes as a result of the Mississippi Power Rate Case Settlement Agreement. See Note (G) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Power
Net Income Attributable to Southern Power
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(111) | | (63.8) | | $(92) | | (40.0) |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $22 | | 29.3 |
Net income attributable to Southern Power forin the secondfirst quarter 20202021 was $63$97 million compared to $174$75 million for the corresponding period in 2019.2020. The decreaseincrease was primarily due to the gain on the sale of Plant Nacogdoches in the second quarter 2019 of $88a $16 million after tax. In addition, the decrease wastax benefit due to reduced net income related to the dispositions of Plant Nacogdocheschanges in 2019 and Plant Mankato in the first quarter 2020. The decrease also reflects net gains in the second quarter 2019 totaling $22 millionstate apportionment methodology resulting from the Roserock solar facility litigation settlement and sales of wind equipment.
Net income attributable to Southern Power for year-to-date 2020 was $138 million compared to $230 million for the corresponding period in 2019. The decrease was primarily due to the gain on the sale of Plant Nacogdoches in the second quarter 2019 of $88 million after tax partially offsetlegislation enacted by the gain on saleState of Plant MankatoAlabama in the first quarter 2020 of $23 million after tax. In addition, the decrease was due to reduced net income related to the dispositions of Plant Nacogdoches and Plant Mankato. The decrease also reflects net gains in the second quarter 2019 totaling $22 million from the Roserock solar facility litigation settlement and sales of wind equipment.February 2021.
See Note (K) to the Condensed Financial Statements under "Southern Power" herein and Note 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K for additional information.
Operating Revenues
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(71) | | (13.9) | | $(139) | | (14.6) |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $65 | | 17.3 |
Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas facilities, and a biomass generating facility (through the second quarter 2019 sale of Plant Nacogdoches), and PPA energy revenues from Southern Power's generation facilities. To the extent Southern Power has capacity not contracted under a PPA, it may sell power into an accessible wholesale market, or, to the extent those generation assets are part of the FERC-approved IIC, it may sell power into the Southern Company power pool.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Natural Gas and Biomass Capacity and Energy Revenue
Capacity revenues generally represent the greatest contribution to operating income and are designed to provide recovery of fixed costs plus a return on investment.
Energy is generally sold at variable cost or is indexed to published natural gas indices. Energy revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.
Solar and Wind Energy Revenue
Southern Power's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have capacity revenue. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy generated from the respective facility and sold to
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors.
See FUTURE EARNINGS POTENTIAL – "Southern"Southern Power's Power Sales Agreements" hereinAgreements" in Item 7 of the Form 10-K for additional information regarding Southern Power's PPAs.
Operating Revenues Details
Details of Southern Power's operating revenues were as follows:
| | | Second Quarter 2020 | | Second Quarter 2019 | | Year-to-Date 2020 | | Year-to-Date 2019 | | | First Quarter 2021 | | First Quarter 2020 |
| (in millions) | | | (in millions) |
PPA capacity revenues | $ | 92 |
| | $ | 125 |
| | $ | 181 |
| | $ | 252 |
| PPA capacity revenues | | $ | 96 | | | $ | 90 | |
PPA energy revenues | 270 |
| | 291 |
| | 475 |
| | 518 |
| PPA energy revenues | | 245 | | | 205 | |
Total PPA revenues | 362 |
| | 416 |
| | 656 |
| | 770 |
| Total PPA revenues | | 341 | | | 295 | |
Non-PPA revenues | 73 |
| | 91 |
| | 151 |
| | 177 |
| Non-PPA revenues | | 95 | | | 77 | |
Other revenues | 4 |
| | 3 |
| | 7 |
| | 6 |
| Other revenues | | 4 | | | 3 | |
Total operating revenues | $ | 439 |
| | $ | 510 |
| | $ | 814 |
| | $ | 953 |
| Total operating revenues | | $ | 440 | | | $ | 375 | |
In the secondfirst quarter 2020,2021, total operating revenues were $439$440 million, reflecting a $71$65 million, or 14%17%, decreaseincrease from the corresponding period in 2019.2020. The decreaseincrease in operating revenues was primarily due to the following:
•PPA capacity revenues decreased $33increased $6 million, or 26%7%, primarily due to decreasesnew natural gas PPAs and increased capacity on existing contracts, partially offset by the disposition of $22 million related to the dispositions of Plant Nacogdoches in the second quarter 2019 and Plant Mankato in the first quarter 2020 and $10 million from the contractual expiration of an affiliatea natural gas PPA.PPA in November 2020.
•PPA energy revenues decreased $21increased $40 million, or 7%20%, primarily due to a $46$35 million decreaseincrease in sales from natural gas facilities resulting from a $25$42 million increase in the price of fuel and purchased power, partially offset by a $7 million decrease in the volume of KWHs sold due to reduced demand and a $21sold. In addition, the increase reflects $6 million decrease in the average cost of fuel and purchased power. This decrease was partially offset by a $13 million increase in sales primarily driven by the volume of KWHs generated by solar and wind facilities and a $12 million increase in sales from a fuel cell project acquirednew wind facilities placed in late 2019.service subsequent to the first quarter 2020.
•Non-PPA revenues decreasedincreased $18 million, or 20%23%, due to a $40$38 million decreaseincrease in the market price of energy, partially offset by a $23$20 million increasedecrease in the volume of KWHs sold through short-term sales.
For year-to-date 2020, total operating revenues were $814 million, reflecting a $139 million, or 15%, decrease from the corresponding period in 2019. The decrease in operating revenues was primarily due to the following:PPA capacity revenues decreased $71 million, or 28%, primarily due to decreases of $45 million related to the dispositions of Plant Nacogdoches in the second quarter 2019 and Plant Mankato in the first quarter 2020 and $24 million from the contractual expiration of an affiliate natural gas PPA.
PPA energy revenues decreased $43 million, or 8%, due to an $86 million decrease in sales from natural gas facilities resulting from a $49 million decrease in the price of fuel and purchased power and a $37 million decrease in the volume of KWHs sold due to reduced demand. This decrease was partially offset by increases of $23 million in sales primarily driven by the volume of KWHs generated by solar and wind facilities and $20 million in sales from a fuel cell project acquired in late 2019.
Non-PPA revenues decreased $26 million, or 15%, due to a $74 million decrease in the market price of energy, partially offset by a $48 million increase in the volume of KWHs sold through short-term sales.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Fuel and Purchased Power Expenses
Details of Southern Power's generation and purchased power were as follows:
| | | Second Quarter 2020 | Second Quarter 2019 | | Year-to-Date 2020 | Year-to-Date 2019 | | | First Quarter 2021 | First Quarter 2020 |
| (in billions of KWHs) | | | (in billions of KWHs) |
Generation | 11.3 | 11.7 | | 22.0 | 21.9 | Generation | | 9.4 | 10.7 |
Purchased power | 0.9 | 1.0 | | 1.5 | 1.8 | Purchased power | | 0.6 | 0.7 |
Total generation and purchased power | 12.2 | 12.7 | | 23.5 | 23.7 | Total generation and purchased power | | 10 | 11.4 |
| | | | |
Total generation and purchased power, excluding solar, wind, and tolling agreements | 7.4 | 7.1 | | 14.5 | 13.7 | Total generation and purchased power, excluding solar, wind, and tolling agreements | | 6.1 | 7.2 |
Southern Power's PPAs for natural gas generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the Southern Company power pool for capacity owned directly by Southern Power.
Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the Southern Company power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.
Details of Southern Power's fuel and purchased power expenses were as follows:
| | | Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 | | | First Quarter 2021 vs. First Quarter 2020 |
| (change in millions) | | (% change) | | (change in millions) | | (% change) | | | (change in millions) | | (% change) |
Fuel | $ | (37 | ) | | (26.6) | | $ | (75 | ) | | (26.4) | Fuel | | $ | 34 | | | 31.8 |
Purchased power | (14 | ) | | (43.8) | | (23 | ) | | (41.8) | Purchased power | | 6 | | | 42.9 |
Total fuel and purchased power expenses | $ | (51 | ) | | $ | (98 | ) | | Total fuel and purchased power expenses | | $ | 40 | | |
In the secondfirst quarter 2020,2021, total fuel and purchased power expenses decreased $51increased $40 million, or 30%33%, compared to the corresponding period in 2019.2020. Fuel expense decreased $37increased $34 million due to a $46$50 million decreaseincrease in the average cost of fuel per KWH generated, partially offset by a $9$16 million increasedecrease associated with the volume of KWHs generated. Purchased power expense decreased $14increased $6 million due to a $9an $8 million decreaseincrease associated with the average cost of purchased power, andpartially offset by a $5$2 million decrease associated with the volume of KWHs purchased.
For year-to-date 2020, total fuel
Other Operations and purchased powerMaintenance Expenses
| | | | | | | | |
First Quarter 2021 vs. First Quarter 2020 |
(change in millions) | | (% change) |
$22 | | 27.8 |
In the first quarter 2021, other operations and maintenance expenses decreased $98were $101 million or 29%, compared to $79 million for the corresponding period in 2019. Fuel expense decreased $75 million2020. The increase was primarily due to a $98 million decrease in the average cost of fuel per KWH generated, partially offset by a $23an $8 million increase in scheduled outage and maintenance expenses, $6 million in expenses related to the allocation of uncollected settlements by the Energy Reliability Council of Texas market as a result of Winter Storm Uri, and $2 million in expenses associated with new wind facilities placed in service subsequent to the volume of KWHs generated. Purchased power expense decreased $23 million due to a $16 million decrease associated with the average cost of purchased power and a $7 million decrease associated with the volume of KWHs purchased.first quarter 2020.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
(Gain) Loss on Dispositions, Net
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $— | | — |
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$23 | | N/M | | $(16) | | N/M |
N/M - Not meaningful
In the secondfirst quarter 2021, gains on dispositions totaled $39 million primarily from contributions of wind turbine equipment to various equity method investments. A $39 million gain was also recorded in the first quarter 2020 loss on dispositions, net was immaterial compared to a gain on dispositions, net of $23 million for the corresponding period in 2019. For year-to-date 2020, gain on dispositions, net was $39 million compared to $23 million for the corresponding period in 2019. The changes were duerelated to the sale of Plant Mankato in the first quarter 2020, which resulted in a $39 million gain,Mankato. See Notes (E) and the sale of Plant Nacogdoches in the second quarter 2019, which resulted in a $23 million gain. See Note (K) to the Condensed Financial Statements under "Southern Power" herein and Note 15 to the financial statements under "Southern Power – Sales of Natural Gas and Biomass Plants" in Item 8 of the Form 10-K under "Southern Power – Sales of Natural Gas and Biomass Plants" for additional information.
Other Income (Expense), NetTaxes (Benefit) |
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(39) | | (97.5) | | $(37) | | (90.2) |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $(17) | | (242.9) |
In the secondfirst quarter 2020, other2021, income (expense), nettax benefit was $1$10 million compared to $40income tax expense of $7 million for the corresponding period in 2019. For year-to-date 2020, other income (expense), net2020. The change was $4 million compared to $41 million for the corresponding period in 2019. The decreases were primarily due to a $36 million gain arisingchanges in state apportionment methodology resulting from tax legislation enacted by the State of Alabama in February 2021, as well as the tax impact from the Roserock solar facility litigation settlementsale of Plant Mankato in the second quarter 2019.January 2020. See Note 3(G) to the Condensed Financial Statements herein, MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Alabama State Tax Reform Legislation" in Item 7 of the Form 10-K, and Note 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K under "General Litigation Matters – Southern Power" for additional information.
Income Taxes (Benefit)
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$57 | | 111.8 | | $73 | | 121.7 |
In the second quarter 2020, income tax expense was $6 million compared to a $51 million benefit for the corresponding period in 2019. For year-to-date 2020, income tax expense was $13 million compared to a $60 million benefit for the corresponding period in 2019. The changes were primarily due to a $75 million income tax benefit in 2019 resulting from ITCs recognized upon the sale of Plant Nacogdoches, partially offset by a decrease in income tax expense as a result of lower pre-tax earnings. See Notes (G) and (K) to the Condensed Financial Statements herein for additional information.
Net Income (Loss) Attributable to Noncontrolling Interests
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(24) | | N/M | | $(26) | | N/M |
In the second quarter 2020, net income attributable to noncontrolling interests was $5 million compared to $29 million for the corresponding period in 2019. For year-to-date 2020, net loss attributable to noncontrolling interests was $26 million compared to an immaterial amount for the corresponding period in 2019. The changes were primarily due to an allocation of approximately $26 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement in the second quarter 2019. See Note 3 to the financial statements in Item 8 of the Form 10-K under "General Litigation Matters – Southern Power" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Company Gas
Operating Metrics
Southern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold.
Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution system. Southern Company Gas has various regulatory mechanisms, such as weather and revenue normalization and straight-fixed-variable rate design, which limit its exposure to weather changes within typical ranges in each of its utility's respective service territory, including Nicor Gas following the approval of a revenue decoupling mechanism for residential customers in its base rate case that concluded in 2019.territory. Southern Company Gas also utilizes weather hedges to limit the negative income impacts in the event of warmer-than-normal weather.
The number of customers served by gas distribution operations and gas marketing services can be impacted by natural gas prices, economic conditions, and competition from alternative fuels. Gas distribution operations and gas marketing services' customers are primarily located in Georgia Illinois, and Ohio.Illinois.
Southern Company Gas' natural gas volume metrics for gas distribution operations and gas marketing services illustrate the effects of weather and customer demand for natural gas. Wholesale gas services' physical sales volumes represent the daily average natural gas volumes sold to its customers.
Seasonality of Results
During the Heating Season, natural gas usage and operating revenues are generally higher as more customers are connected to the gas distribution systems and natural gas usage is higher in periods of colder weather. Occasionally in the summer, wholesale gas services' operating revenues are impacted due to peak usage by power generators in response to summer energy demands. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively evenly throughout the year.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. However, these items are comparable when reviewing Southern Company Gas' annual results. Thus, Southern Company Gas' operating results for the interim periods presented are not necessarily indicative of annual results and can vary significantly from quarter to quarter.
Net Income
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(35) | | (33.0) | | $(30) | | (8.0) |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $123 | | 44.7 |
In the secondfirst quarter 2020,2021, net income was $71$398 million compared to $106$275 million for the corresponding period in 2019. This decrease2020. The increase was primarily due to a $46$103 million decreaseincrease at wholesale gas services primarily due to reduced natural gas price volatility compared to the prior yearhigher commercial activities as a result of Winter Storm Uri and a $7 million gain from the sale of Triton in 2019, partially offset by a $16$19 million increase at gas distribution operations primarily due to base rate increases for Nicor Gas and Atlanta Gas Light and continued investment in infrastructure replacement programs, partially offset by reduced flowback of excess deferred income taxes at Atlanta Gas Light in 2020.
For year-to-date 2020, net income was $346 million compared to $376 million for the corresponding period in 2019. This decrease in net income was primarily due to a $70 million decrease at wholesale gas services primarily due to reduced natural gas price volatility compared to the prior year and a $7 million gain from the sale of Triton in 2019, partially offset by a $47 million increase at gas distribution operations primarily due to base rate increases for Nicor Gas and Atlanta Gas Light and continued investment in infrastructure replacement programs, partially offset by reduced flowback of excess deferred income taxes at Atlanta Gas Light in 2020.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
replacement. See Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
Natural Gas Revenues, including Alternative Revenue Programs
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(53) | | (7.7) | | $(278) | | (12.9) |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $445 | | 35.6 |
In the secondfirst quarter 2020,2021, natural gas revenues, including alternative revenue programs, were $636 million compared to $689 million for the corresponding period in 2019. For year-to-date 2020, natural gas revenues, including alternative revenue programs, were $1.9$1.7 billion compared to $2.2$1.2 billion for the corresponding period in 2019.2020.
Details of the changes in natural gas revenues, including alternative revenue programs, were as follows:
| | | Second Quarter 2020 | | Year-to-Date 2020 | | | First Quarter 2021 |
| (in millions) | | (% change) | | (in millions) | | (% change) | | | (in millions) | | (% change) |
Natural gas revenues – prior year | $ | 689 |
|
|
|
| $ | 2,163 |
|
|
|
| Natural gas revenues – prior year | | $ | 1,249 | | |
Estimated change resulting from – | | | | | | | | Estimated change resulting from – | | |
Infrastructure replacement programs and base rate changes | 43 |
|
| 6.2 | % |
| 119 |
|
| 5.5 | % | Infrastructure replacement programs and base rate changes | | 38 | | | 3.0 | % |
Gas costs and other cost recovery | (38 | ) |
| (5.5 | ) |
| (287 | ) |
| (13.3 | ) | Gas costs and other cost recovery | | 152 | | | 12.2 | |
Weather | 3 |
|
| 0.4 |
|
| (8 | ) |
| (0.4 | ) | |
| Wholesale gas services | (67 | ) |
| (9.7 | ) |
| (102 | ) |
| (4.7 | ) | Wholesale gas services | | 247 | | | 19.8 | |
| Other | 6 |
|
| 0.9 |
|
| — |
|
| — |
| Other | | 8 | | | 0.6 | |
Natural gas revenues – current year | $ | 636 |
| | (7.7 | )% | | $ | 1,885 |
| | (12.9 | )% | Natural gas revenues – current year | | $ | 1,694 | | | 35.6 | % |
Revenues from infrastructure replacement programs and base rate changes increased in the secondfirst quarter and year-to-date 20202021 compared to the corresponding periodsperiod in 20192020 primarily due to base rate increases at Nicor Gas and Atlanta Gas Light, Virginia Natural Gas, and Chattanooga Gas and continued investments recovered throughinvestment in infrastructure replacement programs.replacement. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K for additional information.
Revenues associated with gas costs and other cost recovery decreasedincreased in the secondfirst quarter and year-to-date 20202021 compared to the corresponding periodsperiod in 20192020 primarily due to lower naturalhigher volumes sold and higher gas prices and decreased volumes of natural gas sold. Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations.recovery. See "Cost"Cost of Natural Gas"Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.
Revenues from wholesale gas services decreasedincreased in the secondfirst quarter and year-to-date 20202021 compared to the corresponding periodsperiod in 2019 primarily2020 due to decreasedhigher commercial activityactivities as a result of warmer weather and a decrease inWinter Storm Uri, partially offset by derivative gains.losses. See "Segment"Segment Information – Wholesale Gas Services"Services" herein for additional information. Also see Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for information regarding the sale of Sequent, which is expected to be completed during the third quarter 2021.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Company Gas' natural gas distribution utilities have various regulatory mechanisms that limit their exposure to weather changes. Southern Company Gas hedged the majority of itsalso uses hedges for any remaining exposure to warmer-than-normal weather in Illinois for gas distribution operations and in Illinois and Georgia for gas marketing services. During Heating Season, natural gas usage and operating revenues are generally higher. Weatherservices; therefore, weather typically does not have a significant net income impact other than during the Heating Season.impact. The following table presents Heating Degree Days information for Illinois and Georgia, the primary locations where Southern Company Gas' operations are impacted by weather.
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| First Quarter | | 2021 vs. normal | 2021 vs. 2020 | | | | | |
| Normal(*) | 2021 | 2020 | | colder (warmer) | colder (warmer) | | | | | | | |
| (in thousands) | | | | | | | | |
Illinois | 3,024 | | 2,947 | | 2,759 | | | (2.5) | % | 6.8 | % | | | | | | | |
Georgia | 1,326 | | 1,254 | | 1,091 | | | (5.4) | % | 14.9 | % | | | | | | | |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Second Quarter | | 2020 vs. normal | 2020 vs. 2019 | | Year-to-Date | | 2020 vs. normal | 2020 vs. 2019 |
| Normal(a) | 2020 | 2019 | | colder | colder | | Normal(a) | 2020 | 2019 | | (warmer) | (warmer) |
| (in thousands) | | | | | (in thousands) | | | |
Illinois(b) | 631 |
| 736 |
| 659 |
| | 16.6 | % | 11.7 | % | | 3,684 |
| 3,495 |
| 3,956 |
| | (5.1 | )% | (11.7 | )% |
Georgia | 114 |
| 188 |
| 86 |
| | 64.9 | % | 118.6 | % | | 1,529 |
| 1,279 |
| 1,298 |
| | (16.4 | )% | (1.5 | )% |
| |
(a) | Normal represents the 10-year average from January 1, 2010 through June 30, 2019 for Illinois at Chicago Midway International Airport and for Georgia at Atlanta Hartsfield-Jackson International Airport, based on information obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center. |
| |
(b) | Heating Degree Days in Illinois are expected to have a limited financial impact beginning in 2020. In October 2019, Nicor Gas received approval for a volume balancing adjustment, a revenue decoupling mechanism for residential customers that provides a monthly benchmark level of revenue per rate class for recovery. |
The following table provides the number of customers served by Southern Company Gas at June 30, 2020March 31, 2021 and 2019:2020:
| | | | | | | | | | | | | | | | | |
| March 31, | | |
| 2021 | | 2020 | | 2021 vs. 2020 |
| (in thousands, except market share %) | | (% change) |
Gas distribution operations | 4,335 | | | 4,298 | | | 0.9 | % |
Gas marketing services | | | | | |
Energy customers(*) | 667 | | | 638 | | | 4.5 | % |
Market share of energy customers in Georgia | 28.9 | % | | 28.8 | % | | 0.3 | % |
| | | | | |
| | | | | |
|
| | | | | | | | |
| June 30, | | |
| 2020 | | 2019 | | 2020 vs. 2019 |
| (in thousands, except market share %) | | (% change) |
Gas distribution operations | 4,275 |
| | 4,231 |
| | 1.0 | % |
Gas marketing services | | | | | |
Energy customers(*) | 671 |
| | 622 |
| | 7.9 | % |
Market share of energy customers in Georgia | 29.0 | % | | 28.8 | % | |
|
|
(*)Gas marketing services' customers are primarily located in Georgia and Illinois. March 31, 2021 also includes approximately 50,000 customers in Ohio contracted through an annual auction process to serve for 12 months beginning April 1, 2020. | |
(*) | Gas marketing services' customers are primarily located in Georgia, Ohio, and Illinois. Also included as of June 30, 2020 were approximately 50,000 customers in Ohio contracted through an annual auction process to serve for 12 months beginning April 1, 2020. |
Southern Company Gas anticipates overallcontinued customer growth trends in gas distribution operations to continue as it expects continued low natural gas prices. Southern Company Gas uses a variety of targeted marketing programs to attract new customers and to retain existing customers.
Cost of Natural Gas
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $144 | | 32.8 |
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(47) | | (24.6) | | $(294) | | (33.5) |
Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. Cost of natural gas at gas distribution operations represented 86% of total cost of natural gas for both the secondfirst quarter and year-to-date 2020.2021. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Southern Company Gas – Cost of Natural Gas" in Item 7 of the Form 10-K and "Natural"Natural Gas Revenues, including Alternative Revenue Programs"Programs" herein for additional information.
In the secondfirst quarter 2020, cost of natural gas was $144 million compared to $191 million for the corresponding period in 2019. This decrease reflects a 34.9% decrease in natural gas prices in the second quarter 2020 compared to the corresponding period in 2019.
For year-to-date 2020,2021, cost of natural gas was $583 million compared to $877$439 million for the corresponding period in 2019. This decrease2020. The increase reflects a 36.6% decreasehigher volumes sold due to colder weather and higher gas cost recovery in natural gas prices compared to 2019 and decreased volumes primarily as a result of warmer weather for year-to-date 2020the first quarter 2021 compared to the corresponding period in 2019.2020. The increase also reflects a 38% increase in natural gas prices in the first quarter 2021 compared to the corresponding period in 2020.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
The following table details the volumes of natural gas sold duringduring all periods presented.
| | | Second Quarter | 2020 vs. 2019 | | Year-to-Date | 2020 vs. 2019 | | First Quarter | 2021 vs. 2020 | |
| 2020 | 2019 | | 2020 | 2019 | | 2021 | 2020 | |
Gas distribution operations (mmBtu in millions) | Gas distribution operations (mmBtu in millions) | | | | Gas distribution operations (mmBtu in millions) | | |
Firm | 100 |
| 99 |
| 1.0 | % | | 357 |
| 396 |
| (9.8 | )% | Firm | 288 | | 258 | | 11.6 | % | |
Interruptible | 21 |
| 22 |
| (4.5 | ) | | 45 |
| 46 |
| (2.2 | ) | Interruptible | 26 | | 24 | | 8.3 | | |
Total | 121 |
| 121 |
| — | % | | 402 |
| 442 |
| (9.0 | )% | Total | 314 | | 282 | | 11.3 | % | |
Wholesale gas services (mmBtu in millions/day) | Wholesale gas services (mmBtu in millions/day) | | | | Wholesale gas services (mmBtu in millions/day) | | |
Daily physical sales | 6.4 |
| 5.7 |
| 12.3 | % | | 6.6 |
| 6.3 |
| 4.8 | % | Daily physical sales | 7.1 | | 6.9 | | 2.9 | % | |
Gas marketing services (mmBtu in millions) | Gas marketing services (mmBtu in millions) | |
| | |
| Gas marketing services (mmBtu in millions) | | |
Firm: | |
|
| | |
|
| Firm: | | |
Georgia | 4 |
| 4 |
| — | % | | 18 |
| 19 |
| (5.3 | )% | Georgia | 19 | | 14 | | 35.7 | % | |
Illinois | 1 |
| 2 |
| (50.0 | ) | | 6 |
| 8 |
| (25.0 | ) | Illinois | 4 | | 5 | | (20.0) | | |
| Other | 3 |
| 2 |
| 50.0 |
| | 7 |
| 10 |
| (30.0 | ) | Other | 6 | | 5 | | 20.0 | | |
Interruptible large commercial and industrial | 3 |
| 3 |
| — |
| | 7 |
| 7 |
| — |
| Interruptible large commercial and industrial | 4 | | 4 | | — | | |
Total | 11 |
| 11 |
| — | % | | 38 |
| 44 |
| (13.6 | )% | Total | 33 | | 28 | | 17.9 | % | |
Other Operations and Maintenance Expenses
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$21 | | 10.6 | | $46 | | 10.6 |
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $41 | | 15.9 |
In the secondfirst quarter 2020,2021, other operations and maintenance expenses were $220$299 million compared to $199$258 million for the corresponding period in 2019. For year-to-date 2020, other operations2020. The increase was primarily due to higher compensation expense at wholesale gas services.
Depreciation and maintenance expenses were $479Amortization
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $10 | | 8.3 |
In the first quarter 2021, depreciation and amortization was $130 million compared to $433$120 million for the corresponding period in 2019. These increases were2020. The increase was primarily due to increases in compensation and benefit expenses and expenses passed through directly to customers primarily related to bad debt and pipeline compliance and maintenance activities. See Note (H) tocontinued infrastructure investments at the Condensed Financial Statements herein for additional information.natural gas distribution utilities.
Taxes Other Than Income Taxes
| | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $9 | | 12.5 |
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$1 | | 2.2 | | $(10) | | (7.8) |
For year-to-date 2020,In the first quarter 2021, taxes other than income taxes were $118$81 million compared to $128$72 million for the corresponding period in 2019.2020. The decreaseincrease primarily relates to a decreasereflects an increase in revenue tax expenses as a result of lowerhigher natural gas revenues at Nicor Gas. These revenue tax expenses are passed through directly to customers and have no impact on net income.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Other Income (Expense), Net
Earnings from Equity Method Investments | | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $(72) | | (800.0) |
In the first quarter 2021, other income (expense), net was $63 million of expense compared to $9 million of income for the corresponding period in 2020. The increase in other expense was primarily due to $75 million in charitable contributions in the first quarter 2021. |
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$(1) | | (3.2) | | $(8) | | (10.0) |
Income TaxesFor year-to-date 2020, earnings from equity method investments | | | | | | | | | | | | |
| | First Quarter 2021 vs. First Quarter 2020 |
| | | | (change in millions) | | (% change) |
| | | | $42 | | 53.2 |
In the first quarter 2021, income taxes were $72$121 million compared to $80$79 million for the corresponding period in 2019.2020. The decrease primarily relates to lower income at SNG, the sale of Atlantic Coast Pipeline in the first quarter 2020, and the sale of Triton in the second quarter 2019. See Note (E) to the Condensed Financial Statements herein for additional information.
Other Income (Expense), Net
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$6 | | 100.0 | | $11 | | 110.0 |
In the second quarter 2020, other income (expense), netincrease was $12 million compared to $6 million for the corresponding period in 2019. For year-to-date 2020, other income (expense), net was $21 million compared to $10 million for the corresponding period in 2019. These increases were primarily due to increases in non-service cost-related retirement benefits income. See Note (H) to the Condensed Financial Statements herein for additional information.
Income Taxes
|
| | | | | | |
Second Quarter 2020 vs. Second Quarter 2019 | | Year-to-Date 2020 vs. Year-to-Date 2019 |
(change in millions) | | (% change) | | (change in millions) | | (% change) |
$10 | | 166.7 | | $12 | | 14.5 |
In the second quarter 2020, income taxes were $16 million compared to $6 million for the corresponding period in 2019. For year-to-date 2020, income taxes were $95 million compared to $83 million for the corresponding period in 2019. These increases were primarily due to a decrease in the flowback of excess deferred income taxeshigher pre-tax earnings at Atlanta Gas Light as authorized by the Georgia PSCwholesale gas services and the reversal of a federal income tax valuation allowance in connection with the sale of Triton in 2019, partially offset by lower pre-tax earnings. See Note (G) to the Condensed Financial Statements herein for additional information.gas distribution operations.
Performance and Non-GAAP Measures
Adjusted operating margin is a non-GAAP measure that is calculated as operating revenues less cost of natural gas, cost of other sales, and revenue tax expense. Adjusted operating margin excludes other operations and maintenance expenses, depreciation and amortization, and taxes other than income taxes, which are included in the calculation of operating income as calculated in accordance with GAAP and reflected in the statements of income. The presentation of adjusted operating margin is believed to provide useful information regarding the contribution resulting from base rate changes, infrastructure replacement programs and capital projects, and customer growth at gas distribution operations since the cost of natural gas and revenue tax expense can vary significantly and are generally billed directly to customers. Southern Company Gas further believes that utilizing adjusted operating margin at gas pipeline investments, wholesale gas services, and gas marketing services allows it to focus on a direct measure of performance before overhead costs. The applicable reconciliation of operating income to adjusted operating margin is provided herein.
Adjusted operating margin should not be considered an alternative to, or a more meaningful indicator of, Southern Company Gas' operating performance than operating income as determined in accordance with GAAP. In addition, Southern Company Gas' adjusted operating margin may not be comparable to similarly titled measures of other companies.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Detailed variance explanations of Southern Company Gas' financial performance are provided herein.
Reconciliations of operating income to adjusted operating margin are as follows:
| | | | | | | | | | | |
| | | | First Quarter 2021 | First Quarter 2020 |
| | | | (in millions) |
Operating Income | | | | $ | 601 | | $ | 360 | |
Other operating expenses(a) | | | | 510 | | 450 | |
Revenue taxes(b) | | | | (53) | | (45) | |
Adjusted Operating Margin | | | | $ | 1,058 | | $ | 765 | |
(a)Includes other operations and maintenance, depreciation and amortization, and taxes other than income taxes.
(b)Nicor Gas' revenue tax expenses, which are passed through directly to customers.
|
| | | | | | | | | | | | | |
| Second Quarter 2020 | Second Quarter 2019 | | Year-to-Date 2020 | Year-to-Date 2019 |
| (in millions) |
Operating Income | $ | 102 |
| $ | 134 |
| | $ | 462 |
| $ | 487 |
|
Other operating expenses(a) | 390 |
| 364 |
| | 840 |
| 799 |
|
Revenue taxes(b) | (22 | ) | (22 | ) | | (67 | ) | (76 | ) |
Adjusted Operating Margin | $ | 470 |
| $ | 476 |
| | $ | 1,235 |
| $ | 1,210 |
|
| |
(a) | Includes other operations and maintenance, depreciation and amortization, and taxes other than income taxes. |
| |
(b) | Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Segment Information
Adjusted operating margin, operating expenses, and net income for each segment are provided in the table below. See Note (L) to the Condensed Financial Statements under "Southern"Southern Company Gas"Gas" herein for additional information.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| First Quarter 2021 | | First Quarter 2020 |
| Adjusted Operating Margin(*) | | Operating Expenses(*) | | Net Income (Loss) | | Adjusted Operating Margin(*) | | Operating Expenses(*) | | Net Income (Loss) |
| (in millions) | | (in millions) |
Gas distribution operations | $ | 644 | | | $ | 357 | | | $ | 183 | | | $ | 595 | | | $ | 340 | | | $ | 164 | |
Gas pipeline investments | 8 | | | 3 | | | 29 | | | 8 | | | 3 | | | 30 | |
Wholesale gas services | 297 | | | 55 | | | 126 | | | 50 | | | 17 | | | 23 | |
Gas marketing services | 104 | | | 29 | | | 56 | | | 107 | | | 30 | | | 57 | |
All other | 7 | | | 15 | | | 4 | | | 6 | | | 16 | | | 1 | |
Intercompany eliminations | (2) | | | (2) | | | — | | | (1) | | | (1) | | | — | |
Consolidated | $ | 1,058 | | | $ | 457 | | | $ | 398 | | | $ | 765 | | | $ | 405 | | | $ | 275 | |
(*)Adjusted operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2020 | | Second Quarter 2019 |
| Adjusted Operating Margin(*) | | Operating Expenses(*) | | Net Income (Loss) | | Adjusted Operating Margin(*) | | Operating Expenses(*) | | Net Income (Loss)(b) |
| (in millions) | | (in millions) |
Gas distribution operations | $ | 441 |
| | $ | 314 |
| | $ | 74 |
| | $ | 394 |
| | $ | 287 |
| | $ | 58 |
|
Gas pipeline investments | 8 |
| | 3 |
| | 21 |
| | 8 |
| | 3 |
| | 25 |
|
Wholesale gas services | (19 | ) | | 11 |
| | (23 | ) | | 41 |
| | 10 |
| | 23 |
|
Gas marketing services | 35 |
| | 28 |
| | 5 |
| | 27 |
| | 31 |
| | (3 | ) |
All other | 7 |
| | 14 |
| | (6 | ) | | 7 |
| | 12 |
| | 3 |
|
Intercompany eliminations | (2 | ) | | (2 | ) | | — |
| | (1 | ) | | (1 | ) | | — |
|
Consolidated | $ | 470 |
| | $ | 368 |
| | $ | 71 |
| | $ | 476 |
| | $ | 342 |
| | $ | 106 |
|
| |
(*) | Adjusted operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Year-to-Date 2020 | | Year-to-Date 2019 |
| Adjusted Operating Margin(*) | | Operating Expenses(*) | | Net Income (Loss) | | Adjusted Operating Margin(*) | | Operating Expenses(*) | | Net Income (Loss) |
| (in millions) | | (in millions) |
Gas distribution operations | $ | 1,036 |
| | $ | 654 |
| | $ | 238 |
| | $ | 918 |
| | $ | 601 |
| | $ | 191 |
|
Gas pipeline investments | 16 |
| | 6 |
| | 51 |
| | 16 |
| | 6 |
| | 57 |
|
Wholesale gas services | 31 |
| | 28 |
| | — |
| | 125 |
| | 29 |
| | 70 |
|
Gas marketing services | 142 |
| | 58 |
| | 62 |
| | 142 |
| | 62 |
| | 58 |
|
All other | 13 |
| | 30 |
| | (5 | ) | | 13 |
| | 29 |
| | — |
|
Intercompany eliminations | (3 | ) | | (3 | ) | | — |
| | (4 | ) | | (4 | ) | | — |
|
Consolidated | $ | 1,235 |
| | $ | 773 |
| | $ | 346 |
| | $ | 1,210 |
| | $ | 723 |
| | $ | 376 |
|
| |
(*) | Adjusted operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
Gas Distribution Operations
Gas distribution operations is the largest component of Southern Company Gas' business and is subject to regulation and oversight by regulatory agencies in each of the states it serves. These agencies approve natural gas rates designed to provide Southern Company Gas with the opportunity to generate revenues to recover the cost of natural gas delivered to its customers and its fixed and variable costs, including depreciation, interest expense, operations and maintenance, taxes, and overhead costs, and to earn a reasonable return on its investments.
With the exception of Atlanta Gas Light, Southern Company Gas' second largest utility that operates in a deregulated natural gas market and has a straight-fixed-variable rate design that minimizes the variability of its revenues based on consumption, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas, and general economic conditions that may impact customers' ability to pay for natural gas consumed. Southern Company Gas has various regulatory and other mechanisms, such as weather and revenue normalization mechanisms and weather derivative
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
instruments, that limit its exposure to changes in customer consumption, including weather changes within typical ranges in its natural gas distribution utilities' service territories.
In the secondfirst quarter 2020,2021, net income increased $16$19 million, or 27.6%11.6%, compared to the corresponding period in 2019.2020. The $47$49 million increase in adjusted operating margin primarily reflects base rate increases for Nicor Gas and Atlanta Gas Light, Virginia Natural Gas, and Chattanooga Gas and continued investments recovered throughinvestment in infrastructure replacement programs.replacement. The $27$17 million increase in operating expenses includes increased medical and retirement benefit expenses, higher expenses passed through directly to customers, primarily related to bad debt and pipeline compliance and maintenance activities, and higher depreciation primarily due to additional assets placed in service.service and higher compensation expenses. The $6$5 million increase in other incomeinterest expense net of amounts capitalized is primarily due to an increase in non-service cost-related retirement benefits income. Income tax expense increased $11 million primarily dueadditional debt issued to higher pre-tax earnings and a decrease in the flowback of excess deferred income taxes at Atlanta Gas Light as authorized by the Georgia PSC.
For year-to-date 2020, net income increased $47 million or 24.6%, compared to the corresponding period in 2019.finance continued investments. The $118 million increase in adjusted operating margin primarily reflects base rate increases for Nicor Gas and Atlanta Gas Light and continued investments recovered through infrastructure replacement programs, partially offset by warmer weather, net of weather normalization mechanisms. The $53 million increase in operating expenses includes increased medical and retirement benefit expenses, higher expenses passed through directly to customers, primarily related to bad debt and pipeline compliance and maintenance activities, and additional depreciation primarily due to additional assets placed in service. The $12 million increase in other income is primarily due to an increase in non-service cost-related retirement benefits income. The $31$6 million increase in income tax expense is primarily due to higher pre-tax earnings and a decrease in the flowback of excess deferred income taxes at Atlanta Gas Light as authorized by the Georgia PSC.
earnings. See Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein for additional information.
Gas Pipeline Investments
Gas pipeline investments consists primarily of joint ventures in natural gas pipeline investments including SNG, PennEast Pipeline, Dalton Pipeline, and Atlantic Coast Pipeline (until its sale on March 24, 2020). See NotesNote (E) and (K) to the Condensed Financial Statements under "Southern Company Gas" herein and Note 715 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.
In the second quarter and year-to-date 2020, net income decreased $4 million, or 16.0%, and $6 million, or 10.5%, respectively, compared
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Wholesale Gas Services
Wholesale gas services is involved in asset management and optimization, storage, transportation, producer and peaking services, natural gas supply, natural gas services, and wholesale gas marketing. Southern Company Gas has positioned the business to generate positive economic earnings on an annual basis even under low volatility market conditions that can result from a number of factors. When market price volatility increases, wholesale gas services is well positioned to capture significant value and generate stronger results. Operating expenses primarily reflect employee compensation and benefits.
In the secondfirst quarter 2020,2021, net income decreased $46increased $103 million, or 200.0%447.8%, compared to the corresponding period in 2019. This decrease2020. The increase primarily relates to a $60$247 million decreaseincrease in adjusted operating margin, partially offset by a $15$38 million decreaseincrease in operating expenses primarily related to an increase in variable compensation. The increase was also partially offset by a $75 million increase in other income (expenses) related to higher charitable contributions and a $31 million increase in income tax expense due to lowerhigher pre-tax earnings.
For year-to-date 2020, net income decreased $70 million, or 100.0%, compared to the corresponding period in 2019. This decrease primarily relates to a $94 million decrease in adjusted operating margin and a $1 million decrease in operating expenses, partially offset by a $22 million decrease in income tax expense due to lower pre-tax earnings.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Details of the changes in adjusted operating margin are provided in the table below.
| | | Second Quarter 2020 | Second Quarter 2019 | | Year-to-Date 2020 | Year-to-Date 2019 | | | First Quarter 2021 | First Quarter 2020 |
| (in millions) | | | (in millions) |
Commercial activity recognized | $ | (33 | ) | $ | (1 | ) | | $ | (42 | ) | $ | 37 |
| Commercial activity recognized | | $ | 315 | | $ | (20) | |
Gain (loss) on storage derivatives | (5 | ) | 2 |
| | (11 | ) | 5 |
| Gain (loss) on storage derivatives | | (2) | | (6) | |
Gain on transportation and forward commodity derivatives | 19 |
| 48 |
| | 85 |
| 77 |
| |
Gain (loss) on transportation and forward commodity derivatives | | Gain (loss) on transportation and forward commodity derivatives | | (15) | | 77 | |
LOCOM adjustments, net of current period recoveries | — |
| (6 | ) | | — |
| (8 | ) | LOCOM adjustments, net of current period recoveries | | (1) | | (1) | |
Purchase accounting adjustments to fair value inventory and contracts | — |
| (2 | ) | | (1 | ) | 14 |
| |
| Adjusted operating margin | $ | (19 | ) | $ | 41 |
| | $ | 31 |
| $ | 125 |
| Adjusted operating margin | | $ | 297 | | $ | 50 | |
Change in Commercial Activity
The commercial activity at wholesale gas services includes recognition of storage and transportation values that were generatedgenerated in prior periods, which reflect the impact of prior period hedge gains and losses as associated physical transactions occur. The decreaseincrease in commercial activity in the secondfirst quarter and year-to-date 20202021 compared to the corresponding periodsperiod in 20192020 was primarily due to warmer-than-normalnatural gas price volatility that was generated by cold weather, conditions.particularly in the Midwest and Texas, resulting in wider transportation spreads.
Change in Storage and Transportation Derivatives
Volatility in the natural gas market arises from a number of factors, such as weather fluctuations or changes in supply or demand for natural gas in different regions of the U.S. The volatility of natural gas commodity prices has a significant impact on Southern Company Gas' customer rates, long-term competitive position against other energy sources, and the ability of wholesale gas services to capture value from locational and seasonal spreads. Forward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions in 20202021 resulted in storage derivative losses. Transportation and forward commodity derivative gainslosses in 2020the first quarter 2021 are primarily thea result of narrowingwidening transportation spreads due to supply constraints and increases in natural gas supply, which impacted forward prices at natural gas receipt and delivery points, primarily in the Northeast and Midwest regions.spreads.
Withdrawal Schedule and Physical Transportation Transactions
The expected natural gas withdrawals from storage and expected offset to prior hedge losses/gains associated with the transportation portfolio of wholesale gas services are presented in the following table, along with the net operating revenues expected at the time of withdrawal from storage and the physical flow of natural gas between contracted transportation receipt and delivery points. Wholesale gas services' expected net operating revenues exclude storage and transportation demand charges, as well as other variable fuel, withdrawal, receipt, and delivery charges, and exclude estimated profit sharing under asset management agreements. Further, the amounts that are realizable in future periods are based on the inventory withdrawal schedule, planned physical flow of natural gas between the transportation receipt and delivery points, and forward natural gas prices at June 30, 2020.March 31, 2021. A portion
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
of wholesale gas services' storage inventory and transportation capacity is economically hedged with futures contracts, which results in the realization of substantially fixed net operating revenues.
| | | | | | | | | | | | | | | | | |
| Storage withdrawal schedule | | |
| Total storage(a) | | Expected net operating gains (losses)(b) | | Physical transportation transactions – expected net operating gains (losses)(c) |
| (in mmBtu in millions) | | (in millions) | | (in millions) |
2021 | 11 | | | $ | 6 | | | $ | — | |
2022 and thereafter | 6 | | | 5 | | | 15 | |
Total at March 31, 2021 | 17 | | | $ | 11 | | | $ | 15 | |
Index(b)Represents expected operating gains from planned storage withdrawals associated with existing inventory positions and could change as wholesale gas services adjusts its daily injection and withdrawal plans in response to Financial Statementschanges in future market conditions and forward NYMEX price fluctuations.
(c)Represents the expected net gains during the periods in which the derivatives will be settled and the physical transportation transactions will occur that offset the derivative gains and losses previously recognized.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
|
| | | | | | | | | | |
| Storage withdrawal schedule | | |
| Total storage(a) | | Expected net operating gains(b) | | Physical transportation transactions – expected net operating losses(c) |
| (in mmBtu in millions) | | (in millions) | | (in millions) |
2020 | 15 |
| | $ | 6 |
| | $ | (12 | ) |
2021 and thereafter | 33 |
| | 34 |
| | (73 | ) |
Total at June 30, 2020 | 48 |
| | $ | 40 |
| | $ | (85 | ) |
| |
(a) | At June 30, 2020, the WACOG of wholesale gas services' expected natural gas withdrawals from storage was $1.68 per mmBtu. |
| |
(b) | Represents expected operating gains from planned storage withdrawals associated with existing inventory positions and could change as wholesale gas services adjusts its daily injection and withdrawal plans in response to changes in future market conditions and forward NYMEX price fluctuations. |
| |
(c) | Represents the transportation derivative gains and (losses) that will be settled during the period and the physical transportation transactions that offset the derivative gains and losses previously recognized. |
The unrealized storage and transportation derivative gains do not change the underlying economic value of wholesale gas services' storage and transportation positions and will be reversed when the related transactions occur and are recognized. For more information on wholesale gas services' energy marketing and risk management activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" in Item 7 of the Form 10-K.
Gas Marketing Services
Gas marketing services provides energy-related products and services to natural gas markets and participants in customer choice programs that were approved in various states to increase competition. These programs allow customers to choose their natural gas supplier while the local distribution utility continues to provide distribution and transportation services. Gas marketing services is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to partially mitigate potential weather impacts.
In the second quarter 2020, net income increased $8 million compared to the corresponding period in 2019. This increase primarily relates to an $8 million increase in adjusted operating margin, which primarily reflects recovery of prior period hedge losses, and a $3 million decrease in operating expenses, partially offset by a $3 million increase in income tax expense.
For year-to-date 2020, net income increased $4 million compared to the corresponding period in 2019. This increase primarily relates to a $4 million decrease in operating expenses.
All Other
All other includes natural gas storage businesses, including Jefferson Island through its sale on December 1, 2020, fuels operations through the sale of Southern Company Gas' interest in Pivotal LNG on March 24, 2020, the investment in Triton through its sale on May 29, 2019, AGL Services Company, and Southern Company Gas Capital, as well as various corporate operating expenses that are not allocated to the reportable segments and interest income (expense) associated with affiliate financing arrangements. See Note (K)15 to the Condensed Financial Statementsfinancial statements under "Southern Company Gas" hereinin Item 8 of the Form 10-K for additional information on the sale of its interest in Pivotal LNG.
In the second quarter 2020, net income decreased $9 million compared to the corresponding period in 2019. This decrease primarily reflects a $2 million increase in operating expensesLNG and a $12 million increase in income taxes, partially offset by a $7 million increase in other income (expenses). The increase in other income (expenses) was primarily due to a pre-tax loss on the sale of Triton in 2019. The increase in income taxes reflects the reversal of a federal income tax valuation allowance in connection with the sale of Triton in 2019.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
For year-to-date 2020, net income decreased $5 million compared to the corresponding period in 2019. This decrease includes a $2 million increase in interest expense, net of amounts capitalized, and a $6 million increase in income taxes related to the reversal of a federal income tax valuation allowance in connection with the sale of Triton in 2019, partially offset by a $4 million increase in other income (expenses) primarily due to a pre-tax loss on the sale of Triton in 2019.Jefferson Island.
Segment Reconciliations
Reconciliations of operating income to adjusted operating margin for the secondfirst quarter 2021 and year-to-date 2020 and 2019 are reflected in the following tables. See Note (L) to the Condensed Financial Statements herein for additional information.
|
| | | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2020 |
| Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated |
| (in millions) |
Operating Income (Loss) | $ | 127 |
| $ | 5 |
| $ | (30 | ) | $ | 7 |
| $ | (7 | ) | $ | — |
| $ | 102 |
|
Other operating expenses(a) | 336 |
| 3 |
| 11 |
| 28 |
| 14 |
| (2 | ) | 390 |
|
Revenue tax expense(b) | (22 | ) | — |
| — |
| — |
| — |
| — |
| (22 | ) |
Adjusted Operating Margin | $ | 441 |
| $ | 8 |
| $ | (19 | ) | $ | 35 |
| $ | 7 |
| $ | (2 | ) | $ | 470 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2019 |
| Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated |
| (in millions) |
Operating Income (Loss) | $ | 107 |
| $ | 5 |
| $ | 31 |
| $ | (4 | ) | $ | (5 | ) | $ | — |
| $ | 134 |
|
Other operating expenses(a) | 309 |
| 3 |
| 10 |
| 31 |
| 12 |
| (1 | ) | 364 |
|
Revenue tax expense(b) | (22 | ) | — |
| — |
| — |
| — |
| — |
| (22 | ) |
Adjusted Operating Margin | $ | 394 |
| $ | 8 |
| $ | 41 |
| $ | 27 |
| $ | 7 |
| $ | (1 | ) | $ | 476 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| Year-to-Date 2020 |
| Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated |
| (in millions) |
Operating Income (Loss) | $ | 382 |
| $ | 10 |
| $ | 3 |
| $ | 84 |
| $ | (17 | ) | $ | — |
| $ | 462 |
|
Other operating expenses(a) | 721 |
| 6 |
| 28 |
| 58 |
| 30 |
| (3 | ) | 840 |
|
Revenue tax expense(b) | (67 | ) | — |
| — |
| — |
| — |
| — |
| (67 | ) |
Adjusted Operating Margin | $ | 1,036 |
| $ | 16 |
| $ | 31 |
| $ | 142 |
| $ | 13 |
| $ | (3 | ) | $ | 1,235 |
|
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
| | | | | | | | | | | | | | | | | | | | | | | |
| First Quarter 2021 |
| Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated |
| (in millions) |
Operating Income (Loss) | $ | 287 | | $ | 5 | | $ | 242 | | $ | 75 | | $ | (8) | | $ | — | | $ | 601 | |
Other operating expenses(a) | 410 | | 3 | | 55 | | 29 | | 15 | | (2) | | 510 | |
Revenue tax expense(b) | (53) | | — | | — | | — | | — | | — | | (53) | |
Adjusted Operating Margin | $ | 644 | | $ | 8 | | $ | 297 | | $ | 104 | | $ | 7 | | $ | (2) | | $ | 1,058 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| First Quarter 2020 |
| Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated |
| (in millions) |
Operating Income (Loss) | $ | 255 | | $ | 5 | | $ | 33 | | $ | 77 | | $ | (10) | | $ | — | | $ | 360 | |
Other operating expenses(a) | 385 | | 3 | | 17 | | 30 | | 16 | | (1) | | 450 | |
Revenue tax expense(b) | (45) | | — | | — | | — | | — | | — | | (45) | |
Adjusted Operating Margin | $ | 595 | | $ | 8 | | $ | 50 | | $ | 107 | | $ | 6 | | $ | (1) | | $ | 765 | |
|
| | | | | | | | | | | | | | | | | | | | | |
| Year-to-Date 2019 |
| Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services | Gas Marketing Services | All Other | Intercompany Elimination | Consolidated |
| (in millions) |
Operating Income (Loss) | $ | 317 |
| $ | 10 |
| $ | 96 |
| $ | 80 |
| $ | (16 | ) | $ | — |
| $ | 487 |
|
Other operating expenses(a) | 677 |
| 6 |
| 29 |
| 62 |
| 29 |
| (4 | ) | 799 |
|
Revenue tax expense(b) | (76 | ) | — |
| — |
| — |
| — |
| — |
| (76 | ) |
Adjusted Operating Margin | $ | 918 |
| $ | 16 |
| $ | 125 |
| $ | 142 |
| $ | 13 |
| $ | (4 | ) | $ | 1,210 |
|
(a)Includes other operations and maintenance, depreciation and amortization, and taxes other than income taxes. | |
(a) | Includes other operations and maintenance, depreciation and amortization, and taxes other than income taxes. |
| |
(b) | Nicor Gas' revenue tax expenses, which are passed through directly to customers. |
(b)Nicor Gas' revenue tax expenses, which are passed through directly to customers. FUTURE EARNINGS POTENTIAL
Each Registrant's results of operations are not necessarily indicative of its future earnings potential. Recent disposition activities described under "Acquisitions and Dispositions" herein, in Note (K) to the Condensed Financial Statements herein, and in Note 15 to the financial statements in Item 8 of the Form 10-K will impact future earnings for the applicable Registrants. The level of the Registrants' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Registrants' primary businesses of selling electricity and/or distributing natural gas, as described further herein.
For the traditional electric operating companies, these factors include the ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs during a time of increasing costs, continued customer growth, and the trend of reduced electricity usage per customer, especially in residential and commercial markets. Other major factors includeFor Georgia Power, completing construction of Plant Vogtle Units 3 and 4 and related cost recovery proceedings for Georgia Power and the ability to prevail against legal challenges associated with the Kemper County energy facility for Mississippi Power.is another major factor.
Earnings in the electricity business will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions, which could contribute to a net reduction in customer usage.
Global and U.S. economic conditions have been significantly affected by a series of demand and supply shocks that have caused a global and national economic recession.recession in 2020. Most prominently, the COVID-19 pandemic has negatively impacted global supply chains and globalbusiness operations as suppliers continue to experience difficulties keeping up with strong demand for factory goods, which is being driven by low business inventories. The combination of rising inoculation rates in the U.S. population and services and public policy responses of social distancing and closing non-essential businesses have further restrictedthe recent federal COVID-19 relief package is expected to help boost economic activity.recovery in 2021. The drivers, speed, and depth of thisthe 2020 economic contraction arewere unprecedented and have reduced energy demand across the Southern Company system's service territory, primarily in the commercial and industrial classes. The negative impacts, which started in late-March 2020, of the COVID-19 pandemic and related recession on the Southern Company system's retail electric sales began to improve in the middle of May 2020; however, retail electric sales throughrevenues in the end of the secondfirst quarter 20202021 continued to be approximately 3% to 4% lower than levels projected prior tonegatively impacted by the COVID-19 pandemic. Recovery is expected to continue forinto the remaindersecond half of 2020 and into 2021, but responses to the COVID-19 pandemic by both customers and governmentgovernments could significantly affect the pace of recovery. The ultimate extent of the negative impact on revenues depends on the depth and duration of the economic contraction in
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
the Southern Company system's service territory and cannot be determined at this time. See RESULTS OF OPERATIONS herein for information on COVID-19-related impacts on energy demand in the Southern Company system's service territory during the first six months of 2020.
Alabama Power continues to temporarily suspend disconnections for non-payment by customers and waive late fees as a result of the COVID-19 pandemic. In addition, the traditional electric operating companies have established installment payment plans to allow customers to repay past due accounts over a period of time. See "Regulatory Matters" herein for additional information on the status of disconnections and the deferral of costs resulting from
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
the COVID-19 pandemic at Georgia Power, Mississippi Power, and the natural gas distribution utilities. The ultimate outcome of these matters cannot be determined at this time.quarter 2021.
The level of future earnings for Southern Power's competitive wholesale electric business depends on numerous factors including Southern Power's ability to execute its growth strategy through the development or acquisition of renewable facilities and other energy projects while containing costs, as well as regulatory matters, creditworthiness of customers, total electric generating capacity available in Southern Power's market areas, and Southern Power's ability to successfully remarket capacity as current contracts expire. In addition, renewable portfolio standards, availability of tax credits, transmission constraints, cost of generation from units within the Southern Company power pool, and operational limitations could influence Southern Power's future earnings.
The level of future earnings for Southern Company Gas' primary business of distributing natural gas and its complementary businesses in the gas pipeline investments, wholesale gas services, and gas marketing services sectors depends on numerous factors. These factors include the natural gas distribution utilities' ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs, the completion and subsequent operation of ongoing infrastructure and other construction projects, creditworthiness of customers, and Southern Company Gas' ability to optimize its transportation and storage positions and to re-contract storage rates at favorable prices. The volatility of natural gas prices has an impact on Southern Company Gas' customer rates, its long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services and wholesale gas services businesses to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a portion of Southern Company Gas' operations to earnings variability. Over the longer term, volatility is expected to be low to moderate and locational and/or transportation spreads are expected to decrease as new pipelines are built to reduce the existing supply constraints in the shale areas of the Northeast U.S. To the extent these pipelines are further delayed or not built, volatility could increase. See "Construction Programs"Note 3 to the financial statements in Item 8 of the Form 10-K and Note (C) to the Condensed Financial Statements herein under "Other Matters – Southern Company Gas" for additional information on permitting challenges experienced by the PennEast Pipeline. Additional economic factors may contribute to this environment, including a significant drop in oil and natural gas prices, which could lead to consolidation of natural gas producers or reduced levels of natural gas production. In addition, if the COVID-19 pandemic results in a continued economic downturnuncertainty for a sustained period, demand for natural gas may decrease, resulting in further downward pressure on natural gas prices and lower volatility in the natural gas markets on a longer-term basis.
Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather, competition, developing new and maintaining existing energy contracts and associated load requirements with wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, government incentives to reduce overall energy usage, the prices of electricity and natural gas, and the price elasticity of demand. Demand for electricity and natural gas in the Registrants' service territories is primarily driven by the pace of economic growth or decline that may be affected by changes in regional and global economic conditions, which may impact future earnings.
As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company. In addition, Southern Power and Southern Company Gas regularly consider and evaluate joint development arrangements as well as acquisitions and dispositions of businesses and assets as part of their business strategies. See Note 15 to the financial statements in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL in Item 7 of the Form 10-K and RISK FACTORS in Item 1A herein.10-K.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Acquisitions and Dispositions
See Note 15 to the financial statements in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein for additional information.
Alabama Power
On April 22, 2020 and June 9, 2020, the FERC and the Alabama PSC, respectively, approved the Autauga Combined Cycle Acquisition, which is expected to close by September 1, 2020. See "Regulatory Matters – Alabama Power" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Southern Power
On January 17, 2020, Southern Power completed the sale of its equity interests in Plant Mankato (including the 385-MW expansion unit completed in May 2019) to a subsidiary of Xcel for a purchase price of approximately $663 million, including final working capital adjustments. The sale resulted in a gain of approximately $39 million ($23 million after tax). Pre-tax income for Plant Mankato was immaterial for the six months ended June 30, 2020 and the three and six months ended June 30, 2019.
In March 2020, Southern Power entered into an agreement to acquire a controlling membership interest in an approximately 300-MW wind facility located in South Dakota. The acquisition is subject to FERC approval and certain other customary conditions to closing, including commercial operation of the facility, which is expected to occur in late 2020 or early 2021. The facility's output is contracted under two long-term PPAs. The ultimate outcome of this matter cannot be determined at this time.
On May 1, 2020, Southern Power purchased a controlling interest in the 56-MW Beech Ridge II wind facility located in Greenbrier County, West Virginia from Invenergy Renewables LLC. The facility's output is contracted under a 12-year PPA. See Note (K) to the Condensed Financial Statements herein for additional information.
Southern Power continues to evaluate and refine the deployment of the remaining wind turbine equipment purchased in 2016 and 2017 to development and construction projects. During the six months ended June 30, 2020, certain wind turbine equipment was sold, resulting in an immaterial gain.
Southern Company Gas
On March 24, 2020, Southern Company Gas completed the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline to Dominion Modular LNG Holdings, Inc. and Dominion Atlantic Coast Pipeline, LLC, respectively, with aggregate proceeds of $178 million, including working capital adjustments. The preliminary loss associated with the transactions was immaterial. Southern Company Gas may also receive two future payments of $5 million each, contingent upon certain milestones related to Pivotal LNG being met by Dominion Modular LNG Holdings, Inc. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
Environmental Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" in Item 7 and Note 3 to the financial statements under "Environmental Remediation" in Item 8 of the Form 10-K, as well as Note (C) to the Condensed Financial Statements under "Environmental Remediation""Environmental Remediation" herein, for additional information.
Environmental Laws and Regulations
Coal Combustion ResidualsWater Quality
In June 2020, Alabama Power recorded an increaseis assessing the viability of complying with the EPA's steam electric effluent limitations guidelines (ELG) rule (finalized in 2015) and the ELG reconsideration rule (finalized in October 2020) (ELG rules) for certain of its coal units (totaling approximately $462 million to its AROs related2,000 MWs) due to the CCR Ruletiming and anticipated cost to comply with the ELG rules. The results of the assessment could accelerate a determination to discontinue or modify operation of the units. Alabama Power will review all of the facts and circumstances and evaluate all alternatives prior to reaching a final determination. The units under evaluation have net book values totaling approximately $2.3 billion at March 31, 2021. Additionally, net capitalized asset retirement costs associated with these facilities totaled approximately $900 million at March 31, 2021. Alabama Power is authorized to establish a regulatory asset to record the unrecovered investment costs, including the plant asset balance and the related state rule primarily due to management's completion of a feasibility study and the related cost estimates during the second quarter 2020 for one of its ash ponds. Alabama Power's increase also reflects costs
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
associated with the addition of a water treatment systemsite removal and closure, associated with future unit retirements caused by environmental regulations. The regulatory asset would be amortized and recovered over an affected unit's remaining useful life, as established prior to the design of another ash pond. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to inputs from contractor bids, design revisions, and changes in the expected volume of ash handling.
The traditional electric operating companies expect to continue updating their cost estimates and ARO liabilities periodically as additional information related to ash pond closure methodologies, schedules, and/or costs becomes available. Additionally, the closure designs and plans in the States of Alabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costsdecision regarding early retirement, through regulated rates, results of operations, cash flows, and financial condition for Southern Company and the traditional electric operating companies could be materially impacted.Rate CNP Compliance. See Note (B)2 to the Condensed Financial Statementsfinancial statements under "Georgia"Alabama Power – Integrated Resource PlanRate CNP Compliance" and " herein– Environmental Accounting Order" in Item 8 of the Form 10-K for additional information. The ultimate outcome of these mattersthis matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
Regulatory Matters
See OVERVIEW – "Recent Developments" and Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.
Alabama Power
Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subjecta discussion of regulatory matters related to the oversight of the Alabama PSC. Alabama Power, currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power.
Petition for Certificate of Convenience and Necessity
On June 9, 2020, the Alabama PSC approved in part Alabama Power's petition for a CCN which authorizes Alabama Power to (i) construct an approximately 720-MW combined cycle facility at Alabama Power's Plant Barry (Plant Barry Unit 8), which is expected to be placed in service by the end of 2023, (ii) complete the Autauga Combined Cycle Acquisition, which was approved by the FERC on April 22, 2020 and is expected to close by September 1, 2020, (iii) purchase approximately 240 MWs of combined cycle generation under a long-term PPA expected to begin later in 2020 and (iv) pursue up to approximately 200 MWs of certain demand-side management and distributed energy resource programs.
The Alabama PSC authorized the recovery of actual costs for the construction of Plant Barry Unit 8 up to 5% above the estimated in-service cost of $652 million. In so doing, it recognized the potential for developments that could cause the project costs to exceed the capped amount, in which case Alabama Power would provide documentation to the Alabama PSC to explain and justify potential recovery of the additional costs.
The Alabama PSC further directed that the proposed solar generation of approximately 400 MWs, coupled with battery energy storage systems (solar/battery systems), be evaluated under an existing Renewable Generation Certificate issued by the Alabama PSC in September 2015.
Alabama Power expects to recover all approved costs associated with the CCN through existing rate mechanisms as outlined in Note 2 to the financial statements in Item 8 of the Form 10-K. The Alabama PSC's approval in part of the CCN will be followed by a written order which is subject to any rehearing request or judicial appeal filed within 30 days of the date of such order.
The ultimate outcome of these matters cannot be determined at this time.
Georgia Power,
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through an alternate rate plan, which includes traditional base tariffs, Demand-Side Management tariffs, the
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Environmental Compliance Cost Recovery tariff, and Municipal Franchise Fee tariffs. In addition, financing costs on certified construction costs of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff.
Deferral of Incremental COVID-19 Costs
On April 7, 2020 and June 2, 2020, in response to the COVID-19 pandemic, the Georgia PSC approved orders directing Georgia Power to continue its previous, voluntary suspension of customer disconnections through July 14, 2020 and to defer the resulting incremental bad debt as a regulatory asset. On June 16, 2020 and July 7, 2020, the Georgia PSC approved orders establishing a methodology for identifying incremental bad debt and allowing the deferral of other incremental costs associated with the COVID-19 pandemic. The period over which such costs will be recovered is expected to be determined in Georgia Power's next base rate case. At June 30, 2020, the incremental costs deferred totaled approximately $34 million. The ultimate outcome of this matter cannot be determined at this time.
Integrated Resource Plan
On March 5, 2020, the Sierra Club filed a petition for judicial review in the Superior Court of Fulton County to appeal the Georgia PSC's decision in the 2019 ARP allowing Georgia Power to recover compliance costs for CCR AROs. Georgia Power intervened in the appeal on June 22, 2020. The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
On May 28, 2020, the Georgia PSC approved a stipulation agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors to lower total fuel billings by approximately $740 million over a two-year period effective June 1, 2020. In addition, Georgia Power will further lower fuel billings by approximately $44 million under an interim fuel rider effective June 1, 2020 through September 30, 2020. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to its next fuel case if the under or over recovered fuel balance exceeds $200 million. Georgia Power is scheduled to file its next fuel case no later than February 28, 2023.
Mississippi Power
Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are expected to be recovered through Mississippi Power's base rates.
2019 Base Rate Case
On March 17, 2020, the Mississippi PSC approved the Mississippi Power Rate Case Settlement Agreement between Mississippi Power, and the Mississippi Public Utilities Staff related to Mississippi Power's base rate case filed in November 2019.
Under the terms of the Mississippi Power Rate Case Settlement Agreement, annual retail rates decreased approximately $16.7 million, or 1.85%, effective for the first billing cycle of April 2020, based on a test year period of January 1, 2020 through December 31, 2020, a 53% average equity ratio, an allowed maximum actual equity ratio of 55% by the end of 2020, and a 7.57% return on investment.
Additionally, the approved Mississippi Power Rate Case Settlement Agreement: (i) established common amortization periods of four years for regulatory assets and three years for regulatory liabilities included in the approved revenue requirement, including those related to unprotected deferred income taxes; (ii) established new depreciation rates reflecting an annual increase in depreciation of approximately $10 million; and (iii) excluded
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
certain compensation costs totaling approximately $3.9 million. It also eliminated separate rates for costs associated with Plant Ratcliffe and energy efficiency initiatives and includes such costs in the PEP, ECO Plan, and ad valorem tax adjustment factor, as applicable. In accordance with the previous order of the Mississippi PSC suspending the operation of PEP and the ECO Plan for 2018 through 2020, Mississippi Power plans to resume PEP proceedings and ECO Plan filings for 2021.
Performance Evaluation Plan
On July 24, 2020, the Mississippi PSC approved Mississippi Power's July 14, 2020 filing of its PEP compliance rate clause reflecting revisions agreed to in the Mississippi Power Rate Case Settlement Agreement. These revisions include, among other things, changing the filing date for the annual PEP rate filing from November of the immediately preceding year to March of the current year, utilizing a historic test year adjusted for "known and measurable" changes, using discounted cash flow and regression formulas to determine base return on equity, and moving all embedded ad valorem property taxes currently collected in PEP to the ad valorem tax adjustment clause.
Deferral of Incremental COVID-19 Costs
On April 14, 2020 and May 12, 2020, in order to mitigate the economic impact of the COVID-19 pandemic on customers, the Mississippi PSC approved orders directing Mississippi Power to continue its previous, voluntary suspension of customer disconnections through May 25, 2020 and to defer as a regulatory asset all necessary and reasonable incremental costs or expenses to plan, prepare, stage, or react to protect and keep safe its employees and customers, and to reliably operate its utility system during the COVID-19 pandemic. The period over which such costs will be recovered is expected to be determined in a future PEP filing. At June 30, 2020, the incremental costs deferred totaled approximately $2 million. The ultimate outcome of this matter cannot be determined at this time.
Municipal and Rural Associations Tariff
On June 25, 2020, the FERC accepted Mississippi Power's April 27, 2020 request for an increase in wholesale base revenues under the MRA tariff as agreed upon in a settlement agreement reached with its wholesale customers. The MRA settlement agreement resulted in a $2 million annual increase in base rates effective June 1, 2020.
Southern Company Gas, including items that could impact the applicable registrants' future earnings, cash flows, and/or financial condition.
The natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies for the rates charged to their customers and other matters. With the exception of Atlanta Gas Light, which does not sell natural gas to end-use customers, the natural gas distribution utilities are authorized by the relevant regulatory agencies in the states in which they serve to use natural gas cost recovery mechanisms that adjust rates to reflect changes in the wholesale cost of natural gas and ensure recovery of all costs prudently incurred in purchasing natural gas for customers. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on revenues or net income, but will affect cash flows. In addition to natural gas cost recovery mechanisms, there are other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs, as well as environmental remediation, energy efficiency plans, and bad debt.
The natural gas distribution utilities have various regulatory mechanisms to recover bad debt expense, which will mitigate potential increases in bad debt expense as a result of the COVID-19 pandemic. Nicor Gas fully recovers its bad debt expenses, both the gas and non-gas portions, through its purchased gas adjustment mechanism and separate bad debt rider. Virginia Natural Gas and Chattanooga Gas recover the gas portion of bad debt expense through their purchased gas adjustment mechanisms and the non-gas portion of bad debt expense through their base rates in accordance with established benchmarks. Atlanta Gas Light does not have material bad debt expense because its receivables are from Marketers, rather than end-use customers. Its tariff allows it to obtain credit security support from the Marketers in an amount equal to at least two times their estimated highest bill.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Rate Proceedings
On June 1, 2020, Virginia Natural Gas filed a general rate case with the Virginia Commission seeking an increase in rates of$49.6 million primarily to recover investments and increased costs associated with infrastructure, technology, and workforce development. The requested increase is based on a projected 12-month test year beginning November 1, 2020, a ROE of 10.35%, and an equity ratio of 54%. Rate adjustments are expected to be effective November 1, 2020, subject to refund. The Virginia Commission is expected to rule on the requested increase in the second quarter 2021.
On July 1, 2020, Atlanta Gas Light filed its 2020 GRAM filing with the Georgia PSC. The filing requests an annual base rate increase of $37.6 million based on the projected 12-month period beginning January 1, 2021, which does not exceed the 5% limitation established by the Georgia PSC in its December 2019 approval of Atlanta Gas Light's general base rate case. Resolution of the 2020 GRAM filing is expected by December 31, 2020, with rates effective January 1, 2021.
The ultimate outcome of these matters cannot be determined at this time.
Deferral of Incremental COVID-19 Costs
Atlanta Gas Light
On April 30, 2020, in response to the COVID-19 pandemic, the Georgia PSC approved orders directing Atlanta Gas Light to continue its previous, voluntary suspension of customer disconnections. On June 22, 2020, the Georgia PSC ordered Atlanta Gas Light to resume customer disconnections beginning July 1, 2020, with exceptions for customers still covered by a shelter-in-place order. The orders provide the Marketers, including SouthStar, with a mechanism to receive credits from Atlanta Gas Light for the base rates it charged to the Marketers of non-paying customers during the suspension. Atlanta Gas Light expects to recover these credits through the annual revenue true-up process within its 2021 GRAM filing, which would impact rates effective January 1, 2022. The ultimate outcome of this matter cannot be determined at this time.
Nicor Gas
On March 18, 2020, the Illinois Commission issued an order directing utilities to cease disconnections for non-payment and to suspend the imposition of late payment fees or penalties until the Governor of Illinois announces the end of the COVID-19 state of emergency. In response to this order, on March 27, 2020, Nicor Gas and other utilities in Illinois filed their plans seeking cost recovery and more flexible credit and collection plans.
On June 18, 2020, the Illinois Commission approved a stipulation pursuant to which the utilities will provide more flexible credit and collection procedures to assist customers with financial hardship and which authorizes a special purpose rider for recovery of the following COVID-19 pandemic-related impacts: incremental costs directly associated with the COVID-19 pandemic, net of the offset for COVID-19 pandemic-related credits received, foregone late fees, foregone reconnection charges, and the costs associated with a bill payment assistance program. The special purpose rider is proposed to be effective on October 1, 2020 and continue over a 24-month period. At June 30, 2020, Nicor Gas' related regulatory asset was $12 million. The ultimate outcome of this matter cannot be determined at this time.
Virginia Natural Gas
In response to the COVID-19 pandemic, the Virginia Commission issued orders requiring Virginia Natural Gas to suspend disconnections beginning on March 16, 2020 and also to suspend late payment and reconnection fees beginning on April 9, 2020, both of which continue in effect through August 31, 2020. On April 29, 2020, the Virginia Commission authorized Virginia Natural Gas to defer the following COVID-19 pandemic-related costs as a regulatory asset: incremental uncollectible expense incurred, suspended late fees, suspended reconnection charges, carrying costs, and other incremental prudently incurred costs associated with the COVID-19 pandemic. Specific recovery of the amounts deferred in a regulatory asset will be addressed in a future rate proceeding. At June 30,
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
2020, Virginia Natural Gas' related regulatory asset was $1 million. The ultimate outcome of this matter cannot be determined at this time.
Construction Programs
Overview
The Subsidiary Registrants are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, expanding and improving the electric transmission and electric and natural gas distribution systems, and undertaking projects to comply with environmental laws and regulations.
For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4. See "Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction"Construction" herein for additional information. Also see Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Alabama Power" for information regarding Alabama Power's construction of Plant Barry Unit 8.
While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. See "Southern Power" herein, "Acquisitions and Dispositions – Southern Power" herein,Note 15 to the financial statements in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power" herein as well as Note 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K, for additional information about costs relating to Southern Power's acquisitions that involve construction of renewable energy facilities.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates. See Notes 2 and 3 to the financial statements in Item 8 of the Form 10-K and Notes (B) and (C) to the Condensed Financial Statements herein under "Southern Company Gas" hereinand "Other Matters – Southern Company Gas – PennEast Pipeline Project," respectively, for additional information regarding infrastructure improvement programs at the natural gas distribution utilities and the PennEast Pipelineon Southern Company Gas' construction project.program.
See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations""Cash Requirements" herein for additional information regarding the Registrants' capital requirements for their construction programs.
Nuclear Construction
See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, the joint ownership agreements and related funding agreement, VCM reports, and the NCCR tariff.
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4, in which Georgia Power holds a 45.7% ownership interest. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.
In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.
See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for information on the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.
Cost and Schedule
Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:
|
| | | |
| (in billions) |
Base project capital cost forecast(a)(b) | $ | 8.4 |
|
Construction contingency estimate | 0.1 |
|
Total project capital cost forecast(a)(b) | 8.5 |
|
Net investment as of June 30, 2020(b) | (6.6 | ) |
Remaining estimate to complete(a) | $ | 1.9 |
|
| |
(a) | Excludes financing costs expected to be capitalized through AFUDC of approximately $260 million, of which $52 million had been accrued through June 30, 2020. |
| |
(b) | Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds. |
Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.0 billion, of which $2.4 billion had been incurred through June 30, 2020.
As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers, and workforce statistics.
During the second quarter 2020, approximately $194 million of construction contingency was assigned to the base capital cost forecast for cost risks including, among other things, construction productivity, including the April 2020 reduction in workforce designed to mitigate impacts of the COVID-19 pandemic described below, field support, subcontracts, engineering resources, and procurement. The second quarter 2020 assignment of contingency exceeded the remaining balance of the $366 million construction contingency originally established in the second quarter 2018 by approximately $34 million. Through June 30, 2020, assignments of contingency for cost risks also have included, among other factors, construction productivity; craft labor incentives; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement. As a result of these factors, Southern Nuclear recommended establishing additional construction contingency, of which Georgia Power's share is approximately $115 million, for further potential risks including, among other factors, construction productivity and expected impacts of the COVID-19
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
pandemic; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement.
After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $149 million ($111 million after tax) for the increase in the total project capital cost forecast as of June 30, 2020. As and when these amounts are spent, Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery.
In April 2019, Southern Nuclear established aggressive target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the regulatory-approved in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. Through early 2020, the project faced challenges with the April 2019 aggressive strategy targets including, but not limited to, electrical and pipefitting labor productivity and work package closure rates, which resulted in a backlog of activities and completion percentages below the April 2019 aggressive strategy targets.
In February 2020, Southern Nuclear updated its cost and schedule forecast, which, at that time, did not change the total project capital cost forecast and confirmed the expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4. This update included initiatives to improve productivity while refining and extending system turnover plans and certain near-term milestone dates. Other milestone dates did not change. Achievement of the February 2020 aggressive site work plan relied on meeting increased monthly production and activity target values during 2020.
In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures, isolating individuals who have tested positive for COVID-19, are showing symptoms consistent with COVID-19, are being tested for COVID-19, or have been in close contact with such persons, requiring self-quarantine, and adopting additional precautionary measures.
In April 2020, Georgia Power, acting for itself and as agent for the other Vogtle Owners, announced a reduction in workforce at Plant Vogtle Units 3 and 4, which totaled approximately 20% of the then-existing site workforce. This reduction in workforce was a mitigation action intended to address the impact of the COVID-19 pandemic on the Plant Vogtle Units 3 and 4 workforce and construction site, including challenges with labor productivity that were exacerbated by the impact of the COVID-19 pandemic. The April 2020 workforce reduction was intended to provide operational efficiencies by increasing productivity of the remaining workforce and reducing workforce fatigue and absenteeism. Further, it was also intended to allow for increased social distancing by the workforce and facilitate compliance with the recommendations from the Centers for Disease Control and Prevention. The April 2020 workforce reduction did reduce absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing. From the initial peak in April 2020, the number of active cases at the site declined significantly during May and early June, but began increasing again in mid-June and continues to impact productivity levels and pace of activity completion. As a result of these factors, overall production improvements have not been achieved at the levels anticipated, contributing to the allocation of, and increase in, construction contingency described above. Through mid-July 2020, Unit 3 mechanical, electrical, and subcontract activities continued to build a backlog to Southern Nuclear's February 2020 aggressive site work plan.
To address these issues, in July 2020, Southern Nuclear updated its aggressive site work plan for both Unit 3 and Unit 4. To meet the targets in the July 2020 aggressive site work plan, absenteeism rates must continue to normalize and overall construction productivity and production levels, including subcontractors, must significantly improve and be sustained above pre-pandemic levels. In addition, appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, must be added and maintained. While Southern Nuclear's July 2020 aggressive site work plan extended milestone dates from the February 2020 aggressive site work plan, Georgia Power still expects to achieve the regulatory-approved in-service dates of November 2021 and November 2022 for Plant Vogtle Units 3
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
and 4, respectively. Southern Nuclear and Georgia Power continue to believe that pursuit of an aggressive site work plan is an appropriate strategy to achieve completion of the units by their regulatory-approved in-service dates.
As construction, including subcontract work, continues and testing and system turnover activities increase, challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale), any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.
In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4. Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be between $70 million and $115 million, which is included in the total project capital cost forecast and assumes (i) absenteeism rates continue to normalize and (ii) the intended productivity efficiencies and production targets assumed in Southern Nuclear's July 2020 aggressive site work plan are realized in the coming months. However, the ultimate impact of the COVID-19 pandemic on the construction schedule and budget for Plant Vogtle Units 3 and 4 cannot be determined at this time.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, may arise, which may result in additional license amendments or require other resolution. As part of the aggressive site work plan, in January 2020, Southern Nuclear notified the NRC of its intent to load fuel in 2020. On May 11, 2020, the Blue Ridge Environmental Defense League filed a petition with the NRC that challenges a license amendment request. On June 15, 2020, the NRC issued an appealable order rejecting Nuclear Watch South's April 20, 2020 petition requesting a hearing and challenging the closure of certain ITAAC. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
The ultimate outcome of these matters cannot be determined at this time. However, any extension of the regulatory-approved project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $10 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.
Joint Owner Contracts
In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
As a result of an increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs in conjunction with the nineteenth VCM report in 2018, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. In September 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4.
Amendments to the Vogtle Joint Ownership Agreements
In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG Power's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG Power and MEAG SPVJ to provide up to $300 million of funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. In January 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. In February 2019, Georgia Power, the other Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet (Global Amendments).
As previously disclosed, pursuant to the Global Amendments: (i) each Vogtle Owner must pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which formed the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests. If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option at the time the project budget forecast is so revised to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion.
In addition, pursuant to the Global Amendments, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including, among other events: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power's public announcement of its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Global Amendments described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule.
The ultimate outcome of these matters cannot be determined at this time.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. At June 30, 2020, Georgia Power had recovered approximately $2.4 billion of financing costs. Financing costs related to capital costs above $4.418 billion are being recognized through AFUDC and are expected to be recovered through retail rates over the life of Plant Vogtle Units 3 and 4; however, Georgia Power will not record AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery. In December 2019, the Georgia PSC approved Georgia Power's request to decrease the NCCR tariff by $62 million annually, effective January 1, 2020.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and related customer refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective Unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $75 million in 2019 and are estimated to have negative earnings impacts of approximately $145 million, $255 million, and $200 million in 2020, 2021, and 2022, respectively. In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
In February 2018, Georgia Interfaith Power & Light, Inc. (GIPL) and Partnership for Southern Equity, Inc. (PSE) filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. In March 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's decision and denial of Georgia Watch's motion for reconsideration. In December 2018, the Fulton County Superior Court granted Georgia Power's motion to dismiss the two appeals. In January 2019, GIPL, PSE, and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. In October 2019, the Georgia Court of Appeals issued an opinion affirming the Fulton County Superior Court's ruling that the Georgia PSC's January 11, 2018 order was not a final, appealable decision. In addition, the Georgia Court of Appeals remanded the case to the Fulton County Superior Court to clarify its ruling as to whether the petitioners showed that review of the Georgia PSC's final order would not provide them an adequate remedy. On April 21, 2020, the Fulton County Superior Court granted Georgia Power's motion to dismiss the two appeals. The petitioners filed a notice of appeal of the dismissal on May 20, 2020. Georgia Power believes the petitions have no merit; however, an adverse outcome in the litigation combined with subsequent adverse action by the Georgia PSC could have a material impact on Southern Company's and Georgia Power's results of operations, financial condition, and liquidity.
The Georgia PSC has approved 21 VCM reports covering the periods through June 30, 2019, including total construction capital costs incurred through that date of $6.7 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). On August 18, 2020, the Georgia PSC is scheduled to vote on Georgia Power's twenty-second VCM report, which requested approval of $674 million of construction capital costs incurred from July 1, 2019 through December 31, 2019.
Georgia Power expects to file its twenty-third VCM report with the Georgia PSC by August 31, 2020, which will reflect the revised capital cost forecast discussed above and request approval of $701 million of construction capital costs incurred from January 1, 2020 through June 30, 2020.
See RISK FACTORS in Item 1A herein and in the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.
The ultimate outcome of these matters cannot be determined at this time.
Southern Power
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Construction Programs – Southern Power" in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.
During the six months ended June 30, 2020, Southern Power completed construction of and placed in service the Reading wind facility, continued construction of the Skookumchuck wind facility, and commenced construction of the Garland and Tranquillity battery energy storage facilities. Total aggregate construction costs, excluding acquisition costs, are expected to be between $475 million and $545 million for the facilities under construction. At June 30, 2020, total costs of construction incurred for these projects were $232 million and are included in CWIP. The ultimate outcome of these matters cannot be determined at this time.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
|
| | | | | | |
Project Facility | Resource | Approximate Nameplate Capacity (MW)
| Location | Actual/Expected
COD
| PPA Counterparties | PPA Contract Period |
Projects Completed During the Six Months Ended June 30, 2020 | |
Reading(a)
| Wind | 200 | Osage and Lyon Counties, KS | May 2020 | Royal Caribbean Cruises LTD | 12 years |
Projects Under Construction as of June 30, 2020 | | |
Skookumchuck(b)
| Wind | 136 | Lewis and Thurston Counties, WA | Fourth quarter 2020 | Puget Sound Energy | 20 years |
Garland Solar Storage(c)
| Battery energy storage system | 88 | Kern County, CA | Second quarter 2021 | Southern California Edison | 20 years |
Tranquillity Solar Storage(c)
| Battery energy storage system | 72 | Fresno County, CA | Second quarter 2021 | Southern California Edison | 20 years |
| |
(a) | In 2018, Southern Power purchased 100% of the membership interests of the Reading facility pursuant to a joint development arrangement. At the time the facility was placed in service, Southern Power recorded an operating lease right-of-use asset and an operating lease liability, each in the amount of $24 million. In June 2020, Southern Power completed a tax equity transaction whereby it received $156 million and now owns 100% of the Class B membership interests. |
| |
(b) | In October 2019, Southern Power purchased 100% of the membership interests of the Skookumchuck facility pursuant to a joint development arrangement. Southern Power expects to complete a tax equity transaction upon commercial operation and retain the Class B membership interests. Shortly after commercial operation, Southern Power may sell a noncontrolling interest in these Class B membership interests to another partner. The ultimate outcome of these matters cannot be determined at this time. |
| |
(c) | Prior to commercial operation, Southern Power may enter into one or more partnerships, in which case it would ultimately own less than 100% of the Class B membership interests, but would retain ownership of the controlling interest. The PPAs for these facilities are pending approval from the California Public Utilities Commission. The ultimate outcome of these matters cannot be determined at this time. |
Southern Company Gas
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Construction Programs – Southern Company Gas" in Item 7 of the Form 10-K for additional information.
Infrastructure Replacement Programs and Capital Projects
In addition to capital expenditures recovered through base rates by each of the natural gas distribution utilities, Nicor Gas and Virginia Natural Gas have separate rate riders that provide timely recovery of capital expenditures for specific infrastructure replacement programs. Infrastructure expenditures incurred under these programs in the first six months of 2020 were as follows:
|
| | | | |
Utility | Program | Year-to-Date 2020 |
| | (in millions) |
Nicor Gas | Investing in Illinois | $ | 158 |
|
Virginia Natural Gas | Steps to Advance Virginia's Energy (SAVE) | 25 |
|
Total | | $ | 183 |
|
In December 2019, Virginia Natural Gas filed an application with the Virginia Commission for a 24.1-mile header improvement project to improve resiliency and increase the supply of natural gas delivered to energy suppliers, including Virginia Natural Gas. On June 26, 2020, the Virginia Commission issued an order requiring Virginia Natural Gas to submit additional information by December 31, 2020 related to the financing plans of the project's primary customer before ruling on the December 2019 application. The ultimate outcome of this matter cannot be determined at this time.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" in Item 8 of the Form 10-K for additional information.
Pipeline Construction Projects
On March 24, 2020, Southern Company Gas completed the sale of its interest in Atlantic Coast Pipeline. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
On February 20, 2020, the FERC approved a two-year extension for PennEast Pipeline to complete the project by January 19, 2022.
In September 2019, an appellate court ruled that the PennEast Pipeline does not have federal eminent domain authority over lands in which a state has property rights interests. On June 29, 2020, the U.S. Supreme Court requested the U.S. Solicitor General to provide an opinion on PennEast Pipeline's petition for a writ of certiorari seeking its review of the appellate court's decision.
Expected project costs related to the PennEast Pipeline for Southern Company Gas total approximately $300 million, excluding financing costs. The ultimate outcome of the PennEast Pipeline construction project cannot be determined at this time; however, any work delays, whether caused by judicial or regulatory action, abnormal weather, or other conditions, may result in additional cost or schedule modifications or, ultimately, in project cancellation, any of which could result in impairment of Southern Company Gas' investment and could have a significant impact on Southern Company's financial statements and a material impact on Southern Company Gas' financial statements.
See Notes 3 and 7 to the financial statements in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information.
Southern Power's Power Sales Agreements
See BUSINESS – "The Southern Company System – Southern Power" in Item 1 of the Form 10-K and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Southern Power's Power Sales Agreements" in Item 7 of the Form 10-K for additional information regarding Southern Power's PPAs. Generally, under the solar and wind generation PPAs, the purchasing party retains the right to keep or resell the renewable energy credits.
During the first quarter 2020, Southern Power received $15 million from Pacific Gas & Electric Company (PG&E) in accordance with a November 2019 bankruptcy court order granting payment of certain transmission interconnections. PG&E emerged from bankruptcy on July 1, 2020 and Southern Power's PPAs and transmission interconnection agreements continue in effect unchanged.
Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" in Item 7 of the Form 10-K and Note (G) to the Condensed Financial Statements herein for additional information.
On March 18, 2020 and March 27, 2020, respectively, the Families First Coronavirus Response Act and the Coronavirus Aid, Relief, and Economic Security Act were signed into law. Both acts include provisions intended to provide stability and support for individuals and businesses in response to the COVID-19 pandemic. Southern Company continues to evaluate these provisions, including those related to payroll tax deferrals and employee retention credits; however, they are not expected to have a material impact on the Registrants' financial statements.
On March 20, 2020 and April 9, 2020, the Treasury Department and the Internal Revenue Service issued Notices 2020-18 and 2020-23, respectively, providing relief to taxpayers by postponing to July 15, 2020 a variety of tax form filings and payment obligations that were due before July 15, 2020. Associated interest, additions to tax, and penalties for late filing or late payment were also suspended until July 16, 2020. These provisions had a modest
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
positive impact on the Registrants' liquidity. However, Southern Power's expected utilization of tax credits in the first half of 2020 was delayed until July 15, 2020.
General Litigation and Other Matters
The Registrants are involved in various other matters being litigated and/or regulatory and regulatoryother matters that could affect future earnings.earnings, cash flows, and/or financial condition. The ultimate outcome of such pending or potential litigation or regulatory matters against each Registrant and any subsidiaries or regulatory and other matters cannot be determined at this time; however, for current proceedings and/or matters not specifically reported herein or in Notes (B) and (C) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings and/or matters would have a material effect on such Registrant's financial statements. See Notes (B) and (C) to the Condensed Financial Statements for a discussion of various other contingencies, including matters being litigated, regulatory matters, and other matters being litigated which may affect future earnings potential.
The Registrants believe the pending legal challenges discussed below have no merit; however, the ultimate outcome of these matters cannot be determined at this time.
Southern Company
In January 2017, a securities class action complaint was filed in the U.S. District Court for the Northern District of Georgia by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint names as defendants Southern Company, certain of its current and former officers, and certain former Mississippi Power officers and alleges that the defendants made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. Also in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition. In 2018, the court issued an order dismissing certain claims against certain officers of Southern Company and Mississippi Power and dismissing the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. In 2018, the court denied the defendants' motion for reconsideration and also denied a motion to certify the issue for interlocutory appeal. In the third quarter 2019, the court certified the plaintiffs' proposed class and the defendants filed a petition for interlocutory appeal of the class certification order with the U.S. Court of Appeals for the Eleventh Circuit. In December 2019, the U.S. District Court for the Northern District of Georgia entered an order staying all deadlines in the case pending mediation. The stay automatically expired on March 31, 2020; however, in light of the COVID-19 pandemic, the U.S. District Court for the Northern District of Georgia vacated all existing discovery deadlines until June 15, 2020. On June 30, 2020, the court entered a revised scheduling order, which resumed discovery and set out remaining case deadlines.
In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. In 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. In 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, Georgia that names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. In 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the securities class action. In August 2019, the court granted a motion filed by the plaintiff in July 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust.
GeorgiaAlabama Power
In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state law claims. This case has been ruled upon and appealed numerous times over the last several years. In one recent appeal, the Georgia Supreme Court remanded the case and noted that the trial court could refer the matter to the Georgia PSC to interpret its tariffs. Following a motion by Georgia Power, in February 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling and also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. Also in March 2019, Georgia Power appealed the class certification decision to the Georgia Court of Appeals. In October 2019, the Georgia PSC issued an order that found Georgia Power has appropriately implemented the municipal franchise fee schedule. On March 11, 2020, the Georgia Court10, 2021, Alabama Power executed a coordinated planning and operations agreement with PowerSouth, with a minimum term of Appeals vacated the Superior Court of Fulton County's February 2019 order granting conditional class certification.10 years. The Court of Appeals remanded the caseagreement, which includes combined operations (including joint commitment and dispatch), is expected to the Superior Court of Fulton Countycreate energy cost savings and enhanced system reliability for further proceedings. The amount ofboth parties. Projected revenues are expected to offset any possible losses cannot be calculated at this time because, among other factors, it is unknown whether a class will be certified, the ultimate composition of any class, and whether any losses would be subject to recovery from any municipalities.
On July 29, 2020, a group of individual plaintiffs filed a complaint in the Superior Court of Fulton County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater, surface water, and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief.
Mississippi Power
In May 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filedincreased administrative costs incurred by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. A portion of the claim for damages was on behalf of Martin Transport, Inc. (Martin Transport), an affiliate of Martin. In May 2019, the arbitration panel denied Mississippi Power's and Southern Company's motions to dismiss. In September 2019, Martin Transport filed a separate complaint against Mississippi Power in the Circuit Court of Kemper County, Mississippi alleging claims of fraud, negligent misrepresentation, promissory estoppel, and equitable estoppel, each arising out of the same alleged facts and circumstances that underlie Martin's arbitration demand. Martin Transport seeks compensatory damages of $5 million and punitive damages of $50 million. In November 2019, Martin Transport's claim was combined with the Martin arbitration case and the
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
separate court case was dismissed. In December 2019, Southern Company and Mississippi Power each filed motions for summary judgment on all claims. On February 17, 2020, the arbitration panel granted Southern Company's motion and dismissed Southern Company from the arbitration. On March 12, 2020, the arbitration panel denied Mississippi Power's motions for summary judgment. An adverse outcome in this proceeding could have aAlabama Power; therefore, no material impact on Southern Company's and Mississippi Power's financial statements.
In November 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippito net income is expected. Alabama Power and the three then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. In response to Mississippi Power and the Mississippi PSC each filing a motion to dismiss, the plaintiffs filed an amended complaint in March 2019. The amended complaint included four additional plaintiffs and additional claims for gross negligence, reckless conduct, and intentional wrongdoing. Mississippi Power and the Mississippi PSC have each filed a motion to dismiss the amended complaint. On March 27, 2020, the Mississippi PSC's motion to dismiss was granted. Also on March 27, 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. On April 9, 2020 and April 10, 2020, Mississippi Power and the Mississippi PSC, respectively, filed responses opposing the motion for leave to file a second amended complaint. On May 26, 2020, Mississippi Power's motion to dismiss the first amended complaint filed in 2019 was granted. On July 6, 2020, the plaintiffs filed a motion for revision of the court's decision. The plaintiffs' motion for leave to file a second amended complaint also remains pending before the court. An adverse outcome in this proceeding could have a material impact on Mississippi Power's financial statements.
See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.
Other Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" in Item 7 of the Form 10-K for additional information.
Southern Company
See Notes 1 and 3 under "Leveraged Leases" and "Other Matters – Southern Company," respectively, in Item 8 of the Form 10-K for discussion of challenges associated with a leveraged lease agreement with a subsidiary of Southern Holdings. While all required lease payments through June 30, 2020 have been paid in full, the operational and remarketing risks and the resulting cash liquidity challenges persist and significant concerns continue regarding the lessee's ability to make the remaining required semi-annual lease payments to the Southern Holdings subsidiary through the term of the lease.
In its annual impairment analysis of the expected residual value of the generation assets and the overall collectability of the related lease receivable, Southern Company uses multiple scenarios of long-term market energy prices to estimate the cash flows expected to be received from remarketing the generation assets following the expiration of the existing PPA in 2032 and the residual value of the generation assets at the end of the lease in 2047. Southern Company received the latest annual forecasts of natural gas prices during the second quarter 2020 and considered the significant decline in forecasted prices to be an indicator of potential impairment that required an interim impairment assessment. Accordingly, consistent with prior years, Southern Company evaluated the
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
recoverability of the lease receivable and the expected residual value of the generation assets under various natural gas price scenarios. Based on the current forecasts of energy prices in the years following the expiration of the existing PPA, Southern Company concluded that it is no longer probable that any of the associated rental payments will be received, because it is no longer probable the generation assets will be successfully remarketed and continue to operate after that date. During the second quarter 2020, Southern Company revised the estimated cash flows to be received under the leveraged lease to reflect this conclusion, which resulted in a full impairment of the lease investment and a pre-tax charge to earnings of $154 million ($74 million after tax).
If any future lease payment due prior to the expiration of the associated PPA is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders could represent an event of default that would give the debtholdershas the right to foreclose on, and take ownershipparticipate in a portion of PowerSouth's future incremental load growth. Implementation of the generation assets, in effect terminating the lease. As the full amountagreement is subject to certain regulatory approvals, including approvals of the lease investment has been charged against earnings as of June 30, 2020, termination would not be expected to result in additional charges. Southern Company will continue to monitorRural Utilities Service, the operational performance ofSERC Reliability Corporation, and the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments and meet its obligations associated with a future closure or retirement of the generation assets and associated properties, including the dry ash landfill.
Mississippi Power
Kemper County Energy Facility
See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.
As the mining permit holder, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities related to the lignite mine and equipment and mineral reserves located around the Kemper County energy facility site. As a result of the abandonment of the Kemper IGCC, final mine reclamation began in 2018FERC, and is expected to be substantially completed in 2020, with monitoring expected to continue through 2027. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
Dismantlement of the abandoned gasifier-related assets and site restoration activities are expected to be completed in 2025. The additional pre-tax period costs associated with dismantlement and site restoration activities, including related costs for compliance and safety, ARO accretion, and property taxes, are estimated to total $5 million for the remainder of 2020, $16 million in 2021, and $11 million to $13 million annually in 2022 through 2025. In addition, closure costs for the mine and gasifier-related assets, currently estimated at up to $6 million pre-tax (excluding dismantlement costs, net of salvage), may be incurred during the remainder of 2020.
In December 2019, Mississippi Power transferred ownership of the CO2 pipeline to an unrelated gas pipeline company, with no resulting impact on income. In conjunction with the transfer of the CO2 pipeline, the parties agreed to enter into a 15-year firm transportation agreement, which is expected to be signed by the end of 2020, providing for the conversion by the pipeline company of the CO2 pipeline to a natural gas pipeline to be used for the delivery of natural gas to Plant Ratcliffe. The agreement will be treated as a finance lease for accounting purposes upon commencement.
In 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of grants received for the Kemper County energy facility. Mississippi Power expects to close out the DOE contract in 2020. In connection with the DOE closeout discussions, in April 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of an investigation related to the Kemper County energy facility. The ultimate outcome of this matter cannot be determined at this time; however, it could have a material impact on Southern Company's and Mississippi Power's financial statements.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Plant Daniel
In conjunction with Southern Company's sale of Gulf Power, Mississippi Power and Gulf Power agreed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the restructuring, own 100% of a generating unit. On April 24, 2020, Mississippi Power and Gulf Power amended the terms of the agreement to extend the deadline from May 1, 2020 to August 1, 2020 for Mississippi Power to notify Gulf Power of which generating unit it has selected for 100% ownership. Mississippi Power and Gulf Power are continuing negotiations on a mutually acceptable revised operating agreement for Plant Daniel and, as a result, the parties have agreed not to select a specific unit on August 1, 2020. The impacts of operating the units on an individual basis continue to be evaluated by Mississippi Power and any transfer of ownership would be subject to approval by the FERC and the Mississippi PSC.March 2022. The ultimate outcome of this matter cannot be determined at this time.
ACCOUNTING POLICIES
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES in Item 7 of the Form 10-K for a complete discussion of the Registrants' critical accounting policies and estimates, as well as recently issued accounting standards.
Application of Critical Accounting Policies and Estimates
The Registrants prepare their financial statements in accordance with GAAP. Significant accounting policies are described in the notes to the financial statements in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on the Registrants' results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" in Item 7 of the Form 10-K for a complete discussion of the Registrants' critical accounting policies and estimates.
Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3 and 4
(Southern Company and Georgia Power)
InFollowing milestone extensions in January 2021, Southern Nuclear has been performing additional construction remediation work, primarily related to electrical commodity installations, necessary to ensure quality and design standards are met as system turnovers are completed to support hot functional testing and fuel load for Unit 3. Hot functional testing commenced in late April 2021 and the secondsite work plan currently targets fuel load for Unit 3 in the third quarter 2018,2021 and an in-service date of December 2021. As the site work plan includes minimal margin to these
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
milestone dates, any delay could result in an in-service date in the first quarter 2022 for Unit 3. Achievement of the extended milestone dates established in January 2021 for Unit 4, which are expected to support a regulatory-approved in-service date of November 2022, primarily depends on overall construction productivity and production levels significantly improving as well as appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, being added and maintained.
Considering the factors above, during the first quarter 2021, approximately $84 million of the construction contingency established in the fourth quarter 2020 was assigned to the base capital cost forecast for costs primarily associated with the schedule extension for Unit 3 to December 2021, construction productivity, support resources, and construction remediation work. Georgia Power increased its total capital cost forecast as of March 31, 2021 by adding $48 million to the remaining construction contingency. Georgia Power's revised its base capital cost forecast and contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 to $8.0is $8.62 billion and $0.4$0.14 billion, respectively, for a total project capital cost forecast of $8.4$8.76 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). Through the second quarter 2020, assignment of construction contingency to the base capital cost forecast exceeded the amount originally established in the second quarter 2018 by approximately $34 million. As a result, Southern Nuclear recommended establishing additional construction contingency, of which Georgia Power's share is $115 million.
After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018 and a total pre-tax charge to income of $149$48 million ($11136 million after tax) for the increase in the second quarter 2020.
In July 2020, Southern Nuclear updated its aggressive site work plan for both Unit 3total project capital cost forecast as of March 31, 2021. As and Unit 4. To meet the targets in the July 2020 aggressive site work plan, absenteeism rates must continue to normalize and overall construction productivity and production levels, including subcontractors, must significantly improve and be sustained above pre-pandemic levels. In addition, appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, must be added and maintained. While Southern Nuclear's July 2020 aggressive site work plan extended milestone dates from the February 2020 aggressive site work plan,when these amounts are spent, Georgia Power still expectsmay request the Georgia PSC to achieve the regulatory-approved in-service dates of November 2021 and November 2022evaluate those expenditures for Plant Vogtle Units 3 and 4, respectively. The continuing effects of the COVID-19 pandemic and other factors could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4.rate recovery.
The ultimate impact of these matters on the construction schedule and budget for Plant Vogtle Units 3 and 4 cannot be determined at this time. See Note (B) to the Condensed Financial Statements under ""Georgia Power – Nuclear Construction"Construction" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Recently Issued Accounting Standards
On March 12, 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (ASU 2020-04) providing temporary guidance to ease the potential burden in accounting for reference rate reform primarily resulting from the discontinuation of LIBOR, which is currently expected to occur on December 31, 2021. The amendments in ASU 2020-04 are elective and apply to all entities that have contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued. The new guidance provides the following optional expedients: (i) simplifies accounting analyses under current GAAP for contract modifications; (ii) simplifies the assessment of hedge effectiveness and allows hedging relationships affected by reference rate reform to continue; and (iii) allows a one-time election to sell or transfer debt securities classified as held to maturity that reference a rate affected by reference rate reform. An entity may elect to apply the amendments prospectively from March 12, 2020 through December 31, 2022 by accounting topic.
The Registrants currently reference LIBOR for certain debt and hedging arrangements. Contract language has been, or is expected to be, incorporated into each of these agreements to address the transition to an alternative rate for agreements that will be in place at the transition date. While existing effective hedging relationships are expected to continue, the Registrants are continuing to evaluate the provisions of ASU 2020–04 and the impacts of transitioning to an alternative rate. The ultimate outcome of the transition cannot be determined at this time, but is not expected to have a material impact on the Registrants' financial statements. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein and Note (J) to the Condensed Financial Statements under "Interest Rate Derivatives" herein for additional information.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" in Item 7 of the Form 10-K for additional information. The financial condition of each Registrant remained stable at June 30, 2020. The Registrants have maintained adequate access to capital throughout 2020, including during periods of volatility in the financial markets. This volatility began to constrain access across the Southern Company system to commercial paper during certain periods. As a precautionary measure, in the first quarter 2020, Southern Company, Georgia Power, Mississippi Power, and Southern Company Gas increased their outstanding short-term debt while also increasing cash and cash equivalents by taking actions such as entering into new bank term loans, entering into and funding new committed and uncommitted credit facilities, funding existing uncommitted credit facilities, and issuing commercial paper with longer-date maturities when available. No material changes occurred in the terms of the applicable Registrants' bank credit arrangements or their interest expense on short-term debt as a result of these actions.
The Registrants have experienced no material counterparty credit losses as a result of the volatility in the financial markets.March 31, 2021. The Registrants intend to continue to monitor their access to short-term and long-term capital markets as well as their bank credit arrangements to meet future capital and liquidity needs. The impact on future financing costs as a resultSee "Cash Requirements," "Sources of continued financial market volatility cannot be determined at this time. See "Capital, Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein and Note (K) to the Condensed Financial Statements herein for additional information.
At the end of the secondfirst quarter 2020,2021, the market price of Southern Company's common stock was $51.85$62.16 per share (based on the closing price as reported on the NYSE) and the book value was $26.20$26.90 per share, representing a market-to-book ratio of 198%231%, compared to $63.70, $26.11,$61.43, $26.48, and 244%232%, respectively, at the end of 2019.2020. Southern Company's common stock dividend for the secondfirst quarter 20202021 was $0.64 per share compared to $0.62 per share in the secondfirst quarter 2019.2020.
Cash Requirements
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements" in Item 7 of the Form 10-K for a description of the Registrants' significant cash requirements.
The Registrants' significant cash requirements include estimated capital expenditures associated with their construction programs. The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; abnormal weather; delays in construction due to judicial or regulatory action; storm impacts; and the cost of capital. The continued COVID-19 pandemic could also impair the ability to develop, construct, and operate facilities, as discussed further in Item 1A of the Form 10-K. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, expenditures associated with Southern Power's planned acquisitions may vary due to market opportunities and the execution of its growth strategy. See Note 15 to the financial statements in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements herein under "Southern Power" for additional information regarding Southern Power's plant acquisitions and construction projects.
The construction program of Georgia Power includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale and which may be subject to additional revised cost estimates during construction. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Georgia Power – Nuclear Construction" for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures.
Long-term debt maturities and the interest payable on long-term debt each represent a significant cash requirement for the Registrants. See "Financing Activities" herein for information on changes in the Registrants' long-term debt balances since December 31, 2020.
Sources of Capital
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" in Item 7 of the Form 10-K for additional information. Southern Company intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt and equity issuances in the capital markets. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. Southern Company does not expect to issue any equity in the capital markets through 2025. See Note 8 to the financial statements under "Equity Units" in Item 8 of the Form 10-K for information on stock purchase contracts associated with Southern Company's equity units.
The Subsidiary Registrants plan to obtain the funds to meet their future capital needs from sources similar to those they used in the past, which were primarily from operating cash flows, external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. In addition, Georgia Power plans to utilize borrowings from the FFB (as discussed further in Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K) and Southern Power plans to utilize tax equity partnership contributions (as discussed further herein).
The amount, type, and timing of any financings in 2021, as well as in subsequent years, will be contingent on investment opportunities and the Registrants' capital requirements and will depend upon prevailing market conditions, regulatory approvals (for certain of the Subsidiary Registrants), and other factors. See "Cash Requirements" and "Financing Activities" herein for additional information.
Southern Power utilizes tax equity partnerships as one of its financing sources, where the tax partner takes significantly all of the federal tax benefits. These tax equity partnerships are consolidated in Southern Power's financial statements and are accounted for using HLBV methodology to allocate partnership gains and losses. In
March 2021, Southern Power obtained tax equity funding for the Deuel Harvest wind facility and received proceeds of $220 million. In addition, during the first three months of 2021, Southern Power received tax equity funding totaling $17 million from existing partnerships. See Note 1 to the financial statements under "General" in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.
By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. At March 31, 2021, the amount of subsidiary retained earnings restricted to dividend totaled $1.1 billion. This restriction did not impact Southern
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Company Gas' ability to meet its cash obligations, nor does management expect such restriction to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.
Certain Registrants' current liabilities frequently exceed their current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. The Registrants generally plan to refinance long-term debt as it matures. The following table shows the amount by which current liabilities exceeded current assets at March 31, 2021 for the applicable Registrants:
| | | | | | | | | | | | | | | | | | |
At March 31, 2021 | Southern Company | Alabama Power | Georgia Power | Mississippi Power | | Southern Company Gas |
| (in millions) |
Current liabilities in excess of current assets | $ | 2,117 | | $ | 120 | | $ | 699 | | $ | 514 | | | $ | 166 | |
The Registrants believe the need for working capital can be adequately met by utilizing operating cash flows, as well as commercial paper, lines of credit, and short-term bank notes, as market conditions permit. In addition, under certain circumstances, the Subsidiary Registrants may utilize equity contributions and/or loans from Southern Company.
Bank Credit Arrangements
At March 31, 2021, the Registrants' unused committed credit arrangements with banks were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
At March 31, 2021 | Southern Company parent | Alabama Power | Georgia Power | Mississippi Power | Southern Power(a) | Southern Company Gas(b) | SEGCO | Southern Company |
| (in millions) |
Unused committed credit | $ | 1,999 | | $ | 1,328 | | $ | 1,728 | | $ | 250 | | $ | 568 | | $ | 1,745 | | $ | 30 | | $ | 7,648 | |
(a)At March 31, 2021, Southern Power also had two continuing letters of credit facilities for standby letters of credit, of which $13 million was unused. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.
(b)Includes $1.045 billion and $700 million at Southern Company Gas Capital and Nicor Gas, respectively.
Subject to applicable market conditions, the Registrants, Nicor Gas, and SEGCO expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, the Registrants, Nicor Gas, and SEGCO may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support at March 31, 2021 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, and $34 million at Mississippi Power). In addition, at March 31, 2021, Georgia Power and Mississippi Power had approximately $174 million and $50 million, respectively, of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months.
See Note 8 to the financial statements in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements herein under "Bank Credit Arrangements" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Short-term Borrowings
The Registrants, Nicor Gas, and SEGCO make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Power's subsidiaries are not issuers or obligors under its commercial paper program. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. Details of the Registrants' short-term borrowings were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Short-term Debt at March 31, 2021 | | Short-term Debt During the Period(*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) |
Southern Company | $ | 1,092 | | | 0.3 | % | | $ | 998 | | | 0.2 | % | | $ | 1,520 | |
Alabama Power | — | | | — | | | 46 | | | 0.1 | | | 200 | |
Georgia Power | 205 | | | 0.2 | | | 51 | | | 0.2 | | | 230 | |
Mississippi Power | 54 | | | 0.2 | | | 20 | | | 0.2 | | | 64 | |
Southern Power | 315 | | | 0.2 | | | 147 | | | 0.2 | | | 520 | |
Southern Company Gas: | | | | | | | | | |
Southern Company Gas Capital | $ | — | | | — | % | | $ | 221 | | | 0.2 | % | | $ | 345 | |
Nicor Gas | 497 | | | 0.5 | | | 120 | | | 0.3 | | | 520 | |
Southern Company Gas Total | $ | 497 | | | 0.5 | % | | $ | 341 | | | 0.3 | % | | |
(*)Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2021.
Analysis of Cash Flows
Net cash flows provided from (used for) operating, investing, and financing activities for the sixthree months ended June 30,March 31, 2021 and 2020 and 2019 are presented in the following table:
| | Net cash provided from (used for): | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | Net cash provided from (used for): | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) | | (in millions) |
Six Months Ended June 30, 2020 | | |
Three Months Ended March 31, 2021 | | Three Months Ended March 31, 2021 | |
Operating activities | $ | 2,847 |
| $ | 674 |
| $ | 1,124 |
| $ | 71 |
| $ | 195 |
| $ | 1,046 |
| Operating activities | $ | 1,242 | | $ | 214 | | $ | 489 | | $ | (38) | | $ | 187 | | $ | 550 | |
Investing activities | (2,655 | ) | (783 | ) | (1,659 | ) | (145 | ) | 490 |
| (570 | ) | Investing activities | (2,243) | | (466) | | (913) | | (67) | | (504) | | (308) | |
Financing activities | (285 | ) | 116 |
| 869 |
| (178 | ) | (808 | ) | (401 | ) | Financing activities | 1,734 | | 341 | | 444 | | 90 | | 478 | | 50 | |
| | |
Six Months Ended June 30, 2019 | | |
Three Months Ended March 31, 2020 | | Three Months Ended March 31, 2020 | |
Operating activities | $ | 2,513 |
| 695 |
| $ | 1,112 |
| $ | 60 |
| $ | 719 |
| $ | 931 |
| Operating activities | $ | 894 | | $ | 155 | | $ | 213 | | $ | (17) | | $ | 83 | | $ | 643 | |
Investing activities | 1,002 |
| (1,002 | ) | (1,834 | ) | (128 | ) | 254 |
| (586 | ) | Investing activities | (889) | | (424) | | (795) | | (71) | | 600 | | (193) | |
Financing activities | (3,648 | ) | 617 |
| 620 |
| (26 | ) | (784 | ) | (355 | ) | Financing activities | 185 | | 273 | | 742 | | (98) | | (632) | | (185) | |
Fluctuations in cash flows from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Company
Net cash provided from operating activities increased $0.3 billion for the sixthree months ended June 30, 2020March 31, 2021 as compared to the corresponding period in 20192020 primarily due to the timing of vendor payments and income tax payments, as well as increased fuel cost recovery, partially offset by the timing of receivable collections and customer bill credits issued in February 2020 at Georgia Power associated with Tax Reform, partially offset by Alabama Power and Georgia Power. See FUTURE EARNINGS POTENTIAL – "Tax Matters" herein and Note 2 to the financial statements under "Alabama Power" and "Georgia Power" in Item 8 of the Form 10-K for additional information.recovered natural gas costs at Southern Company Gas resulting from Winter Storm Uri.
The net cash used for investing activities for the sixthree months ended June 30, 2020March 31, 2021 was primarily duerelated to the Subsidiary Registrants' construction programs, partially offset by proceeds from the sale transactions described in Note (K) to the Condensed Financial Statements herein.programs.
The net cash used forprovided from financing activities for the sixthree months ended June 30, 2020March 31, 2021 was primarily duerelated to common stock dividend payments and net repaymentsissuances of long-term debt, short-term bank debtloans, and commercial paper, partially offset by net issuances of long-term debt.common stock dividend payments.
Alabama Power
Net cash provided from operating activities decreased $21increased $59 million for the sixthree months ended June 30, 2020March 31, 2021 as compared to the corresponding period in 20192020 primarily due to an increase in retail revenues associated with an increase in Rate RSE customer refunds,effective in January 2021 and colder weather in Alabama Power's service territory in the first quarter 2021 compared to the corresponding period in 2020, as well as the timing of fossil fuel stock and materials and supplies purchases, partially offset by lower fuel cost recovery and the timing of income tax payments. See Note 2 to the financial statements under "Alabama Power – Rate RSE" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Tax Matters" herein for additional information.receivable collections.
The net cash used for investing activities for the sixthree months ended June 30, 2020March 31, 2021 was primarily duerelated to gross property additions.
The net cash provided from financing activities for the sixthree months ended June 30, 2020March 31, 2021 was primarily duerelated to a capital contributionscontribution from Southern Company, partially offset by common stock dividend payments.
Georgia Power
Net cash provided from operating activities increased $276 million for the three months ended March 31, 2021 as compared to the corresponding period in 2020 primarily due to the timing of customer receivable collections, as well as customer bill credits issued in February 2020 associated with Tax Reform.
The net cash used for investing activities for the three months ended March 31, 2021 was primarily related to gross property additions, including a total of approximately $350 million related to the construction of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information on construction of Plant Vogtle Units 3 and 4.
The net cash provided from financing activities for the three months ended March 31, 2021 was primarily related to net issuances of senior notes, capital contributions from Southern Company, and an increase in notes payable, partially offset by common stock dividend payments.
Mississippi Power
Net cash used for operating activities increased $21 million for the three months ended March 31, 2021 as compared to the corresponding period in 2020 primarily due to the timing of ad valorem tax payments.
The net cash used for investing activities for the three months ended March 31, 2021 was primarily related to gross property additions.
The net cash provided from financing activities for the three months ended March 31, 2021 was primarily related to capital contributions from Southern Company and an increase in commercial paper borrowings, partially offset by common stock dividend payments.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
GeorgiaSouthern Power
Net cash provided from operating activities increased $12$104 million for the sixthree months ended June 30, 2020March 31, 2021 as compared to the corresponding period in 20192020 primarily due to the timing of income tax payments and increased fuel cost recovery, partially offset by customer bill credits issued in 2020 associated with Tax Reform and 2018 earnings in excess of the allowed retail ROE range. See FUTURE EARNINGS POTENTIAL – "Tax Matters" herein and Note 2 to the financial statements under "Georgia Power – Rate Plans" in Item 8 of the Form 10-K for additional information.
The net cash used for investing activities for the six months ended June 30, 2020 was primarily due to gross property additions, including approximately $690 million related to the construction of Plant Vogtle Units 3PPA counterparties and 4. See FUTURE EARNINGS POTENTIAL – "Construction Programs – Nuclear Construction" herein for additional information on construction of Plant Vogtle Units 3 and 4.
The net cash provided from financing activities for the six months ended June 30, 2020 was primarily due to issuances of senior notes, borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, capital contributions from Southern Company, and short-term borrowings, partially offset by the redemption and maturity of senior notes and common stock dividend payments.
Mississippi Power
Net cash provided from operating activities increased $11 million for the six months ended June 30, 2020 as compared to the corresponding period in 2019 primarily due to the timing of income tax payments.receipts from affiliated companies.
The net cash used for investing activities for the sixthree months ended June 30, 2020March 31, 2021 was primarily duerelated to gross property additions.
The net cash used for financing activities for the six months ended June 30, 2020 was primarily due to the redemption of senior notes and a return of capital to Southern Company, partially offset by debt issuances and capital contributions from Southern Company.
Southern Power
Net cash provided from operating activities decreased $524 million for the six months ended June 30, 2020 as compared to the corresponding period in 2019 primarily due to the delay in utilization of tax credits in the first half of 2020 compared to the utilization of $427 million in income tax credits in the first half of 2019. See FUTURE EARNINGS POTENTIAL – "Tax Matters" herein for additional information.
The net cash provided from investing activities for the six months ended June 30, 2020 was primarily due to proceeds from the disposition of Plant Mankato, partially offset by the acquisition of the Beech Ridge IIDeuel Harvest wind facility and ongoing construction activities. See Note (K) to the Condensed Financial StatementStatements under "Southern Power" herein for additional information.
The net cash used forprovided from financing activities for the sixthree months ended June 30, 2020March 31, 2021 was primarily duerelated to net repayments of short-term bank debt and commercial paper, the repaymentissuance of senior notes, at maturity, distributionsnet capital contributions from noncontrolling interests, and an increase in commercial paper borrowings, partially offset by a return of capital to non-controlling interests,Southern Company and common stock dividend payments, partially offset by contributions from non-controlling interests.payments.
Southern Company Gas
Net cash provided from operating activities increased $115decreased $93 million for the sixthree months ended June 30, 2020March 31, 2021 as compared to the corresponding period in 20192020 primarily due to natural gas cost under recovery, reflecting an increase in the timingcost of vendor paymentsgas purchased during Winter Storm Uri, and income tax payments, partially offset by the timing of customer receivable collections, partially offset by temporary LIFO liquidation, and an increase in the usetiming of stored natural gas at lower prices.vendor payments.
The net cash used for investing activities for the sixthree months ended June 30, 2020March 31, 2021 was primarily duerelated to utility capital expendituresconstruction of transportation and distribution assets recovered through base rates and infrastructure investmentsinvestment recovered through replacement programs at gas distribution operations and capital contributed to equity method investments, partially offset by proceeds from the sale of interests inoperations.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Pivotal LNG and Atlantic Coast Pipeline. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
The net cash used forprovided from financing activities for the sixthree months ended June 30, 2020March 31, 2021 was primarily duerelated to net repayments the issuance of short-term borrowings debt and capital contributions from Southern Company, partially offset by common stock dividend payments partially offset by capital contributions from Southern Company.and repayments of commercial paper borrowings.
Significant Balance Sheet Changes
Southern Company
Significant balance sheet changes for the six months ended June 30, 2020 included:
an increaseSources of $1.9 billion in total property, plant, and equipment primarily related to the Subsidiary Registrants' construction programs;
an increase of $1.9 billion in long-term debt (including amounts due within one year) related to new issuances;
a decrease of $0.9 billion in notes payable related to net repayments of short-term bank debt and commercial paper;
a decrease of $0.8 billion in assets held for sale related to the completion of Southern Power's sale of Plant Mankato and Southern Company Gas' sale of its interests in Pivotal LNG and Atlantic Coast Pipeline;
increases of $0.5 billion in both AROs and regulatory assets associated with AROs primarily related to cost estimate updates at Alabama Power for certain of its ash pond facilities; and
an increase of $0.4 billion in accumulated deferred income taxes related to the expected utilization of tax credits in 2020.
See FUTURE EARNINGS POTENTIAL – "Tax Matters" herein, "Financing Activities" herein, and Notes (A) and (K) to the Condensed Financial Statements herein for additional information.
Alabama Power
Significant balance sheet changes for the six months ended June 30, 2020 included:
an increase of $715 million in common stockholder's equity primarily due to capital contributions from Southern Company;
increases of $436 million and $472 million in AROs and regulatory assets associated with AROs, respectively, primarily related to cost estimate updates for certain ash pond facilities; and
an increase of $408 million in total property, plant, and equipment primarily related to the construction of distribution and transmission facilities and the installation of equipment to comply with environmental standards.
See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Georgia Power
Significant balance sheet changes for the six months ended June 30, 2020 included:
an increase of $1.3 billion in total property, plant, and equipment primarily related to the construction of generation, transmission, and distribution facilities, partially offset by a $149 million decrease due to a charge related to the construction of Plant Vogtle Units 3 and 4;
an increase of $1.1 billion in long-term debt (including securities due within one year) primarily due to a net increase in outstanding senior notes and borrowings from the FFB for construction of Plant Vogtle Units 3 and 4; and
an increase of $0.4 billion in common stockholder's equity primarily due to capital contributions from Southern Company.
See "Financing Activities – Georgia Power" herein and Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information.
Mississippi Power
Significant balance sheet changes for the six months ended June 30, 2020 included:
a decrease of $252 million in cash and cash equivalents and a decrease of $185 million in long-term debt (including amounts due within one year) primarily related to the repayment of senior notes at maturity;
an increase of $72 million in common stockholder's equity primarily due to a capital contribution from Southern Company;
a decrease of $42 million in deferred credits related to income taxes due to reclassifying certain amounts to other regulatory liabilities, current for the expected flowback of excess deferred income taxes; and
an increase of $38 million in total property, plant, and equipment primarily related to the installation of equipment to comply with environmental standards and the construction of transmission and distribution facilities.
See "Financing Activities – Mississippi Power" herein for additional information.
Southern Power
Significant balance sheet changes for the six months ended June 30, 2020 included:
a decrease of $618 million in assets held for sale (of which $17 million related to current assets) due to completion of the sale of Plant Mankato;
a decrease of $457 million in notes payable due to net repayments of short-term bank debt and commercial paper;
an increase of $366 million in prepaid income taxes and a decrease of $395 million in accumulated deferred income tax assets primarily related to the expected utilization of tax credits in 2020;
an increase of $364 million in property, plant, and equipment in service and a decrease of $201 million in construction work in progress primarily due to wind facilities being acquired or placed in service; and
a decrease of $299 million in securities due within one year primarily related to the maturity of senior notes.
See FUTURE EARNINGS POTENTIAL – "Tax Matters" herein, "Financing Activities – Southern Power" herein, and Note (K) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Company Gas
Significant balance sheet changes for the six months ended June 30, 2020 included:
an increase of $477 million in total property, plant, and equipment primarily due to utility capital expenditures and infrastructure investments recovered through replacement programs;
a decrease of $321 million in notes payable due to net repayments of short-term borrowings;
an increase of $263 million in common stockholder's equity primarily from net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company;
a decrease of $197 million in natural gas for sale due to the use of stored natural gas;
a decrease of $171 million in assets held for sale due to the completed sale of interests in Pivotal LNG and Atlantic Coast Pipeline;
decreases of $155 million and $158 million in energy marketing receivables and payables, respectively, due to lower natural gas prices and volumes of natural gas sold; and
a decrease of $126 million in unbilled revenues due to seasonality.
See "Financing Activities – Southern Company Gas" herein and Note (K) to the Condensed Financial Statements herein for additional information.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements" and "Contractual Obligations"Sources of Capital" in Item 7 of the Form 10-K for a descriptionadditional information. Southern Company intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt and equity issuances in the capital markets. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. Southern Company does not expect to issue any equity in the capital markets through 2025. See Note 8 to the financial statements under "Equity Units" in Item 8 of the Form 10-K for information on stock purchase contracts associated with Southern Company's equity units.
The Subsidiary Registrants plan to obtain the funds to meet their future capital needs from sources similar to those they used in the past, which were primarily from operating cash flows, external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. In addition, Georgia Power plans to utilize borrowings from the FFB (as discussed further in Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K) and Southern Power plans to utilize tax equity partnership contributions (as discussed further herein).
The amount, type, and timing of any financings in 2021, as well as in subsequent years, will be contingent on investment opportunities and the Registrants' capital requirements and contractual obligations. The following table provideswill depend upon prevailing market conditions, regulatory approvals (for certain of the applicable Registrants' maturities of long-term debt through June 30, 2021:
|
| | | | | | | | | | | | | | | |
At June 30, 2020: | Southern Company | Alabama Power | Georgia Power | Southern Power | Southern Company Gas |
| (in millions) |
Securities due within one year | $ | 1,596 |
| $ | 496 |
| $ | 536 |
| $ | 525 |
| $ | 31 |
|
Subsidiary Registrants), and other factors. See "Sources of Capital""Cash Requirements" and "Financing Activities""Financing Activities" herein for additional information.
The construction programsSouthern Power utilizes tax equity partnerships as one of its financing sources, where the tax partner takes significantly all of the federal tax benefits. These tax equity partnerships are subjectconsolidated in Southern Power's financial statements and are accounted for using HLBV methodology to periodic reviewallocate partnership gains and revision,losses. In
March 2021, Southern Power obtained tax equity funding for the Deuel Harvest wind facility and actual construction costs may vary from these estimates becausereceived proceeds of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; abnormal weather; delays in construction due to judicial or regulatory action; storm impacts; and the cost of capital. The continued COVID-19 pandemic could also impair the ability to develop, construct, and operate facilities, as discussed further in Item 1A herein.$220 million. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally,during the first three months of 2021, Southern Power's planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy.Power received tax equity funding totaling $17 million from existing partnerships. See Note 151 to the financial statements under "Southern Power""General" in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power""Southern Power" herein for additional information regarding Southern Power's plant acquisitions and construction projects.information.
The construction programBy regulation, Nicor Gas is restricted, to the extent of Georgia Power also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only within the last few years began initial operationits retained earnings balance, in the global nuclear industry at this scaleamount it can dividend or loan to affiliates and which may be subjectis not permitted to additional revised cost estimates during construction. See Note 2make money pool loans to affiliates. At March 31, 2021, the financial statements under "Georgia Power – Nuclear Construction" in Item 8amount of the Form 10-K, Note (B)subsidiary retained earnings restricted to thedividend totaled $1.1 billion. This restriction did not impact Southern
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Company Gas' ability to meet its cash obligations, nor does management expect such restriction to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.
Certain Registrants' current liabilities frequently exceed their current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. The Registrants generally plan to refinance long-term debt as it matures. The following table shows the amount by which current liabilities exceeded current assets at March 31, 2021 for the applicable Registrants:
| | | | | | | | | | | | | | | | | | |
At March 31, 2021 | Southern Company | Alabama Power | Georgia Power | Mississippi Power | | Southern Company Gas |
| (in millions) |
Current liabilities in excess of current assets | $ | 2,117 | | $ | 120 | | $ | 699 | | $ | 514 | | | $ | 166 | |
The Registrants believe the need for working capital can be adequately met by utilizing operating cash flows, as well as commercial paper, lines of credit, and short-term bank notes, as market conditions permit. In addition, under certain circumstances, the Subsidiary Registrants may utilize equity contributions and/or loans from Southern Company.
Bank Credit Arrangements
At March 31, 2021, the Registrants' unused committed credit arrangements with banks were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
At March 31, 2021 | Southern Company parent | Alabama Power | Georgia Power | Mississippi Power | Southern Power(a) | Southern Company Gas(b) | SEGCO | Southern Company |
| (in millions) |
Unused committed credit | $ | 1,999 | | $ | 1,328 | | $ | 1,728 | | $ | 250 | | $ | 568 | | $ | 1,745 | | $ | 30 | | $ | 7,648 | |
Condensed Financial Statements under "(a)GeorgiaAt March 31, 2021, Southern Power – Nuclear Construction" herein, and Item 1A herein also had two continuing letters of credit facilities for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures.standby letters of credit, of which $13 million was unused. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.
As a result(b)Includes $1.045 billion and $700 million at Southern Company Gas Capital and Nicor Gas, respectively.
Subject to applicable market conditions, the Registrants, Nicor Gas, and SEGCO expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, the Registrants, Nicor Gas, and SEGCO may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the second quarter 2020 increase in Alabama Power's AROs discussed under FUTURE EARNINGS POTENTIAL – "Environmental Matters" herein, Alabama Power's costs through 2024 associatedunused credit with closure and monitoringbanks is allocated to provide liquidity support to the revenue bonds of ash ponds and landfills in accordance with the CCR Ruletraditional electric operating companies and the related state rulecommercial paper programs of the Registrants, Nicor Gas, and SEGCO. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support at March 31, 2021 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, and $34 million at Mississippi Power). In addition, at March 31, 2021, Georgia Power and Mississippi Power had approximately $174 million and $50 million, respectively, of fixed rate revenue bonds outstanding that are currently estimatedrequired to be approximately $263 million for 2020, $247 million for 2021, $301 million for 2022, $330 million for 2023, and $326 million for 2024. These costs are reflected in Alabama Power's ARO liabilities and are based on closure-in-place for all of its ash ponds. These anticipated costs are likelyremarketed within the next 12 months.
See Note 8 to change, and could change materially, as assumptions and details pertaining to closure are refined and compliance activities continue. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals"the financial statements in Item 8 of the Form 10-K and Note (A)(F) to the Condensed Financial Statements herein under "Bank Credit Arrangements" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Short-term Borrowings
The Registrants, Nicor Gas, and SEGCO make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Power's subsidiaries are not issuers or obligors under its commercial paper program. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. Details of the Registrants' short-term borrowings were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Short-term Debt at March 31, 2021 | | Short-term Debt During the Period(*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) |
Southern Company | $ | 1,092 | | | 0.3 | % | | $ | 998 | | | 0.2 | % | | $ | 1,520 | |
Alabama Power | — | | | — | | | 46 | | | 0.1 | | | 200 | |
Georgia Power | 205 | | | 0.2 | | | 51 | | | 0.2 | | | 230 | |
Mississippi Power | 54 | | | 0.2 | | | 20 | | | 0.2 | | | 64 | |
Southern Power | 315 | | | 0.2 | | | 147 | | | 0.2 | | | 520 | |
Southern Company Gas: | | | | | | | | | |
Southern Company Gas Capital | $ | — | | | — | % | | $ | 221 | | | 0.2 | % | | $ | 345 | |
Nicor Gas | 497 | | | 0.5 | | | 120 | | | 0.3 | | | 520 | |
Southern Company Gas Total | $ | 497 | | | 0.5 | % | | $ | 341 | | | 0.3 | % | | |
(*)Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2021.
Analysis of Cash Flows
Net cash flows provided from (used for) operating, investing, and financing activities for the three months ended March 31, 2021 and 2020 are presented in the following table:
| | | | | | | | | | | | | | | | | | | | |
Net cash provided from (used for): | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
Three Months Ended March 31, 2021 | | | | | | |
Operating activities | $ | 1,242 | | $ | 214 | | $ | 489 | | $ | (38) | | $ | 187 | | $ | 550 | |
Investing activities | (2,243) | | (466) | | (913) | | (67) | | (504) | | (308) | |
Financing activities | 1,734 | | 341 | | 444 | | 90 | | 478 | | 50 | |
| | | | | | |
Three Months Ended March 31, 2020 | | | | | | |
Operating activities | $ | 894 | | $ | 155 | | $ | 213 | | $ | (17) | | $ | 83 | | $ | 643 | |
Investing activities | (889) | | (424) | | (795) | | (71) | | 600 | | (193) | |
Financing activities | 185 | | 273 | | 742 | | (98) | | (632) | | (185) | |
Fluctuations in cash flows from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Company
Net cash provided from operating activities increased $0.3 billion for the three months ended March 31, 2021 as compared to the corresponding period in 2020 primarily due to the timing of vendor payments and customer bill credits issued in February 2020 at Georgia Power associated with Tax Reform, partially offset by under recovered natural gas costs at Southern Company Gas resulting from Winter Storm Uri.
The net cash used for investing activities for the three months ended March 31, 2021 was primarily related to the Subsidiary Registrants' construction programs.
The net cash provided from financing activities for the three months ended March 31, 2021 was primarily related to net issuances of long-term debt, short-term bank loans, and commercial paper, partially offset by common stock dividend payments.
Alabama Power
Net cash provided from operating activities increased $59 million for the three months ended March 31, 2021 as compared to the corresponding period in 2020 primarily due to an increase in retail revenues associated with an increase in Rate RSE effective in January 2021 and colder weather in Alabama Power's service territory in the first quarter 2021 compared to the corresponding period in 2020, as well as the timing of fossil fuel stock and materials and supplies purchases, partially offset by lower fuel cost recovery and the timing of receivable collections.
The net cash used for investing activities for the three months ended March 31, 2021 was primarily related to gross property additions.
The net cash provided from financing activities for the three months ended March 31, 2021 was primarily related to a capital contribution from Southern Company, partially offset by common stock dividend payments.
Georgia Power
Net cash provided from operating activities increased $276 million for the three months ended March 31, 2021 as compared to the corresponding period in 2020 primarily due to the timing of customer receivable collections, as well as customer bill credits issued in February 2020 associated with Tax Reform.
The net cash used for investing activities for the three months ended March 31, 2021 was primarily related to gross property additions, including a total of approximately $350 million related to the construction of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information on construction of Plant Vogtle Units 3 and 4.
The net cash provided from financing activities for the three months ended March 31, 2021 was primarily related to net issuances of senior notes, capital contributions from Southern Company, and an increase in notes payable, partially offset by common stock dividend payments.
Mississippi Power
Net cash used for operating activities increased $21 million for the three months ended March 31, 2021 as compared to the corresponding period in 2020 primarily due to the timing of ad valorem tax payments.
The net cash used for investing activities for the three months ended March 31, 2021 was primarily related to gross property additions.
The net cash provided from financing activities for the three months ended March 31, 2021 was primarily related to capital contributions from Southern Company and an increase in commercial paper borrowings, partially offset by common stock dividend payments.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Power
Net cash provided from operating activities increased $104 million for the three months ended March 31, 2021 as compared to the corresponding period in 2020 primarily due to the timing of payments to PPA counterparties and the timing of receipts from affiliated companies.
The net cash used for investing activities for the three months ended March 31, 2021 was primarily related to the acquisition of the Deuel Harvest wind facility and ongoing construction activities. See Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.
The net cash provided from financing activities for the three months ended March 31, 2021 was primarily related to the issuance of senior notes, net capital contributions from noncontrolling interests, and an increase in commercial paper borrowings, partially offset by a return of capital to Southern Company and common stock dividend payments.
Southern Company Gas
Net cash provided from operating activities decreased $93 million for the three months ended March 31, 2021 as compared to the corresponding period in 2020 primarily due to natural gas cost under recovery, reflecting an increase in the cost of gas purchased during Winter Storm Uri, and the timing of customer receivable collections, partially offset by temporary LIFO liquidation, and the timing of vendor payments.
The net cash used for investing activities for the three months ended March 31, 2021 was primarily related to construction of transportation and distribution assets recovered through base rates and infrastructure investment recovered through replacement programs at gas distribution operations.
The net cash provided from financing activities for the three months ended March 31, 2021 was primarily related to the issuance of short-term debt and capital contributions from Southern Company, partially offset by common stock dividend payments and repayments of commercial paper borrowings.
Sources of Capital
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" in Item 7 of the Form 10-K for additional information. Southern Company intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt and equity issuances in the capital markets. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. Southern Company does not expect to issue any equity in the capital markets through 2024.2025. See Note 8 to the financial statements under "Equity Units" in Item 8 of the Form 10-K for information on stock purchase contracts associated with Southern Company's equity units.
The Subsidiary Registrants plan to obtain the funds to meet their future capital needs from sources similar to those they used in the past, which were primarily from operating cash flows, external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. In addition, Georgia Power plans to utilize borrowings from the FFB (as discussed further in Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K) and Southern Power plans to utilize tax equity partnership contributions (as discussed further herein).
The traditional electric operating companies and the natural gas distribution utilities have experienced a reduction in operating cash flows as a result of the temporary suspension of disconnections for non-payment by customers resulting from the COVID-19 pandemic and the related overall economic contraction. The U.S. House of Representatives has passed the Heroes Act, which would prohibit creditors, including utilities, from collecting consumer debts that are or become past-due, imposing late fees, or disconnecting customers for nonpayment. If the Heroes Act becomes law, its restrictions would apply until 120 days after the end of the presidential declared emergency related to the COVID-19 pandemic. While the reduction in operating cash flows is expected to continue while disconnections for non-payment are suspended, the ultimate extent of the negative impact on the Registrants' liquidity depends on the duration of the COVID-19 pandemic and the timing of economic recovery and cannot be determined at this time. The Registrants intend to continue to monitor their access to short-term and long-term capital markets as well as their bank credit arrangements to meet future capital and liquidity needs. See Note (B) to the Condensed Financial Statements herein for information regarding suspended disconnections for non-payment by the traditional electric operating companies and the natural gas distribution utilities.
The amount, type, and timing of any financings in 2020,2021, as well as in subsequent years, will be contingent on investment opportunities and the Registrants' capital requirements and will depend upon prevailing market conditions, regulatory approvals (for certain of the Subsidiary Registrants), and other factors. See "Capital Requirements"Cash Requirements" and Contractual Obligations""Financing Activities" herein for additional information. Also see "Overview" herein for information on volatility in the financial markets that has occurred at certain periods during 2020 as a result of the COVID-19 pandemic.
Southern Power utilizes tax equity partnerships as one of its financing sources, where the tax partner takes significantly all of the federal tax benefits. These tax equity partnerships are consolidated in Southern Power's financial statements and are accounted for using HLBV methodology to allocate partnership gains and losses. In June 2020,
March 2021, Southern Power obtained tax equity funding for the ReadingDeuel Harvest wind projectfacility and received proceeds of $156$220 million. In addition, during the first sixthree months of 2020,2021, Southern Power received tax equity funding totaling $16
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
$17 million from existing partnerships. See Note 1 to the financial statements under "General" in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.
By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. At June 30, 2020,March 31, 2021, the amount of subsidiary retained earnings restricted to dividend totaled $1.1 billion. This restriction did not impact Southern
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Company Gas' ability to meet its cash obligations, nor does management expect such restriction to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" in Item 7 of the Form 10-K for additional information.
TheCertain Registrants' current liabilities frequently exceed their current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. The Registrants generally plan to refinance long-term debt as it matures. The following table shows the amount by which current liabilities exceeded current assets at June 30, 2020March 31, 2021 for the applicable Registrants:
| | At June 30, 2020 | Southern Company | Georgia Power | Mississippi Power | Southern Company Gas | |
At March 31, 2021 | | At March 31, 2021 | Southern Company | Alabama Power | Georgia Power | Mississippi Power | | Southern Company Gas |
| (in millions) | | (in millions) |
Current liabilities in excess of current assets | $ | 265 |
| $ | 1,132 |
| $ | 70 |
| $ | 209 |
| Current liabilities in excess of current assets | $ | 2,117 | | $ | 120 | | $ | 699 | | $ | 514 | | | $ | 166 | |
The Registrants believe the need for working capital can be adequately met by utilizing operating cash flows, as well as commercial paper, lines of credit, and short-term bank notes, as market conditions permit. In addition, under certain circumstances, the Subsidiary Registrants may utilize equity contributions and/or loans from Southern Company.
Bank Credit Arrangements
At June 30, 2020,March 31, 2021, the Registrants' unused committed credit arrangements with banks were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
At March 31, 2021 | Southern Company parent | Alabama Power | Georgia Power | Mississippi Power | Southern Power(a) | Southern Company Gas(b) | SEGCO | Southern Company |
| (in millions) |
Unused committed credit | $ | 1,999 | | $ | 1,328 | | $ | 1,728 | | $ | 250 | | $ | 568 | | $ | 1,745 | | $ | 30 | | $ | 7,648 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
At June 30, 2020 | Southern Company parent | Alabama Power | Georgia Power | Mississippi Power | Southern Power(a) | Southern Company Gas(b) | SEGCO | Southern Company |
| (in millions) |
Unused committed credit | $ | 1,999 |
| $ | 1,328 |
| $ | 1,733 |
| $ | 250 |
| $ | 590 |
| $ | 1,745 |
| $ | 30 |
| $ | 7,675 |
|
(a)At March 31, 2021, Southern Power also had two continuing letters of credit facilities for standby letters of credit, of which $13 million was unused. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities. | |
(a) | At June 30, 2020, Southern Power also had two continuing letters of credit facilities for standby letters of credit, of which $79 million was unused. Southern Power's subsidiaries are not parties to its bank credit arrangement or to the letter of credit facilities. |
| |
(b) | Includes $1.245 billion and $500 million at Southern Company Gas Capital and Nicor Gas, respectively. |
(b)Includes $1.045 billion and $700 million at Southern Company Gas Capital and Nicor Gas, respectively.
Subject to applicable market conditions, the Registrants, Nicor Gas, and SEGCO expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, the Registrants, Nicor Gas, and SEGCO may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support at June 30, 2020March 31, 2021 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, and $34 million at Mississippi Power). In addition, at June 30, 2020,March 31, 2021, Georgia Power and Mississippi Power had approximately $257$174 million and $50 million, respectively, of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months.
See Note 8 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements herein under "Bank"Bank Credit Arrangements" hereinArrangements" for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Short-term Borrowings
The Registrants, Nicor Gas, and SEGCO make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Power's subsidiaries are not issuers or obligors under its commercial paper program. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. Details of the Registrants' short-term borrowings were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Short-term Debt at March 31, 2021 | | Short-term Debt During the Period(*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) |
Southern Company | $ | 1,092 | | | 0.3 | % | | $ | 998 | | | 0.2 | % | | $ | 1,520 | |
Alabama Power | — | | | — | | | 46 | | | 0.1 | | | 200 | |
Georgia Power | 205 | | | 0.2 | | | 51 | | | 0.2 | | | 230 | |
Mississippi Power | 54 | | | 0.2 | | | 20 | | | 0.2 | | | 64 | |
Southern Power | 315 | | | 0.2 | | | 147 | | | 0.2 | | | 520 | |
Southern Company Gas: | | | | | | | | | |
Southern Company Gas Capital | $ | — | | | — | % | | $ | 221 | | | 0.2 | % | | $ | 345 | |
Nicor Gas | 497 | | | 0.5 | | | 120 | | | 0.3 | | | 520 | |
Southern Company Gas Total | $ | 497 | | | 0.5 | % | | $ | 341 | | | 0.3 | % | | |
(*)Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2021.
Analysis of Cash Flows
Net cash flows provided from (used for) operating, investing, and financing activities for the three months ended March 31, 2021 and 2020 are presented in the following table:
| | | | | | | | | | | | | | | | | | | | |
Net cash provided from (used for): | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas |
| (in millions) |
Three Months Ended March 31, 2021 | | | | | | |
Operating activities | $ | 1,242 | | $ | 214 | | $ | 489 | | $ | (38) | | $ | 187 | | $ | 550 | |
Investing activities | (2,243) | | (466) | | (913) | | (67) | | (504) | | (308) | |
Financing activities | 1,734 | | 341 | | 444 | | 90 | | 478 | | 50 | |
| | | | | | |
Three Months Ended March 31, 2020 | | | | | | |
Operating activities | $ | 894 | | $ | 155 | | $ | 213 | | $ | (17) | | $ | 83 | | $ | 643 | |
Investing activities | (889) | | (424) | | (795) | | (71) | | 600 | | (193) | |
Financing activities | 185 | | 273 | | 742 | | (98) | | (632) | | (185) | |
Fluctuations in cash flows from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
|
| | | | | | | | | | | | | | | | | |
| Short-term Debt at June 30, 2020 | | Short-term Debt During the Period(*) |
| Amount Outstanding | | Weighted Average Interest Rate | | Average Amount Outstanding | | Weighted Average Interest Rate | | Maximum Amount Outstanding |
| (in millions) | | | | (in millions) | | | | (in millions) |
Southern Company | $ | 1,185 |
| | 1.2 | % | | $ | 1,317 |
| | 1.6 | % | | $ | 1,738 |
|
Alabama Power | — |
| | — |
| | 42 |
| | 1.3 |
| | 105 |
|
Georgia Power | 465 |
| | 1.5 |
| | 443 |
| | 1.6 |
| | 478 |
|
Mississippi Power | 4 |
| | 0.3 |
| | 26 |
| | 1.9 |
| | 40 |
|
Southern Power | 92 |
| | 0.3 |
| | 68 |
| | 0.5 |
| | 252 |
|
Southern Company Gas: | | | | | | | | | |
Southern Company Gas Capital | $ | 290 |
| | 1.1 | % | | $ | 332 |
| | 1.6 | % | | $ | 482 |
|
Nicor Gas | 39 |
| | 0.2 |
| | 25 |
| | 1.4 |
| | 104 |
|
Southern Company Gas Total | $ | 329 |
| | 1.0 | % | | $ | 357 |
| | 1.6 | % | | |
| |
(*) | Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2020. |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Company
Net cash provided from operating activities increased $0.3 billion for the three months ended March 31, 2021 as compared to the corresponding period in 2020 primarily due to the timing of vendor payments and customer bill credits issued in February 2020 at Georgia Power associated with Tax Reform, partially offset by under recovered natural gas costs at Southern Company Gas resulting from Winter Storm Uri.
The net cash used for investing activities for the three months ended March 31, 2021 was primarily related to the Subsidiary Registrants' construction programs.
The net cash provided from financing activities for the three months ended March 31, 2021 was primarily related to net issuances of long-term debt, short-term bank loans, and commercial paper, partially offset by common stock dividend payments.
Alabama Power
Net cash provided from operating activities increased $59 million for the three months ended March 31, 2021 as compared to the corresponding period in 2020 primarily due to an increase in retail revenues associated with an increase in Rate RSE effective in January 2021 and colder weather in Alabama Power's service territory in the first quarter 2021 compared to the corresponding period in 2020, as well as the timing of fossil fuel stock and materials and supplies purchases, partially offset by lower fuel cost recovery and the timing of receivable collections.
The net cash used for investing activities for the three months ended March 31, 2021 was primarily related to gross property additions.
The net cash provided from financing activities for the three months ended March 31, 2021 was primarily related to a capital contribution from Southern Company, partially offset by common stock dividend payments.
Georgia Power
Net cash provided from operating activities increased $276 million for the three months ended March 31, 2021 as compared to the corresponding period in 2020 primarily due to the timing of customer receivable collections, as well as customer bill credits issued in February 2020 associated with Tax Reform.
The net cash used for investing activities for the three months ended March 31, 2021 was primarily related to gross property additions, including a total of approximately $350 million related to the construction of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information on construction of Plant Vogtle Units 3 and 4.
The net cash provided from financing activities for the three months ended March 31, 2021 was primarily related to net issuances of senior notes, capital contributions from Southern Company, and an increase in notes payable, partially offset by common stock dividend payments.
Mississippi Power
Net cash used for operating activities increased $21 million for the three months ended March 31, 2021 as compared to the corresponding period in 2020 primarily due to the timing of ad valorem tax payments.
The net cash used for investing activities for the three months ended March 31, 2021 was primarily related to gross property additions.
The net cash provided from financing activities for the three months ended March 31, 2021 was primarily related to capital contributions from Southern Company and an increase in commercial paper borrowings, partially offset by common stock dividend payments.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Power
Net cash provided from operating activities increased $104 million for the three months ended March 31, 2021 as compared to the corresponding period in 2020 primarily due to the timing of payments to PPA counterparties and the timing of receipts from affiliated companies.
The net cash used for investing activities for the three months ended March 31, 2021 was primarily related to the acquisition of the Deuel Harvest wind facility and ongoing construction activities. See Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.
The net cash provided from financing activities for the three months ended March 31, 2021 was primarily related to the issuance of senior notes, net capital contributions from noncontrolling interests, and an increase in commercial paper borrowings, partially offset by a return of capital to Southern Company and common stock dividend payments.
Southern Company Gas
Net cash provided from operating activities decreased $93 million for the three months ended March 31, 2021 as compared to the corresponding period in 2020 primarily due to natural gas cost under recovery, reflecting an increase in the cost of gas purchased during Winter Storm Uri, and the timing of customer receivable collections, partially offset by temporary LIFO liquidation, and the timing of vendor payments.
The net cash used for investing activities for the three months ended March 31, 2021 was primarily related to construction of transportation and distribution assets recovered through base rates and infrastructure investment recovered through replacement programs at gas distribution operations.
The net cash provided from financing activities for the three months ended March 31, 2021 was primarily related to the issuance of short-term debt and capital contributions from Southern Company, partially offset by common stock dividend payments and repayments of commercial paper borrowings.
Significant Balance Sheet Changes
Southern Company
Significant balance sheet changes for the three months ended March 31, 2021 included:
•an increase of $1.7 billion in long-term debt (including amounts due within one year) related to new issuances;
•an increase of $1.4 billion in total property, plant, and equipment primarily related to the Subsidiary Registrants' construction programs, as well as Southern Power's acquisition of the Deuel Harvest wind facility;
•an increase of $0.8 billion in total stockholders' equity primarily related to net income, partially offset by common stock dividend payments;
•an increase of $0.7 billion in accumulated deferred income taxes primarily related to the expected utilization of tax credits in 2021;
•an increase of $0.7 billion in cash and cash equivalents, as discussed further under "Analysis of Cash Flows – Southern Company" herein;
•an increase of $0.5 billion in natural gas cost under recovery, which was impacted by an increase in Southern Company Gas' cost of gas purchased during Winter Storm Uri; and
•an increase of $0.5 billion in notes payable related to net issuances of short-term bank debt and commercial paper.
See "Financing Activities" herein and Notes (B) and (K) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Alabama Power
Significant balance sheet changes for the three months ended March 31, 2021 included:
•an increase of $716 million in common stockholder's equity primarily due to capital contributions from Southern Company;
•an increase of $269 million in total property, plant, and equipment primarily related to construction of distribution and transmission facilities and the installation of equipment to comply with environmental standards; and
•a decrease of $153 million in other accounts payable primarily due to the timing of vendor payments.
Georgia Power
Significant balance sheet changes for the three months ended March 31, 2021 included:
•an increase of $547 million in total property, plant, and equipment primarily related to the construction of generation, transmission, and distribution facilities, including $291 million for Plant Vogtle Units 3 and 4 (net of a pre-tax charge of $48 million for an estimated probable loss);
•an increase of $395 million in long-term debt (including securities due within one year) primarily due to a net increase in outstanding senior notes; and
•an increase of $273 million in common stockholder's equity primarily due to capital contributions from Southern Company.
See "Financing Activities – Georgia Power" herein and Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information.
Mississippi Power
Significant balance sheet changes for the three months ended March 31, 2021 included:
•an increase of $106 million in common stockholder's equity primarily from capital contributions from Southern Company and
•a decrease of $75 million in accrued taxes primarily due to the payment of ad valorem taxes.
Southern Power
Significant balance sheet changes for the three months ended March 31, 2021 included:
•an increase of $409 million in property, plant, and equipment in service primarily due to the acquisition of the Deuel Harvest wind facility;
•an increase of $357 million in prepaid income taxes, a decrease of $262 million in accumulated deferred income tax assets, and a $107 million increase in accumulated deferred income tax liabilities primarily related to the expected utilization of ITCs in 2021; and
•an increase of $337 million in long-term debt primarily related to the issuance of senior notes.
See "Financing Activities – Southern Power" herein and Note (K) to the Condensed Financial Statements herein for additional information.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Company Gas
Significant balance sheet changes for the three months ended March 31, 2021 included:
•increases of $487 million in natural gas cost under recovery, $171 million in other regulatory assets, deferred, and $162 million in accumulated deferred income taxes, all primarily related to natural gas cost under recovery, reflecting an increase in the cost of gas purchased during Winter Storm Uri;
•an increase of $327 million in common stockholder's equity primarily related to net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company;
•an increase of $292 million in cash and cash equivalents, as discussed further under "Analysis of Cash Flows – Southern Company Gas" herein;
•a decrease of $263 million in natural gas for sale due to higher volumes of natural gas sold;
•an increase of $194 million in temporary LIFO liquidation due to higher natural gas prices during Winter Storm Uri;
•an increase of $173 million in notes payable due to issuances of short-term borrowings; and
•an increase of $171 million in total property, plant, and equipment primarily related to the construction of transportation and distribution assets recovered through base rates and infrastructure investment recovered through replacement programs.
See "Financing Activities – Southern Company Gas" herein and Note (B) to the Condensed Financial Statements herein for additional information.
Financing Activities
The following table outlines the Registrants' long-term debt financing activities for the first sixthree months of 2020:2021:
| | | | | | | | | | | | | | | | | | | | | | | |
| Senior Notes | | | | | | |
Company | Issuances | | Maturities, Redemptions, and Repurchases | | | | | | | | Other Long-Term Debt Redemptions and Maturities(*) |
| (in millions) |
Southern Company parent | $ | 1,000 | | | $ | — | | | | | | | | | $ | — | |
| | | | | | | | | | | |
Georgia Power | 750 | | | 325 | | | | | | | | | 26 | |
| | | | | | | | | | | |
Southern Power | 400 | | | — | | | | | | | | | — | |
Southern Company Gas | — | | | — | | | | | | | | | 30 | |
Other | — | | | — | | | | | | | | | 3 | |
| | | | | | | | | | | |
Southern Company | $ | 2,150 | | | $ | 325 | | | | | | | | | $ | 59 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Senior Notes | | Revenue Bonds | | Other Long-Term Debt |
Company | Issuances | | Maturities, Redemptions, and Repurchases | | Issuances/ Remarketings | | Maturities, Redemptions, and Repurchases | | Issuances | | Redemptions and Maturities(*) |
| (in millions) |
Southern Company parent | $ | 1,000 |
| | $ | 600 |
| | $ | — |
| | $ | — |
| | $ | 1,000 |
| | $ | — |
|
Alabama Power | — |
| | — |
| | 87 |
| | 87 |
| | — |
| | — |
|
Georgia Power | 1,500 |
| | 950 |
| | 53 |
| | 148 |
| | 519 |
| | 35 |
|
Mississippi Power | — |
| | 275 |
| | 34 |
| | 41 |
| | 100 |
| | — |
|
Southern Power | — |
| | 300 |
| | — |
| | — |
| | — |
| | — |
|
Other | — |
| | — |
| | — |
| | — |
| | — |
| | 8 |
|
Southern Company | $ | 2,500 |
| | $ | 2,125 |
| | $ | 174 |
| | $ | 276 |
| | $ | 1,619 |
| | $ | 43 |
|
| |
(*) | Includes reductions in finance lease obligations resulting from cash payments under finance leases and, for Georgia Power, principal amortization payments for FFB borrowings. |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Except as otherwise described herein, the Registrants used the proceeds of debt issuances for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including working capital. The Subsidiary Registrants also used the proceeds for their construction programs.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Registrants plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
Southern Company
During the first sixthree months of 2020,2021, Southern Company issued approximately 2.92.2 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $59$14 million.
In January 2020, Southern Company issued $1.0 billion aggregate principal amount of Series 2020A 4.95% Junior Subordinated Notes due January 30, 2080.
In March 2020,2021, Southern Company borrowed $250$25 million pursuant to a short-term uncommitted bank credit arrangement, bearing interest at a rate agreed upon by Southern Company and the bank from time to time and payable on demand, following specified notice by the bank. In April 2020, Southern Companywhich it repaid $50 million of the $250 million borrowed.
Also in March 2020, Southern Company entered into a $75 million short-term floating rate bank loan bearing interest based on one-month LIBOR.2021.
In April 2020, Southern Company issued $1.0 billion aggregate principal amount of Series 2020A 3.70% Senior Notes due April 30, 2030.127
In May 2020, Southern Company redeemed all $600 million aggregate principal amount of its Series 2015A 2.750% Senior Notes due June 15, 2020.
Alabama Power
In March 2020, Alabama Power purchased and held approximately $87 million aggregate principal amount of The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2007-A, which were remarketed to the public in June 2020.
Georgia Power
In January 2020, Georgia Power issued $700 million aggregate principal amount of Series 2020A 2.10% Senior Notes due July 30, 2023, $500 million aggregate principal amount of Series 2020B 3.70% Senior Notes due January 30, 2050, and an additional $300 million aggregate principal amount of Series 2019B 2.65% Senior Notes due September 15, 2029.
In February 2020, Georgia Power redeemed all $500 million aggregate principal amount of its Series 2017C 2.00% Senior Notes due September 8, 2020.
Also in February 2020, Georgia Power purchased and held approximately $28 million, $49 million, and $18 million aggregate principal amounts of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), Second Series 2006, First Series 2012, and First Series 2013, respectively, which may be remarketed to the public at a later date.
In March 2020, Georgia Power repaid at maturity $450 million aggregate principal amount of its Series 2017A 2.00% Senior Notes.
Also in March 2020, Georgia Power purchased and subsequently remarketed to the public approximately $53 million of pollution control revenue bonds.
Also in March 2020, Georgia Power extended one of its $125 million short-term floating rate bank loans to a long-term term loan, which matures in June 2021, and borrowed $200 million pursuant to a $250 million short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
In February 2021, Southern Company issued $600 million aggregate principal amount of Series 2021A 0.60% Senior Notes due February 26, 2024 and $400 million aggregate principal amount of Series 2021B 1.75% Senior Notes due March 15, 2028.
from time to time and is payable on demand, following specified notice by the bank. In April 2020, Georgia
Alabama Power borrowed the remaining $50 million pursuant to this bank credit arrangement.
In June 2020, GeorgiaMarch 2021, Alabama Power extended the maturity dates from March 2021 to March 2026 on its other $125 million short-term floating ratethree bank term loan which matures in December 2020.
Also in June 2020, Georgia Power made additional borrowings under the FFB Credit Facilities inagreements with an aggregate principal amount of $519$45 million, at anbearing interest ratebased on three-month LIBOR.
Georgia Power
In February 2021, Georgia Power issued $750 million aggregate principal amount of 1.652% throughSeries 2021A 3.25% Senior Notes due March 15, 2051. An amount equal to the finalnet proceeds of the senior notes is being allocated to finance or refinance, in whole or in part, one or more renewable energy projects and/or expenditures and programs related to enabling opportunities for diverse and small businesses/suppliers.
In March 2021, Georgia Power redeemed all $325 million aggregate principal amount of its Series 2016B 2.40% Senior Notes due April 1, 2021.
Also in March 2021, Georgia Power extended the maturity date of February 20, 2044. The proceeds were usedits $125 million term loan from June 2021 to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4. June 2022.
During the sixthree months ended June 30, 2020,March 31, 2021, Georgia Power made principal amortization payments of $32$25 million under the FFB Credit Facilities. At June 30, 2020,March 31, 2021, the outstanding principal balance under the FFB Credit Facilities was $4.3$4.6 billion. See Note 8 to the financial statements under "Long-Term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information.
MississippiSouthern Power
In January 2021, Southern Power issued $400 million aggregate principal amount of Series 2021A 0.90% Senior Notes due January 15, 2026. An amount equal to the net proceeds of the senior notes is being allocated to finance or refinance, in whole or in part, one or more renewable energy projects.
Southern Company Gas
In February 2020, Mississippi Power2021, Atlanta Gas Light repaid at maturity $30 million aggregate principal amount of 9.1% medium-term notes.
In March 2021, Nicor Gas entered into $60 million and $15 millionthree short-term floating rate bank term loans which mature in December 2021 and January 2022, respectively,an aggregate principal amount of $300 million, each bearing interest based on one-month LIBOR.
In March 2020, Mississippi Power entered into a $125 million revolving credit arrangement that matures in March 2023 and borrowed $40 million (short term) and $25 million (long term) pursuant to the arrangement, each bearing interest based on one-month LIBOR. In May 2020, Mississippi Power repaid the $40 million short-term portion.
In March 2020, Mississippi Power repaid at maturity the remaining $275 million aggregate principal amount of its Series 2018A Floating Rate Senior Notes.
In April 2020, Mississippi Power purchased and held approximately $11 million, $14 million, and $9 million aggregate principal amount of Mississippi Business Finance Corporation Solid Waste Disposal Facilities Revenue Bonds, Series 1995 (Mississippi Power Company Project), Solid Waste Disposal Facilities Revenue Refunding Bonds, Series 1998 (Mississippi Power Company Project), and Revenue Bonds, Series 1999 (Mississippi Power Company Project), respectively, which were remarketed to the public in May 2020.
Also in April 2020, Mississippi Power redeemed approximately $7 million aggregate principal amount of The Industrial Development Board of the City of Eutaw, Alabama Pollution Control Revenue Refunding Bonds, Series 1992 (Mississippi Power Greene County Plant Project) due December 1, 2020.
Southern Power
In February 2020, Southern Power repaid its $100 million short-term floating rate bank loan entered into in December 2019.
In June 2020, Southern Power repaid at maturity $300 million aggregate principal amount of its Series 2015B 2.375% Senior Notes.
Southern Company Gas
In March 2020, Southern Company Gas Capital, as borrower, and Southern Company Gas, as guarantor, entered into a $150 million short-term floating rate bank loan bearing interest based on one-month LIBOR.
Also in March 2020, Southern Company Gas Capital borrowed approximately $95 million pursuant to a short-term uncommitted bank credit arrangement, guaranteed by Southern Company Gas, bearing interest at a rate agreed upon by Southern Company Gas Capital and the bank from time to time and payable on demand, following specified notice by the bank.
Credit Rating Risk
At June 30, 2020,March 31, 2021, the Registrants did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiariesRegistrants to BBB and/or Baa2 or below. These contracts are primarily for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and, for Georgia Power, construction of new generation at Plant Vogtle Units 3 and 4.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
The maximum potential collateral requirements under these contracts at June 30, 2020March 31, 2021 were as follows:
| | | | | | | | | | | | | | | | | | | | |
Credit Ratings | Southern Company(*) | Alabama Power | Georgia Power | Mississippi Power | Southern Power(*) | Southern Company Gas |
| (in millions) |
At BBB and/or Baa2 | $ | 38 | | $ | 1 | | $ | — | | $ | — | | $ | 37 | | $ | — | |
At BBB- and/or Baa3 | 433 | | 2 | | 61 | | 1 | | 371 | | — | |
At BB+ and/or Ba1 or below | 1,938 | | 366 | | 965 | | 308 | | 1,210 | | 10 | |
|
| | | | | | | | | | | | | | | | | | |
Credit Ratings | Southern Company(*) | Alabama Power | Georgia Power | Mississippi Power | Southern Power(*) | Southern Company Gas |
| (in millions) |
At BBB and/or Baa2 | $ | 36 |
| $ | 1 |
| $ | — |
| $ | — |
| $ | 35 |
| $ | — |
|
At BBB- and/or Baa3 | 428 |
| 2 |
| 61 |
| 1 |
| 366 |
| — |
|
At BB+ and/or Ba1 or below | 1,926 |
| 319 |
| 899 |
| 265 |
| 1,188 |
| 7 |
|
(*)Southern Power has PPAs that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPAs require credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade. Southern Power had $105 million of cash collateral posted related to PPA requirements at March 31, 2021. | |
(*) | Southern Power has PPAs that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPAs require credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade. Southern Power had $105 million of cash collateral posted related to PPA requirements at June 30, 2020. |
The potential collateral requirement amounts in the previous table for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event thatif either Alabama Power or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the Registrants to access capital markets and would be likely to impact the cost at which they do so.
Market Price Risk
Other than the Southern Company Gas items discussed below, there were no material changes to the Registrants' disclosures about market price risk during the secondfirst quarter 2020.2021. For an in-depth discussion of Southern Company Gas' market price risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" in Item 7 of the Form 10-K. Also see "Overview" herein for information on volatility in the financial markets that has occurred at certain periods during 2020 resulting from the COVID-19 pandemic and Notes (I) and (J) to the Condensed Financial Statements herein for information relating to derivative instruments.
Southern Company Gas is exposed to market risks, including commodity price risk, interest rate risk, and weather risk. Due to various cost recovery mechanisms, the natural gas distribution utilities that sell natural gas directly to end-use customers continue to have limited exposure to market volatility of natural gas prices. Certain of the natural gas distribution utilities may manage fuel-hedging programs implemented per the guidelines of their respective state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. In addition, certain of Southern Company Gas' non-regulated operations routinely utilize various types of derivative instruments to economically hedge certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and over-the-counter energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Some of these economic hedge activities may not qualify, or may not be designated, for hedge accounting treatment.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
For the periods presented below, the changes in net fair value of Southern Company Gas' energy-related derivative contracts were as follows:
| | | | | | | | | | | |
| | | | First Quarter 2021 | First Quarter 2020 |
| | | | (in millions) |
Contracts outstanding at beginning of period, assets (liabilities), net | | | | $ | 101 | | $ | 70 | |
Contracts realized or otherwise settled | | | | (48) | | (91) | |
Current period changes(*) | | | | (13) | | 59 | |
Contracts outstanding at the end of period, assets (liabilities), net | | | | $ | 40 | | $ | 38 | |
Netting of cash collateral | | | | 27 | | 128 | |
Cash collateral and net fair value of contracts outstanding at end of period | | | | $ | 67 | | $ | 166 | |
|
| | | | | | | | | | | | | |
| Second Quarter 2020 | Second Quarter 2019 | | Year-to-Date 2020 | Year-to-Date 2019 |
| (in millions) |
Contracts outstanding at beginning of period, assets (liabilities), net | $ | 17 |
| $ | (128 | ) | | $ | 72 |
| $ | (167 | ) |
Contracts realized or otherwise settled | (8 | ) | 5 |
| | (99 | ) | — |
|
Current period changes(*) | 17 |
| 33 |
| | 53 |
| 77 |
|
Contracts outstanding at the end of period, assets (liabilities), net | $ | 26 |
| $ | (90 | ) |
| $ | 26 |
| $ | (90 | ) |
Netting of cash collateral | 114 |
| 178 |
| | 114 |
| 178 |
|
Cash collateral and net fair value of contracts outstanding at end of period | $ | 140 |
| $ | 88 |
|
| $ | 140 |
| $ | 88 |
|
(*)Current period changes also include the fair value of new contracts entered into during the period, if any. | |
(*) | Current period changes also include the fair value of new contracts entered into during the period, if any. |
The maturities of Southern Company Gas' derivative contracts at June 30, 2020March 31, 2021 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Fair Value Measurements of Contracts at |
| March 31, 2021 |
| Total Fair Value | | Maturity |
| | 2021 | | 2022 – 2023 | | 2024 – 2025 |
| (in millions) |
Level 1(a) | $ | 13 | | | $ | 11 | | | $ | (12) | | | $ | 14 | |
Level 2(b) | (1) | | | (1) | | | (2) | | | 2 | |
Level 3(c) | 28 | | | 9 | | | 8 | | | 11 | |
Fair value of contracts outstanding at end of period(d) | $ | 40 | | | $ | 19 | | | $ | (6) | | | $ | 27 | |
(a)Valued using NYMEX futures prices.
(b)Valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers.
(c)Valued using a combination of observable and unobservable inputs.
(d)Excludes cash collateral of$27 million.
Southern Company Gas Value at Risk (VaR)
VaR is the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability. Southern Company Gas' VaR may not be comparable to that of other companies due to differences in the factors used to calculate VaR. Southern Company Gas' VaR is determined on a 95% confidence interval and a one-day holding period, which means that 95% of the time, the risk of loss in a day from a portfolio of positions is expected to be less than or equal to the amount of VaR calculated. The open exposure of Southern Company Gas is managed in accordance with established policies that limit market risk and require daily reporting of potential financial exposure to senior management. Because Southern Company Gas generally manages physical gas assets and economically protects its positions by hedging in the futures markets, Southern Company Gas' open exposure is generally mitigated. Southern Company Gas employs daily risk testing, using both VaR and stress testing, to evaluate the risk of its positions.
Southern Company Gas actively monitors open commodity positions and the resulting VaR and maintains a relatively small risk exposure as total buy volume is close to sell volume, with minimal open natural gas price risk. Based on a 95% confidence interval and employing a one-day holding period, SouthStar's portfolio of positions for all periods presented was immaterial.
|
| | | | | | | | | | | | | | | |
| | | Fair Value Measurements |
| | | June 30, 2020 |
| Total Fair Value | | Maturity |
| | Year 1 | | Years 2 & 3 | | Years 4 and thereafter |
| (in millions) |
Level 1(a) | $ | (80 | ) | | $ | (46 | ) | | $ | (41 | ) | | $ | 7 |
|
Level 2(b) | 26 |
| | 13 |
| | 9 |
| | 4 |
|
Level 3(c) | 80 |
| | 12 |
| | 27 |
| | 41 |
|
Fair value of contracts outstanding at end of period(d) | $ | 26 |
| | $ | (21 | ) | | $ | (5 | ) | | $ | 52 |
|
| |
(a) | Valued using NYMEX futures prices. |
| |
(b) | Valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers. |
| |
(c) | Valued using a combination of observable and unobservable inputs. |
| |
(d) | Excludes cash collateral of $114 million. |
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS (Continued)
Southern Company Gas' wholesale gas services segment had the following VaRs at March 31:
| | | | | | | | |
| 2021 | 2020 |
| (in millions) |
Period end(*) | $ | 1.1 | | $ | 4.2 | |
Average | 3.2 | | 2.1 | |
High(*) | 55.3 | | 4.2 | |
Low | 0.9 | | 1.3 | |
(*)The VaR at March 31, 2021 reflects significant natural gas price increases in Sequent's key markets driven by a disruption in natural gas supplies and an increase in usage due to Winter Storm Uri that extended from the Gulf Coast to across the mid-west. VaR returned to typical levels as temperatures and natural gas supplies normalized.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the sixthree months ended June 30, 2020,March 31, 2021, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, and Southern Power's disclosures about market risk. For additional market risk disclosures relating to Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" herein. For an in-depth discussion of each Registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" in Item 7 of the Form 10-K and Note 1 to the financial statements under "Financial Instruments" and Notes 13 and 14 to the financial statements in Item 8 of the Form 10-K, as well as Notes (I) and (J) to the Condensed Financial Statements herein.
Item 4. Controls and Procedures.
| |
(a) | Evaluation of disclosure controls and procedures. |
(a)Evaluation of disclosure controls and procedures.
As of the end of the period covered by this Quarterly Report on Form 10-Q, Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas conducted separate evaluations under the supervision and with the participation of each company's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective.
| |
(b) | Changes in internal controls over financial reporting. |
(b) Changes in internal controls over financial reporting.
There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the secondfirst quarter 20202021 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting.
PART II — OTHER INFORMATION
Item 1. Legal Proceedings.
See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the Registrants are involved. The Registrants' threshold for disclosing material environmental legal proceedings involving a governmental authority where potential monetary sanctions are involved is $1 million.
Item 1A. Risk Factors.
See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the Registrants. Except as described below, thereThere have been no material changes to these risk factors from those previously disclosed in the Form 10-K.
The Registrants are subject to risks related to the COVID-19 pandemic, including, but not limited to, disruption to the construction of Plant Vogtle Units 3 and 4 for Southern Company and Georgia Power.
COVID-19 has been declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention and has spread globally, including throughout the United States. In response, most jurisdictions, including in the United States, have instituted restrictions on travel, public gatherings, and non-essential business operations. While some jurisdictions, including some in the Southern Company system's service territory, have begun to relax these restrictions, many of these restrictions remain and there is no guarantee restrictions will not be reimposed in the future. These restrictions have significantly disrupted economic activity in the service territories of the traditional electric operating companies and the natural gas distribution utilities and caused volatility in capital markets at certain periods during 2020. For example, retail electric revenues attributable to changes in sales decreased 3.0% in the second quarter 2020 as compared to the corresponding period in 2019, as discussed further in RESULTS OF OPERATIONS – "Southern Company – Retail Electric Revenues" in Item 2 herein. In addition, the traditional electric operating companies and the natural gas distribution utilities temporarily suspended disconnections for non-payment by customers and waived late fees for certain periods. The U.S. House of Representatives has passed the Heroes Act, which would prohibit creditors, including utilities, from collecting consumer debts that are or become past-due, imposing late fees, or disconnecting customers for nonpayment. If the Heroes Act becomes law, its restrictions would apply until 120 days after the end of the presidential declared emergency related to the COVID-19 pandemic. The effects of the continued COVID-19 pandemic and related responses could include extended disruptions to supply chains and capital markets, further reduced labor availability and productivity, and a prolonged reduction in economic activity. These effects could have a variety of adverse impacts on the Registrants, including continued reduced demand for energy, particularly from commercial and industrial customers, reduced cash flows and liquidity, impairment of goodwill or long-lived assets, reductions in investments recorded at fair value, and further impairment of the ability of the Registrants to develop, construct, and operate facilities, including electric generation, transmission, and distribution assets, to perform necessary corporate and customer service functions, and to access funds from financial institutions and capital markets. In addition, the COVID-19 pandemic could cause delays or cancellations to regulatory proceedings.
Further, the effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4. In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures, isolating individuals who have tested positive for COVID-19, are showing symptoms consistent with COVID-19, are being tested for COVID-19, or have been in close contact with such persons, requiring self-quarantine, and adopting additional precautionary measures. In April 2020, Georgia Power announced a reduction in workforce at Plant Vogtle Units 3 and 4, which totaled approximately 20% of the then-existing workforce. This reduction in workforce was a mitigation action intended to address the impact of the COVID-19 pandemic on the Plant Vogtle Units 3 and 4 workforce and construction site, including challenges with labor productivity that were exacerbated by the impact of the COVID-19 pandemic. The April 2020 workforce reduction was intended to provide operational efficiencies by increasing productivity of the remaining workforce and reducing workforce fatigue and absenteeism. Further, it was also intended to allow for increased social distancing by the workforce and facilitate compliance with the recommendations from the Centers for Disease Control and Prevention. The April 2020 workforce reduction did reduce absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing. From the initial peak in April 2020, the number of active
cases at the site declined significantly during May and early June, but began increasing again in mid-June and continues to impact productivity levels and pace of activity completion. As a result of these factors, overall production improvements have not been achieved at the levels anticipated, contributing to the allocation of, and increase in, construction contingency described in Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein. Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be between $70 million and $115 million, which is included in the total project capital cost forecast and assumes (i) absenteeism rates continue to normalize and (ii) the intended productivity efficiencies and production targets assumed in Southern Nuclear's July 2020 aggressive site work plan are realized in the coming months. However, the ultimate impact of the COVID-19 pandemic on the construction schedule and budget for Plant Vogtle Units 3 and 4 cannot be determined at this time.
Item 6. Exhibits.
The exhibits below with an asterisk (*) preceding the exhibit number are filed herewith. The remaining exhibits have previously been filed with the SEC and are incorporated herein by reference. The exhibits marked with a pound sign (#) are management contracts or compensatory plans or arrangements.
| | | | | | | | | | | | | | |
| | (4) Instruments Describing Rights of Security Holders, Including Indentures |
| | | | |
| | (3) Articles of Incorporation and By-LawsSouthern Company |
| | | | |
| | Mississippi Power |
(a)1 | | | | |
| * | (d)1 | - | |
| | | | |
| * | (d)(a)2 | - | |
| | | | |
| | Georgia Power |
| | | | |
| | (b) | - | |
| | | | |
| | (10) Material Contracts |
| | | | |
| | Alabama PowerSouthern Company |
| | | | |
# | * | (b)(a) | - | |
| | | | |
| | Alabama Power |
| | | | |
# | | (b) | - | Amendment No. 2 to The Southern Company Change in Control Benefits Protection Plan, effective as of February 26, 2021. See Exhibit 10(a) herein. |
| | | | |
| | (24) Power of Attorney and Resolutions |
| | | | |
| | Southern Company |
| | | | |
| | (a) | - | |
| | | | |
| | Alabama Power |
| | | | |
| | (b) | - | |
| | | | |
| | | | | | | | | | | | | | |
| | Georgia Power |
| | | | |
| | (c)1 | - | |
| | | | |
| | Mississippi Power |
(c)2 | | | | |
| | (d) | - | |
| | | | |
| | SouthernMississippi Power |
| | | | |
| | (e)(d)1 | - | |
| | | | |
| * | (e)2 | - | |
| | | | |
|
| | | | |
| | Southern Company GasPower |
| | | | |
| | (f)(e)1 | - | |
| | | | |
| | Southern Company Gas |
| | | | |
| | (f)1 | - | |
| | | | |
| | (f)2 | - | |
| | | | |
| | (31) Section 302 Certifications |
| | | | |
| | Southern Company |
| | | | |
| * | (a)1 | - | |
| | | | |
| * | (a)2 | - | |
| | | | |
| | Alabama Power |
| | | | |
| * | (b)1 | - | |
| | | | |
| * | (b)2 | - | |
| | | | |
| | Georgia Power |
| | | | |
| * | (c)1 | - | |
| | | | |
| * | (c)2 | - | |
| | | | |
| | Mississippi Power |
| | | | |
| * | (d)1 | - | |
| | | | |
| * | (d)2 | - | |
| | | | |
| | | | | | | | | | | | | | |
| | Southern Power |
| | | | |
| * | (e)1 | - | |
| | | | |
| * | (e)2 | - | |
| | | | |
| | Southern Company Gas |
| | | | |
| * | (f)1 | - | |
| | | | |
| * | (f)2 | - | |
| | | | |
| | (32) Section 906 Certifications |
| | | | |
| | Southern Company |
| | | | |
| * | (a) | - | |
| | | | |
| | Alabama Power |
| | | | |
| * | (b) | - | |
| | | | |
|
| | | | |
| | Georgia Power |
| | | | |
| * | (c) | - | |
| | | | |
| | Mississippi Power |
| | | | |
| * | (d) | - | |
| | | | |
| | Southern Power |
| | | | |
| * | (e) | - | |
| | | | |
| | Southern Company Gas |
| | | | |
| * | (f) | - | |
| | | | |
| | (101) Interactive Data Files |
| | | | |
| * | INS | - | XBRL Instance Document – The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document. |
| * | SCH | - | XBRL Taxonomy Extension Schema Document |
| * | CAL | - | XBRL Taxonomy Calculation Linkbase Document |
| * | DEF | - | XBRL Definition Linkbase Document |
| * | LAB | - | XBRL Taxonomy Label Linkbase Document |
| * | PRE | - | XBRL Taxonomy Presentation Linkbase Document |
| | | | |
| | (104) Cover Page Interactive Data File |
| * | | | Formatted as inline XBRL with applicable taxonomy extension information contained in Exhibits 101. |
THE SOUTHERN COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
| | | | | | | | | | | |
| | THE SOUTHERN COMPANY |
| | | |
By | | THE SOUTHERN COMPANY |
| | | |
By | | Thomas A. Fanning |
| | Chairman, President, and Chief Executive Officer |
| | (Principal Executive Officer) |
| | | |
By | | Andrew W. Evans |
| | Executive Vice President and Chief Financial Officer |
| | (Principal Financial Officer) |
| | | |
By | | /s/ Melissa K. Caen | |
| | (Melissa K. Caen, Attorney-in-fact) | |
Date: July 29, 2020April 28, 2021
ALABAMA POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
| | | | | | | | | | | |
| | ALABAMA POWER COMPANY |
| | | |
By | | ALABAMA POWER COMPANY |
| | | |
By | | Mark A. Crosswhite | |
| | Chairman, President, and Chief Executive Officer |
| | (Principal Executive Officer) |
| | | |
By | | Philip C. Raymond |
| | Executive Vice President, Chief Financial Officer, and Treasurer |
| | (Principal Financial Officer) |
| | | |
By | | /s/ Melissa K. Caen | |
| | (Melissa K. Caen, Attorney-in-fact) | |
Date: July 29, 2020April 28, 2021
GEORGIA POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
| | | | | | | | | | | |
| | GEORGIA POWER COMPANY |
| | | |
By | | GEORGIA POWER COMPANY |
| | | |
By | | W. Paul Bowers |
| | Chairman President, and Chief Executive Officer |
| | (Principal Executive Officer) |
| | | |
By | | David P. PorochDaniel S. Tucker |
| | Executive Vice President, Chief Financial Officer, Treasurer, and ComptrollerTreasurer |
| | (Principal Financial Officer) |
| | | |
By | | /s/ Melissa K. Caen | |
| | (Melissa K. Caen, Attorney-in-fact) | |
Date: July 29, 2020April 28, 2021
MISSISSIPPI POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
| | | | | | | | | | | |
| | MISSISSIPPI POWER COMPANY |
| | | |
By | | MISSISSIPPI POWER COMPANY |
| | | |
By | | Anthony L. Wilson |
| | Chairman, President, and Chief Executive Officer |
| | (Principal Executive Officer) |
| | | |
By | | Moses H. Feagin |
| | Senior Vice President, Chief Financial Officer, and Treasurer |
| | (Principal Financial Officer) |
| | | |
By | | /s/ Melissa K. Caen | |
| | (Melissa K. Caen, Attorney-in-fact) | |
Date: July 29, 2020April 28, 2021
SOUTHERN POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
| | | | | | | | | | | |
| | SOUTHERN POWER COMPANY |
| | | |
By | | SOUTHERN POWER COMPANYChristopher Cummiskey |
| | | |
By | | Christopher Cummiskey |
| | Chairman and Chief Executive Officer |
| | (Principal Executive Officer) |
| | | |
By | | Elliott L. Spencer |
| | Senior Vice President, Chief Financial Officer, and Treasurer |
| | (Principal Financial Officer) |
| | | |
By | | /s/ Melissa K. Caen | |
| | (Melissa K. Caen, Attorney-in-fact) | |
Date: July 29, 2020April 28, 2021
SOUTHERN COMPANY GAS
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
| | | | | | | | | | | |
| | SOUTHERN COMPANY GAS |
| | | |
By | | SOUTHERN COMPANY GAS |
| | | |
By | | Kimberly S. Greene |
| | Chairman, President, and Chief Executive Officer |
| | (Principal Executive Officer) |
| | | |
By | | Daniel S. TuckerDavid P. Poroch |
| | Executive Vice President, Chief Financial Officer, and Treasurer |
| | (Principal Financial Officer) |
| | | |
By | | /s/ Melissa K. Caen | |
| | (Melissa K. Caen, Attorney-in-fact) | |
Date: July 29, 2020April 28, 2021