XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (amounts in millions, shares in thousands)
|
| | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock Issued | | Retained Earnings | | Accumulated
Other
Comprehensive
Loss | | Total
Common
Stockholders’
Equity |
| | Shares | | Par Value | | Additional Paid In Capital | | | |
| Three Months Ended June 30, 2019 and 2018 | | | | | | | | | | | |
| Balance at March 31, 2018 | 508,662 |
| | $ | 1,272 |
| | $ | 5,903 |
| | $ | 4,510 |
| | $ | (124 | ) | | $ | 11,561 |
|
| Net income |
|
| |
|
| |
|
| | 265 |
| |
|
| | 265 |
|
| Other comprehensive income |
|
| |
|
| |
|
| |
|
| | 2 |
| | 2 |
|
| Dividends declared on common stock ($0.38 per share) |
|
| |
|
| |
|
| | (195 | ) | |
|
| | (195 | ) |
| Issuances of common stock | 236 |
| | — |
| | 10 |
| |
|
| |
|
| | 10 |
|
| Share-based compensation |
|
| |
|
| | 7 |
| | — |
| |
|
| | 7 |
|
| Balance at June 30, 2018 | 508,898 |
| | $ | 1,272 |
| | $ | 5,920 |
| | $ | 4,580 |
| | $ | (122 | ) | | $ | 11,650 |
|
| | | | | | | | | | | | |
| Balance at March 31, 2019 | 514,668 |
| | $ | 1,287 |
| | $ | 6,173 |
| | $ | 4,996 |
| | $ | (127 | ) | | $ | 12,329 |
|
| Net income |
|
| |
|
| |
|
| | 238 |
| |
|
| | 238 |
|
| Other comprehensive loss |
|
| |
|
| |
|
| |
|
| | (8 | ) | | (8 | ) |
| Dividends declared on common stock ($0.41 per share) |
|
| |
|
| |
|
| | (209 | ) | |
|
| | (209 | ) |
| Issuances of common stock | 197 |
| | — |
| | 10 |
| |
|
| |
|
| | 10 |
|
| Share-based compensation |
|
| |
|
| | 7 |
| | (1 | ) | |
|
| | 6 |
|
| Balance at June 30, 2019 | 514,865 |
| | $ | 1,287 |
| | $ | 6,190 |
| | $ | 5,024 |
| | $ | (135 | ) | | $ | 12,366 |
|
| | | | | | | | | | | | |
| See Notes to Consolidated Financial Statements |
XCEL ENERGY INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (amounts in millions, shares in thousands)
|
| | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock Issued | | Retained Earnings | | Accumulated
Other
Comprehensive
Loss | | Total
Common
Stockholders’
Equity |
| | Shares | | Par Value | | Additional Paid In Capital | | | |
| Six Months Ended June 30, 2019 and 2018 | | | | | | | | | | | |
| Balance at Dec. 31, 2017 | 507,763 |
| | $ | 1,269 |
| | $ | 5,898 |
| | $ | 4,413 |
| | $ | (125 | ) | | $ | 11,455 |
|
| Net income | | | | | | | 556 |
| | | | 556 |
|
| Other comprehensive income | | | | | | | | | 3 |
| | 3 |
|
| Dividends declared on common stock ($0.76 per share) | | | | | | | (389 | ) | | | | (389 | ) |
| Issuances of common stock | 1,157 |
| | 3 |
| | 24 |
| | | | | | 27 |
|
| Repurchases of common stock | (22 | ) | | — |
| | (1 | ) | | | | | | (1 | ) |
| Share-based compensation | | | | | (1 | ) | | — |
| | | | (1 | ) |
| Balance at June 30, 2018 | 508,898 |
| | $ | 1,272 |
| | $ | 5,920 |
| | $ | 4,580 |
| | $ | (122 | ) | | $ | 11,650 |
|
| | | | | | | | | | | | |
| Balance at Dec. 31, 2018 | 514,037 |
| | $ | 1,285 |
| | $ | 6,168 |
| | $ | 4,893 |
| | $ | (124 | ) | | $ | 12,222 |
|
| Net income | | | | | | | 553 |
| | | | 553 |
|
| Other comprehensive income | | | | | | | | | (11 | ) | | (11 | ) |
| Dividends declared on common stock ($0.81 per share) | | | | | | | (419 | ) | | | | (419 | ) |
| Issuances of common stock | 834 |
| | 2 |
| | 20 |
| | | | | | 22 |
|
| Repurchases of common stock | (6 | ) | | — |
| | — |
| | | | | | — |
|
| Share-based compensation | | | | | 2 |
| | (3 | ) | | | | (1 | ) |
| Balance at June 30, 2019 | 514,865 |
| | $ | 1,287 |
| | $ | 6,190 |
| | $ | 5,024 |
| | $ | (135 | ) | | $ | 12,366 |
|
| | | | | | | | | | | | |
| See Notes to Consolidated Financial Statements |
XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements (UNAUDITED)
In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP),U.S. GAAP, the financial position of Xcel Energy Inc. and its subsidiaries as of June 30, 20192020 and Dec. 31, 2018;2019; the results of its operations, including the components of net income and comprehensive income, and changes in stockholders’ equity for the three and six months ended June 30, 20192020 and 2018;2019; and its cash flows for the six months ended June 30, 20192020 and 2018. 2019.
All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 20192020, up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 20182019, balance sheet information has been derived from the audited 20182019 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2018. 2019. Notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto, included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2018,2019, filed with the SEC on Feb. 22, 2019.21, 2020. Due to the seasonality of Xcel Energy’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results. | | |
| 1. | Summary of Significant Accounting Policies |
The significant accounting policies set forth in Note 1 to the consolidated financial statements in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2018,2019, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference. | | |
| 2. | Accounting Pronouncements |
Recently Issued
Credit Losses— In 2016, the FASB issued Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326), which changes how entities account for losses on receivables and certain other assets. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards. ASC Topic 326 is effective for interim and annual periods beginning on or after Dec. 15, 2019, and will be applied on a modified-retrospective approach through a cumulative-effect adjustment to retained earnings as of Jan. 1, 2020. Xcel Energy is currently evaluating the impact of adoption of the new standard on its consolidated financial statements.
Recently Adopted
LeasesCredit Losses —In 2016, the FASB issued LeasesFinancial Instruments - Credit Losses, Topic 326 (ASC Topic 326), Topic 842(ASC Topic 842), which provides newchanges how entities account for losses on receivables and certain other assets. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting and disclosure guidance for leasing activities, most significantly requiring that operating leases be recognized on the balance sheet. standards.
Xcel Energy adoptedimplemented the guidance using a modified-retrospective approach, recognizing a cumulative effect charge of $2 million (after tax) to retained earnings on Jan. 1, 2019 utilizing the package of transition practical expedients provided by the new standard, including carrying forward prior conclusions on whether agreements existing before the adoption date contain leases and whether existing leases are operating or finance leases; ASC Topic 842 refers to capital leases as finance leases.
Specifically for land easement contracts, Xcel Energy has elected the practical expedient provided by ASU No. 2018-01 Leases: Land Easement Practical Expedient for Transition to Topic 842, and as a result, only those easement contracts entered on or after Jan. 1, 2019 will be evaluated to determine if lease treatment is appropriate.
Xcel Energy also utilized the transition practical expedient offered by ASU No. 2018-11 Leases: Targeted Improvements to implement the standard on a prospective basis. As a result, reporting periods in the consolidated financial statements beginning Jan. 1, 2019 reflect the implementation of ASC Topic 842, while prior periods continue to be reported in accordance with Leases, Topic 840 (ASC Topic 840).2020. Other than first-time recognition of operating leasesan allowance for doubtful accounts on its consolidated balance sheet,accrued unbilled revenues, the implementationJan. 1, 2020, adoption of ASC Topic 842326 did not have a significant impact on Xcel Energy’s consolidated financial statements. Adoption resulted in recognition of approximately $1.7 billion of operating lease ROU assets and current/noncurrent operating lease liabilities. See Note 10 for leasing disclosures.
3. Selected Balance Sheet Data
|
| | | | | | | | |
| (Millions of Dollars) | | June 30, 2019 | | Dec. 31, 2018 |
| Accounts receivable, net | | | | |
| Accounts receivable | | $ | 786 |
| | $ | 915 |
|
| Less allowance for bad debts | | (49 | ) | | (55 | ) |
| | | $ | 737 |
| | $ | 860 |
|
|
| | | | | | | | |
| (Millions of Dollars) | | June 30, 2019 | | Dec. 31, 2018 |
| Inventories | | | | |
| Materials and supplies | | $ | 272 |
| | $ | 271 |
|
| Fuel | | 164 |
| | 170 |
|
| Natural gas | | 47 |
| | 107 |
|
| | | $ | 483 |
| | $ | 548 |
|
|
| | | | | | | | |
| (Millions of Dollars) | | June 30, 2019 | | Dec. 31, 2018 |
| Property, plant and equipment, net | | | | |
| Electric plant | | $ | 43,006 |
| | $ | 41,472 |
|
| Natural gas plant | | 6,289 |
| | 6,210 |
|
| Common and other property | | 2,215 |
| | 2,154 |
|
Plant to be retired (a) | | 290 |
| | 322 |
|
| CWIP | | 1,745 |
| | 2,091 |
|
| Total property, plant and equipment | | 53,545 |
| | 52,249 |
|
| Less accumulated depreciation | | (16,278 | ) | | (15,659 | ) |
| Nuclear fuel | | 2,859 |
| | 2,771 |
|
| Less accumulated amortization | | (2,475 | ) | | (2,417 | ) |
| | | $ | 37,651 |
| | $ | 36,944 |
|
| | |
(a)3. Selected Balance Sheet Data
| In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in approximately 2022 and 2025, respectively. PSCo also expects Craig Unit 1 to be retired early in 2025. Amounts are presented net of accumulated depreciation. |
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | June 30, 2020 | | Dec. 31, 2019 |
| Accounts receivable, net | | | | |
| Accounts receivable | | $ | 859 | | | $ | 892 | |
| Less allowance for bad debts | | (60) | | | (55) | |
| Accounts receivable, net | | $ | 799 | | | $ | 837 | |
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | June 30, 2020 | | Dec. 31, 2019 |
| Inventories | | | | |
| Materials and supplies | | $ | 277 | | | $ | 270 | |
| Fuel | | 173 | | | 191 | |
| Natural gas | | 37 | | | 83 | |
| Total inventories | | $ | 487 | | | $ | 544 | |
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | June 30, 2020 | | Dec. 31, 2019 |
| Property, plant and equipment, net | | | | |
| Electric plant | | $ | 45,413 | | | $ | 44,355 | |
| Natural gas plant | | 6,747 | | | 6,560 | |
| Common and other property | | 2,385 | | | 2,341 | |
Plant to be retired (a) | | 292 | | | 259 | |
| CWIP | | 3,060 | | | 2,329 | |
| Total property, plant and equipment | | 57,897 | | | 55,844 | |
| Less accumulated depreciation | | (17,097) | | | (16,735) | |
| Nuclear fuel | | 2,925 | | | 2,909 | |
| Less accumulated amortization | | (2,601) | | | (2,535) | |
| Property, plant and equipment, net | | $ | 41,124 | | | $ | 39,483 | |
(a)In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in approximately 2022 and 2025, respectively. PSCo also expects Craig Unit 1 to be retired early in 2025. Amounts are presented net of accumulated depreciation.
| | |
| 4. Borrowings and Other Financing Instruments |
Short-Term Borrowings
Short-Term Debt — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan agreements.
Commercial paper and term loan borrowings outstanding for Xcel Energy were as follows:
| | | (Amounts in Millions, Except Interest Rates) | | Three Months Ended June 30, 2019 | | Year Ended
Dec. 31, 2018 | (Amounts in Millions, Except Interest Rates) | | Three Months Ended June 30, 2020 | | Year Ended Dec. 31, 2019 |
| Borrowing limit | | $ | 3,600 |
| | $ | 3,250 |
| Borrowing limit | | $ | 4,300 | | | $ | 3,600 | |
| Amount outstanding at period end | | 1,597 |
| | 1,038 |
| Amount outstanding at period end | | 1,410 | | | 595 | |
| Average amount outstanding | | 1,313 |
| | 788 |
| Average amount outstanding | | 1,496 | | | 1,115 | |
| Maximum amount outstanding | | 1,597 |
| | 1,349 |
| Maximum amount outstanding | | 1,770 | | | 1,780 | |
| Weighted average interest rate, computed on a daily basis | | 2.83 | % | | 2.34 | % | Weighted average interest rate, computed on a daily basis | | 1.65 | % | | 2.72 | % |
| Weighted average interest rate at period end | | 2.74 |
| | 2.97 |
| Weighted average interest rate at period end | | 0.76 | | | 2.34 | |
Letters of Credit — Xcel Energy Inc. and its subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At both June 30, 20192020 and Dec. 31, 2018,2019, there were $54$20 million and $49 million, respectively, of letters of credit outstanding under the credit facilities. The contract amounts of these letters of credit approximate their fair value and are subject to fees.
Revolving Credit Facilities — In order to use their commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper in an aggregate amount exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
Amended Credit Agreements —InAs of June 2019,30, 2020, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS entered into amended five-year credit agreements with a syndicate of banks. The total borrowing limit under the amended credit agreements was increased to $3.1 billion. The amended credit agreements have substantially the same terms and conditions as the prior credit agreements withits utility subsidiaries had the following exceptions:committed revolving credit facilities available:
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Credit Facility (a) | | Outstanding (b) | | Available |
| Xcel Energy Inc. | | $ | 1,250 | | | $ | 210 | | | $ | 1,040 | |
| PSCo | | 700 | | | 8 | | | 692 | |
| NSP-Minnesota | | 500 | | | 2 | | | 498 | |
| SPS | | 500 | | | 10 | | | 490 | |
| NSP-Wisconsin | | 150 | | | — | | | 150 | |
| Total | | $ | 3,100 | | | $ | 230 | | | $ | 2,870 | |
(a)Expires in June 2024.
Maturity extended from June 2021 to June 2024.
| |
• | Borrowing limit for Xcel Energy was increased from $1.0 billion to $1.25 billion(b)Includes outstanding commercial paper and letters of credit.
|
| |
• | Borrowing limit for SPS was increased from $400 million to $500 million
|
| |
• | Added swingline subfacility for Xcel Energy up to $75 million
|
Xcel Energy Inc., NSP-Minnesota, PSCo, and SPS each have the right to request an extension of the revolving credit facility termination date for two additional one yearone-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility termination date for an additional one yearone-year period. All extension requests are subject to majority bank group approval.
As of June 30, 2019, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available:
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | Credit Facility (a) | | Outstanding (b) | | Available |
| Xcel Energy Inc. | | $ | 1,250 |
| | $ | 632 |
| | $ | 618 |
|
| PSCo | | 700 |
| | 231 |
| | 469 |
|
| NSP-Minnesota | | 500 |
| | 213 |
| | 287 |
|
| SPS | | 500 |
| | 2 |
| | 498 |
|
| NSP-Wisconsin | | 150 |
| | 50 |
| | 100 |
|
| Total | | $ | 3,100 |
| | $ | 1,128 |
| | $ | 1,972 |
|
| |
(b)
| Includes outstanding commercial paper and letters of credit. |
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the respective credit facilities. Xcel Energy Inc. and its subsidiaries had no0 direct advances on the credit facilities outstanding as of June 30, 20192020 and Dec. 31, 2018.2019.
Term Loan AgreementAgreements — In December 2018,2019, Xcel Energy Inc. renewed itsentered into a $500 million 364 Day364-Day Term Loan Agreement. No additional capacity remains as loans borrowed and repaid may not be redrawn. The loan is unsecured andAgreement that matures Dec. 3, 2019.1, 2020. Xcel Energy has an option to request an extension through Dec. 2, 2020.
Nov. 30, 2021. In March 2020, Xcel Energy Inc. entered into a $700 million, 364-Day Term Loan Agreement. The loan is unsecured and matures March 22, 2021. Xcel Energy has an option to request an extension through March 21, 2022. The term loan includesloans include one financial covenant, requiring Xcel Energy’s consolidated funded debt to total capitalization ratio to be less than or equal to 65%.65 percent. Interest is at a rate equal to either (i) the Eurodollar rate, plus 50.060.0 basis points, or (ii) an alternate base rate. Xcel Energy is also required to pay a commitment fee equal to 10 basis points per annum on any unborrowed portion.
As of June 30, 2019,2020, Xcel Energy Inc.’s term loan borrowings were as follows:
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | Limit | | Amount Used | | Available |
| Xcel Energy Inc. | | $ | 500 |
| | $ | 500 |
| | $ | — |
|
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Limit | | Amount Used | | Available |
| Xcel Energy Inc. | | $ | 1,200 | | | $ | 1,200 | | | $ | — | |
Bilateral Credit Agreement
In March 2019, NSP-Minnesota entered into a one-yearone year uncommitted bilateral credit agreement. The credit agreement is limited in use to support letters of credit. In March 2020, NSP-Minnesota renewed its bilateral credit agreement for an additional one year term.
As of June 30, 2019,2020, NSP-Minnesota’s outstanding letters of credit under the Bilateral Credit Agreementbilateral credit agreement were as follows:
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | Limit | | Amount Outstanding | | Available |
| NSP-Minnesota | | $ | 75 |
| | $ | 23 |
| | $ | 52 |
|
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Limit | | Amount Outstanding | | Available |
| NSP-Minnesota | | $ | 75 | | | $ | 31 | | | $ | 44 | |
Long-Term Borrowings
During the six months ended June 30, 2019,2020, Xcel Energy Inc. and its utility subsidiaries issued the following:
•Xcel Energy Inc. issued $600 million of 3.40% senior unsecured notes due June 1, 2030;
•PSCo issued $400$375 million of 4.05%2.70% first mortgage bonds due Sept.Jan. 15, 2049.
Xcel Energy Inc. issued $1302051 and $375 million of 4.00% senior unsecured1.90% first mortgage bonds due JuneJan. 15, 2028.2031;
•SPS issued $300$350 million of 3.75%3.15% first mortgage bonds due May 1, 2050;
•NSP-Wisconsin issued $100 million of 3.05% first mortgage bonds due May 1, 2051; and
•NSP-Minnesota issued $700 million of 2.60% first mortgage bonds due June 15, 2049.1, 2051.
Forward Equity Agreements — In November 2018,2019, Xcel Energy Inc. entered into forward sale agreements in connection with a completed $459$743 million public offering of 9.411.8 million shares of Xcel Energy common stock. The initial forward agreement was for 8.110.3 million shares with an additional agreement for 1.21.5 million shares that was exercised at the option of the banking counterparty.
At June 30, 2019,2020, the forward agreements could have been settled with physical delivery of 9.411.8 million common shares to the banking counterparty in exchange for cash of $452$728 million. The forward instruments could also have been settled at June 30, 20192020, with delivery of approximately $100$24 million of cash or approximately 1.70.4 million shares of common stock to the counterparty, if Xcel Energy unilaterally elected net cash or net share settlement, respectively.
The forward price used to determine amounts due at settlement is calculated based on the November 20182019 public offering price for Xcel Energy’s common stock of $49.00,$62.69, increased for the overnight bank funding rate, less a spread of 0.75% and less expected dividends on Xcel Energy’s common stock during the period the instruments are outstanding.
Xcel Energy may settle the agreements at any time up to the maturity date of February 7,Dec. 31, 2020. Depending on settlement timing, and form of settlement, cash proceeds are expected to be approximately $450$720 million to $730 million.
Forward equity instruments were recognized within stockholders’ equity at fair value at execution of the agreements and will not be subsequently adjusted until settlement.
Other Equity — Xcel Energy Inc. issued $19.4$20 million and $38.5$19 millionof equity through the DRIP during the six months ended June 30, 20192020 and year ended Dec. 31, 2018,2019, respectively. The program allows shareholders to elect dividend reinvestment in Xcel Energy Inc. common stock through a non-cash transaction.
Revenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy’s operating revenues consists of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, 2020 | | | | | | |
| (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
| Major revenue types | | | | | | | | |
| Revenue from contracts with customers: | | | | | | | | |
| Residential | | $ | 718 | | | $ | 167 | | | $ | 10 | | | $ | 895 | |
| C&I | | 1,075 | | | 73 | | | 6 | | | 1,154 | |
| Other | | 31 | | | — | | | 1 | | | 32 | |
| Total retail | | 1,824 | | | 240 | | | 17 | | | 2,081 | |
| Wholesale | | 160 | | | — | | | — | | | 160 | |
| Transmission | | 153 | | | — | | | — | | | 153 | |
| Other | | 21 | | | 26 | | | — | | | 47 | |
| Total revenue from contracts with customers | | 2,158 | | | 266 | | | 17 | | | 2,441 | |
| Alternative revenue and other | | 128 | | | 14 | | | 3 | | | 145 | |
| Total revenues | | $ | 2,286 | | | $ | 280 | | | $ | 20 | | | $ | 2,586 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, 2019 | | | | | | |
| (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
| Major revenue types | | | | | | | | |
| Revenue from contracts with customers: | | | | | | | | |
| Residential | | $ | 624 | | | $ | 182 | | | $ | 10 | | | $ | 816 | |
| C&I | | 1,201 | | | 90 | | | 6 | | | 1,297 | |
| Other | | 31 | | | — | | | 1 | | | 32 | |
| Total retail | | 1,856 | | | 272 | | | 17 | | | 2,145 | |
| Wholesale | | 154 | | | — | | | — | | | 154 | |
| Transmission | | 127 | | | — | | | — | | | 127 | |
| Other | | 11 | | | 26 | | | — | | | 37 | |
| Total revenue from contracts with customers | | 2,148 | | | 298 | | | 17 | | | 2,463 | |
| Alternative revenue and other | | 101 | | | 10 | | | 3 | | | 114 | |
| Total revenues | | $ | 2,249 | | | $ | 308 | | | $ | 20 | | | $ | 2,577 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30, 2020 | | | | | | |
| (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
| Major revenue types | | | | | | | | |
| Revenue from contracts with customers: | | | | | | | | |
| Residential | | $ | 1,394 | | | $ | 522 | | | $ | 21 | | | $ | 1,937 | |
| C&I | | 2,141 | | | 253 | | | 15 | | | 2,409 | |
| Other | | 60 | | | — | | | 2 | | | 62 | |
| Total retail | | 3,595 | | | 775 | | | 38 | | | 4,408 | |
| Wholesale | | 326 | | | — | | | — | | | 326 | |
| Transmission | | 285 | | | — | | | — | | | 285 | |
| Other | | 38 | | | 58 | | | — | | | 96 | |
| Total revenue from contracts with customers | | 4,244 | | | 833 | | | 38 | | | 5,115 | |
| Alternative revenue and other | | 245 | | | 30 | | | 7 | | | 282 | |
| Total revenues | | $ | 4,489 | | | $ | 863 | | | $ | 45 | | | $ | 5,397 | |
| | | | | Three Months Ended June 30, 2018 | | Six Months Ended June 30, 2019 | |
| (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total | (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
| Major revenue types | | | | | | | | | Major revenue types | | | | | | | | |
| Revenue from contracts with customers: | | | | | | | | | Revenue from contracts with customers: | |
| Residential | | $ | 678 |
| | $ | 157 |
| | $ | 9 |
| | $ | 844 |
| Residential | | $ | 1,351 | | | $ | 677 | | | $ | 19 | | | $ | 2,047 | |
| C&I | | 1,206 |
| | 82 |
| | 5 |
| | 1,293 |
| C&I | | 2,341 | | | 345 | | | 15 | | | 2,701 | |
| Other | | 33 |
| | — |
| | 2 |
| | 35 |
| Other | | 63 | | | — | | | 2 | | | 65 | |
| Total retail | | 1,917 |
| | 239 |
| | 16 |
| | 2,172 |
| Total retail | | 3,755 | | | 1,022 | | | 36 | | | 4,813 | |
| Wholesale | | 194 |
| | — |
| | — |
| | 194 |
| Wholesale | | 343 | | | — | | | — | | | 343 | |
| Transmission | | 132 |
| | — |
| | — |
| | 132 |
| Transmission | | 258 | | | — | | | — | | | 258 | |
| Other | | 24 |
| | 23 |
| | — |
| | 47 |
| Other | | 29 | | | 60 | | | — | | | 89 | |
| Total revenue from contracts with customers | | 2,267 |
| | 262 |
| | 16 |
| | 2,545 |
| Total revenue from contracts with customers | | 4,385 | | | 1,082 | | | 36 | | | 5,503 | |
| Alternative revenue and other | | 81 |
| | 30 |
| | 2 |
| | 113 |
| Alternative revenue and other | | 189 | | | 20 | | | 6 | | | 215 | |
| Total revenues | | $ | 2,348 |
| | $ | 292 |
| | $ | 18 |
| | $ | 2,658 |
| Total revenues | | $ | 4,574 | | | $ | 1,102 | | | $ | 42 | | | $ | 5,718 | |
|
| | | | | | | | | | | | | | | | |
| | | Six Months Ended June 30, 2019 |
| (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
| Major revenue types | | | | | | | | |
| Revenue from contracts with customers: | | | | | | | | |
| Residential | | $ | 1,351 |
| | $ | 677 |
| | $ | 19 |
| | $ | 2,047 |
|
| C&I | | 2,341 |
| | 345 |
| | 15 |
| | 2,701 |
|
| Other | | 63 |
| | — |
| | 2 |
| | 65 |
|
| Total retail | | 3,755 |
| | 1,022 |
| | 36 |
| | 4,813 |
|
| Wholesale | | 343 |
| | — |
| | — |
| | 343 |
|
| Transmission | | 258 |
| | — |
| | — |
| | 258 |
|
| Other | | 29 |
| | 60 |
| | — |
| | 89 |
|
| Total revenue from contracts with customers | | 4,385 |
| | 1,082 |
| | 36 |
| | 5,503 |
|
| Alternative revenue and other | | 189 |
| | 20 |
| | 6 |
| | 215 |
|
| Total revenues | | $ | 4,574 |
| | $ | 1,102 |
| | $ | 42 |
| | $ | 5,718 |
|
|
| | | | | | | | | | | | | | | | |
| | | Six Months Ended June 30, 2018 |
| (Millions of Dollars) | | Electric | | Natural Gas | | All Other | | Total |
| Major revenue types | | | | | | | | |
| Revenue from contracts with customers: | | | | | | | | |
| Residential | | $ | 1,365 |
| | $ | 547 |
| | $ | 18 |
| | $ | 1,930 |
|
| C&I | | 2,318 |
| | 289 |
| | 12 |
| | 2,619 |
|
| Other | | 66 |
| | — |
| | 4 |
| | 70 |
|
| Total retail | | 3,749 |
| | 836 |
| | 34 |
| | 4,619 |
|
| Wholesale | | 382 |
| | — |
| | — |
| | 382 |
|
| Transmission | | 255 |
| | — |
| | — |
| | 255 |
|
| Other | | 63 |
| | 51 |
| | — |
| | 114 |
|
| Total revenue from contracts with customers | | 4,449 |
| | 887 |
| | 34 |
| | 5,370 |
|
| Alternative revenue and other | | 168 |
| | 67 |
| | 4 |
| | 239 |
|
| Total revenues | | $ | 4,617 |
| | $ | 954 |
| | $ | 38 |
| | $ | 5,609 |
|
Except to the extent noted below, Note 7 to the consolidated financial statements included in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 20182019, represents, in all material respects, the current status of other income tax matters except to the extent noted below, and are incorporated herein by reference.The following table reconciles the difference between the statutory rate and the ETR:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30 | | | | Six Months Ended June 30 | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
| Federal statutory rate | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
| State tax (net of federal tax effect) | | 5.1 | | | 5.0 | | | 5.0 | | | 5.0 | |
| Decreases in tax from: | | | | | | | | |
| Wind PTCs | | (21.1) | | | (11.9) | | | (19.1) | | | (10.0) | |
Plant regulatory differences (a) | | (7.1) | | | (5.5) | | | (7.8) | | | (5.6) | |
| Other tax credits, net NOL & tax credit allowances | | (1.9) | | | (0.6) | | | (1.4) | | | (1.8) | |
| Other (net) | | (0.7) | | | 1.2 | | | (1.1) | | | (0.5) | |
| Effective income tax rate | | (4.7) | % | | 9.2 | % | | (3.4) | % | | 8.1 | % |
|
| | | | | | | | | | | | |
| | | Three Months Ended June 30 | | Six Months Ended June 30 |
| | | 2019 | | 2018 | | 2019 | | 2018 |
| Federal statutory rate | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
| State tax (net of federal tax effect) | | 5.0 |
| | 5.1 |
| | 5.0 |
| | 5.0 |
|
| (Decreases) increases: | | | | | | | | |
| Wind PTCs | | (11.9 | ) | | (5.4 | ) | | (10.0 | ) | | (5.8 | ) |
Plant regulatory differences (a) | | (5.5 | ) | | (2.4 | ) | | (5.6 | ) | | (1.8 | ) |
| Other tax credits and allowances (net) | | (0.6 | ) | | (1.1 | ) | | (1.8 | ) | | (1.2 | ) |
| Other (net) | | 1.2 |
| | (0.3 | ) | | (0.5 | ) | | (0.2 | ) |
| Effective income tax rate | | 9.2 | % | | 16.9 | % | | 8.1 | % | | 17.0 | % |
| |
(a) (a) Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions.
| Regulatory differences for income tax primarily relate to the flow back of excess deferred taxes to customers through the average rate assumption method and the impact of AFUDC - Equity. Quarterly variations primarily relates to the deferral of the flow back of excess deferred taxes in 2018, as a result of pending regulatory decisions. Treatment of most tax reform items was established prior to the first quarter of 2019, resulting in a reduction in deferred amounts. Income tax benefits associated with the flow back of excess deferred credits are offset by corresponding revenue reductions and additional prepaid pension asset amortization. |
Federal Audits — Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows:
|
| | | | | | | |
Tax Year(s)Years | | Expiration |
2009 -— 2013 | | JuneSeptember 2020 |
2014 -— 2016 | | September 2020 |
2017 | | SeptemberJune 2021 |
In 2015, the IRS commenced an examination of tax years 2012 and 2013. In 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy filed a protest with the IRS. As of June 30, 2019, the case has been forwarded to the Office of Appeals andIn April 2020, Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.Appeals reached an agreement and no material adjustments were required.
In 2018, the IRS began an audit of tax years 2014 - 2016. As of June 30, 2019,2020, no adjustments have been proposed.
State Audits — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions and various other state income-based tax returns.
As of June 30, 2019,2020, Xcel Energy’s earliest open tax years (subject to examination by state taxing authorities in its major operating jurisdictions) were as follows:
|
| | | | | | | |
| State | | Year |
| Colorado | | 2009 |
| Minnesota | | 2009 |
| Texas | | 2009 |
| Wisconsin | | 2014 |
In 2018, Wisconsin began an audit of tax years 2014 - 2016. As of June 30, 2019, no2020, 0 material adjustments have been proposed.
•No other state income tax audits were in progress as of June 30, 2019.2020.
Unrecognized Benefits — Unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain, but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment to the taxing authority to an earlier period.
Unrecognized tax benefits -— permanent vs. temporary:
|
| | | | | | | | |
| (Millions of Dollars) | | June 30, 2019 | | Dec. 31, 2018 |
| Unrecognized tax benefit — Permanent tax positions | | $ | 30 |
| | $ | 28 |
|
| Unrecognized tax benefit — Temporary tax positions | | 10 |
| | 9 |
|
| Total unrecognized tax benefit | | $ | 40 |
| | $ | 37 |
|
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | June 30, 2020 | | Dec. 31, 2019 |
| Unrecognized tax benefit — Permanent tax positions | | $ | 36 | | | $ | 35 | |
| Unrecognized tax benefit — Temporary tax positions | | 10 | | | 9 | |
| Total unrecognized tax benefit | | $ | 46 | | | $ | 44 | |
Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:
|
| | | | | | | | |
| (Millions of Dollars) | | June 30, 2019 | | Dec. 31, 2018 |
| NOL and tax credit carryforwards | | $ | (36 | ) | | $ | (35 | ) |
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | June 30, 2020 | | Dec. 31, 2019 |
| NOL and tax credit carryforwards | | $ | (41) | | | $ | (40) | |
Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $25$31 million at June 30, 20192020 and $24$29 million at Dec. 31, 2018.2019.
As the IRS Appeals and federal and state audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $28$23 million in the next 12 months.
Payables for interest related to unrecognized tax benefits were not material and no0 amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 20192020 or Dec. 31, 2018.2019.
Basic EPS was computed by dividing the earnings available to common shareholders by the weighted average number of common shares outstanding. Diluted EPS was computed by dividing the earnings available to common shareholders by the diluted weighted average number of common shares outstanding.
Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate diluted EPS is calculated using the treasury stock method.
Common Stock Equivalents — Xcel Energy Inc. has common stock equivalents related to forward equity agreements and time-based equity compensation awards.
Stock equivalent units granted to Xcel Energy Inc.’s Board of Directors are included in common shares outstanding upon grant date as there is no further service, performance or market condition associated with these awards. Restricted stock issued to employees is included in common shares outstanding when granted.
Share-based compensation arrangements for which there is currently no dilutive impact to EPS include the following:
•Equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions for settlement have been satisfied by the end of the reporting period; and
•Liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement.
Diluted common shares outstanding included common stock equivalents of 0.5 million and 0.7 million for the three and six months ended June 30, 2020, respectively, and 1.8 million and 1.5 million for the three and six months ended June 30, 2019, respectively (0.4 million for the three and six months ended June 30, 2018).respectively.
| | |
| 8. | Fair Value of Financial Assets and Liabilities |
Fair Value Measurements
Accounting guidance for fair value measurements and disclosures provides a single definition of fair value hierarchical framework for measuring assets and liabilities and requires disclosuredisclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance.
•Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.prices;
•Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.inputs; and
•Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.
Specific valuation methods include the following:include:
Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAV.
Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs. The investments in commingled funds may be redeemed for NAV with proper notice. Private equity commingled fund investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate commingled funds’funds investments may be redeemed with proper notice;notice, however, withdrawals may be delayed or discounted as a result of fund illiquidity.
Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.
Interest rate derivatives — Fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
Commodity derivatives — Methods used to measure the fair value of commodity derivative forwards and options generally utilize observable forward prices and volatilities, as well as observable pricing adjustments for specific delivery locations and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations for which pricing is relatively unobservable, or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable inputsforecasts of forward prices and volatilities on a valuation is evaluated and may result in Level 3 classification.
Electric commodity derivatives held by NSP-Minnesota and SPS include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path.
The value of an FTR is derived from, and designed to offset, the cost of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR.
If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of importantcertain inputs to the value of FTRs between auction processes, including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3.
Non-trading monthly FTR settlements are included in fuel and purchased energy cost recovery mechanisms as applicable in each jurisdiction and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of NSP-Minnesota and SPS, the numerous unobservable quantitative inputs pertinent to the value of FTRs are insignificant to the consolidated financial statements of Xcel Energy.statements.
Non-Derivative Fair Value Measurements
The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other investments. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust.
NSP-Minnesota recognizes the costs of funding the decommissioning over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset.
Unrealized gains for the nuclear decommissioning fund were $606$637 million and $450$706 million as of June 30, 20192020 and Dec. 31, 2018,2019, respectively, and unrealized losses were $15$16 million and $45$6 million as of June 30, 20192020 and Dec. 31, 2018,2019, respectively.
Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 2020 | | | | | | | | | | |
| | | | Fair Value | | | | | | | | |
| (Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | NAV | | Total |
Nuclear decommissioning fund (a) | | | | | | | | | | | | |
| Cash equivalents | | $ | 22 | | | $ | 22 | | | $ | — | | | $ | — | | | $ | — | | | $ | 22 | |
| Commingled funds | | 766 | | | — | | | — | | | — | | | 897 | | | 897 | |
| Debt securities | | 513 | | | — | | | 531 | | | 10 | | | — | | | 541 | |
| Equity securities | | 473 | | | 934 | | | 1 | | | — | | | — | | | 935 | |
| Total | | $ | 1,774 | | | $ | 956 | | | $ | 532 | | | $ | 10 | | | $ | 897 | | | $ | 2,395 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | June 30, 2019 |
| | | | | Fair Value |
| (Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | NAV | | Total |
Nuclear decommissioning fund (a) | | | | | | | | | | | | |
| Cash equivalents | | $ | 27 |
| | $ | 27 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 27 |
|
| Commingled funds | | 802 |
| | — |
| | — |
| | — |
| | 988 |
| | 988 |
|
| Debt securities | | 485 |
| | — |
| | 473 |
| | 14 |
| | — |
| | 487 |
|
| Equity securities | | 396 |
| | 798 |
| | 1 |
| | — |
| | — |
| | 799 |
|
| Total | | $ | 1,710 |
| | $ | 825 |
| | $ | 474 |
| | $ | 14 |
| | $ | 988 |
| | $ | 2,301 |
|
| |
(a) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Dec. 31, 2019 | | | | | | | | | | | | | | | Fair Value | | | | | | | | | | (Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | NAV | | Total | Nuclear decommissioning fund (a) | | | | | | | | | | | | | | Cash equivalents | | $ | 33 | | | $ | 33 | | | $ | — | | | $ | — | | | $ | — | | | $ | 33 | | | Commingled funds | | 733 | | | — | | | — | | | — | | | 935 | | | 935 | | | Debt securities | | 489 | | | — | | | 495 | | | 13 | | | — | | | 508 | | | Equity securities | | 485 | | | 962 | | | 2 | | | — | | | — | | | 964 | | | Total | | $ | 1,740 | | | $ | 995 | | | $ | 497 | | | $ | 13 | | | $ | 935 | | | $ | 2,440 | |
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $155 million of equity investments in unconsolidated subsidiaries and $136 million of rabbi trust assets and miscellaneous investments. | Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $145 million of equity investments in unconsolidated subsidiaries and $126 million of rabbi trust assets and miscellaneous investments. |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2018 |
| | | | | Fair Value |
| (Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | NAV | | Total |
Nuclear decommissioning fund (a) | | | | | | | | | | | | |
| Cash equivalents | | $ | 24 |
| | $ | 24 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 24 |
|
| Commingled funds | | 758 |
| | 79 |
| | — |
| | — |
| | 819 |
| | 898 |
|
| Debt securities | | 466 |
| | — |
| | 436 |
| | — |
| | — |
| | 436 |
|
| Equity securities | | 401 |
| | 697 |
| | — |
| | — |
| | — |
| | 697 |
|
| Total | | $ | 1,649 |
| | $ | 800 |
| | $ | 436 |
| | $ | — |
| | $ | 819 |
| | $ | 2,055 |
|
| |
(a)
| Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $141 million of equity investments in unconsolidated subsidiaries and $121 million of rabbi trust assets and miscellaneous investments. |
For the three and six months ended June 30, 2020 and 2019, and 2018, there was nowere immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.
Contractual maturity dates of debt securities in the nuclear decommissioning fund as of June 30, 2019:2020:
|
| | | | | | | | | | | | | | | | | | | | |
| | | Final Contractual Maturity |
| (Millions of Dollars) | | Due in 1 Year or Less | | Due in 1 to 5 Years | | Due in 5 to 10 Years | | Due after 10 Years | | Total |
| Debt securities | | $ | 1 |
| | $ | 122 |
| | $ | 225 |
| | $ | 139 |
| | $ | 487 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Final Contractual Maturity | | | | | | | | |
| (Millions of Dollars) | | Due in 1 Year
or Less | | Due in 1 to 5
Years | | Due in 5 to 10
Years | | Due after 10
Years | | Total |
| Debt securities | | $ | (4) | | | $ | 98 | | | $ | 212 | | | $ | 235 | | | $ | 541 | |
Rabbi Trusts
Xcel Energy has established rabbi trusts to provide partial funding for future distributions of its supplemental executive retirement plan and deferred compensation plan.
Cost and fair value of assets held in rabbi trusts:
|
| | | | | | | | | | | | | | | | | | | | |
| | | June 30, 2019 |
| | | | | Fair Value |
| (Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | Total |
Rabbi Trusts (a) | | | | | | | | | | |
| Cash equivalents | | $ | 13 |
| | $ | 13 |
| | $ | — |
| | $ | — |
| | $ | 13 |
|
| Mutual funds | | 52 |
| | 58 |
| | — |
| | — |
| | 58 |
|
| Total | | $ | 65 |
| | $ | 71 |
| | $ | — |
| | $ | — |
| | $ | 71 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 2020 | | | | | | | | |
| | | | Fair Value | | | | | | |
| (Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | Total |
Rabbi Trusts (a) | | | | | | | | | | |
| Cash equivalents | | $ | 17 | | | $ | 17 | | | $ | — | | | $ | — | | | $ | 17 | |
| Mutual funds | | 57 | | | 61 | | | — | | | — | | | 61 | |
| Total | | $ | 74 | | | $ | 78 | | | $ | — | | | $ | — | | | $ | 78 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Dec. 31, 2019 | | | | | | | | |
| | | | Fair Value | | | | | | |
| (Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | Total |
Rabbi Trusts (a) | | | | | | | | | | |
| Cash equivalents | | $ | 17 | | | $ | 17 | | | $ | — | | | $ | — | | | $ | 17 | |
| Mutual funds | | 57 | | | 65 | | | — | | | — | | | 65 | |
| Total | | $ | 74 | | | $ | 82 | | | $ | — | | | $ | — | | | $ | 82 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2018 |
| | | | | Fair Value |
| (Millions of Dollars) | | Cost | | Level 1 | | Level 2 | | Level 3 | | Total |
Rabbi Trusts (a) | | | | | | | | | | |
| Cash equivalents | | $ | 16 |
| | $ | 16 |
| | $ | — |
| | $ | — |
| | $ | 16 |
|
| Mutual funds | | 52 |
| | 51 |
| | — |
| | — |
| | 51 |
|
| Total | | $ | 68 |
| | $ | 67 |
| | $ | — |
| | $ | — |
| | $ | 67 |
|
(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
Derivative Instruments Fair Value Measurements
Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.
Interest Rate Derivatives — Xcel Energy enters into various instruments that effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.purposes, with changes in fair value prior to settlement recorded as other comprehensive income.
As of June 30, 2019,2020, accumulated other comprehensive loss related to settled interest rate derivatives included $4$5 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings.
As of June 30, 2019,2020. Xcel Energy had 0 unsettled interest rate swaps outstanding with a notional amount of $300 million. These interest rate derivatives were designated as cash flow hedges, and as such, changes in fair value are recorded to other comprehensive income.derivatives.
Wholesale and Commodity Trading Risk — Xcel Energy Inc.’s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Xcel Energy is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in activities governed by this policy.
Commodity Derivatives — Xcel Energy enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, FTRs, vehicle fuel and weather derivatives.
Xcel Energy may enter into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but may not be designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded as other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.
As of June 30, 2019,2020, Xcel Energy had no0 commodity contracts designated as cash flow hedges.
Xcel Energy also enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms.
Gross notional amounts of commodity forwards, options and FTRs:
| | | | | | | | | | | | | | |
(Amounts in Millions) (a)(b) | | June 30, 2020 | | Dec. 31, 2019 |
| Megawatt hours of electricity | | 127 | | | 95 | |
| Million British thermal units of natural gas | | 153 | | | 110 | |
| | | | |
|
| | | | | | |
(Amounts in Millions) (a)(b) | | June 30, 2019 | | Dec. 31, 2018 |
| MWh of electricity | | 134 |
| | 87 |
|
| MMBtu of natural gas | | 95 |
| | 92 |
|
| |
(a)(b)Notional amounts for options included on a gross basis but weighted for the probability of exercise. | Not reflective of net positions in the underlying commodities. |
| |
(b)
| Notional amounts for options included on a gross basis, but are weighted for the probability of exercise. |
Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets. Xcel Energy’s utility subsidiaries’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to their wholesale, trading and non-trading commodity activities.
As of June 30, 2019, six2020, 6 of Xcel Energy’s 10 most significant counterparties for these activities, comprising $72$152 million, or 36%57%, of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings. ThreeNaN of the 10 most significant counterparties, comprising $21$36 million, or 11%14%, of this credit exposure, were not rated by these external agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade. OneNaN of these significant counterparties, comprising $8$13 million or 4%5% of this credit exposure, had credit quality less than investment grade, based on externalinternal analysis. Nine NaN of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.
Impact of derivative activity:
|
| | | | | | | | |
| | | Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: |
| (Millions of Dollars) | | Accumulated
Other
Comprehensive Loss | | Regulatory
(Assets) and Liabilities |
| Three Months Ended June 30, 2019 | | | | |
| Derivatives designated as cash flow hedges | | | | |
| Interest rate | | $ | (13 | ) | | $ | — |
|
| Total | | $ | (13 | ) | | $ | — |
|
| Other derivative instruments | | | | |
| Electric commodity | | $ | — |
| | $ | 26 |
|
| Natural gas commodity | | — |
| | (2 | ) |
| Total | | $ | — |
| | $ | 24 |
|
| | | | | |
| Six Months Ended June 30, 2019 | | | | |
| Derivatives designated as cash flow hedges | | | | |
| Interest rate | | $ | (22 | ) | | $ | — |
|
| Total | | $ | (22 | ) | | $ | — |
|
| Other derivative instruments | | | | |
| Electric commodity | | $ | — |
| | $ | 4 |
|
| Natural gas commodity | | — |
| | (2 | ) |
| Total | | $ | — |
| | $ | 2 |
|
| | | | | |
| Three Months Ended June 30, 2018 | | | | |
| Other derivative instruments | | | | |
| Electric commodity | | $ | — |
| | $ | 37 |
|
| Total | | $ | — |
| | $ | 37 |
|
| | | | | |
| Six Months Ended June 30, 2018 | | | | |
| Other derivative instruments | | | | |
| Electric commodity | | $ | — |
| | $ | 8 |
|
| Total | | $ | — |
| | $ | 8 |
|
|
| | | | | | | | | | | | |
| | Pre-Tax (Gains) Losses Reclassified into Income During the Period from: | | Pre-Tax Gains (Losses) Recognized
During the Period in Income | |
| (Millions of Dollars) | Accumulated
Other
Comprehensive Loss | | Regulatory
Assets and (Liabilities) | | |
| Three Months Ended June 30, 2019 | | | | | | |
| Derivatives designated as cash flow hedges | | | | | | |
| Interest rate | $ | 1 |
| (a) | $ | — |
| | $ | — |
| |
| Total | $ | 1 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | |
| Commodity trading | $ | — |
| | $ | — |
| | $ | 5 |
| (b) |
| Total | $ | — |
| | $ | — |
| | $ | 5 |
| |
| | | | | | | |
| Six Months Ended June 30, 2019 | | | | | | |
| Derivatives designated as cash flow hedges | | | | | | |
| Interest rate | $ | 2 |
| (a) | $ | — |
| | $ | — |
| |
| Total | $ | 2 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | |
| Commodity trading | $ | — |
| | $ | — |
| | $ | 4 |
| (b) |
| Electric commodity | — |
| | 1 |
| (c) | — |
| |
| Natural gas commodity | — |
| | (1 | ) | (d) | (4 | ) | (d) |
| Total | $ | — |
| | $ | — |
| | $ | — |
| |
| | | | | | | |
| Three Months Ended June 30, 2018 | | | | | | |
| Derivatives designated as cash flow hedges | | | | | | |
| Interest rate | $ | 1 |
| (a) | $ | — |
| | $ | — |
| |
| Total | $ | 1 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | |
| Commodity trading | $ | — |
| | $ | — |
| | $ | 2 |
| (b) |
| Electric commodity | — |
| | (3 | ) | (c) | — |
| |
| Total | $ | — |
| | $ | (3 | ) | | $ | 2 |
| |
| | | | | | | |
| Six Months Ended June 30, 2018 | | | | | | |
| Derivatives designated as cash flow hedges | | | | | | |
| Interest rate | $ | 1 |
| (a) | $ | — |
| | $ | — |
| |
| Total | $ | 1 |
| | $ | — |
| | $ | — |
| |
| Other derivative instruments | | | | | | |
| Commodity trading | $ | — |
| | $ | — |
| | $ | 10 |
| (b) |
| Natural gas commodity | — |
| | 2 |
| (d) | (2 | ) | (d) |
| Total | $ | — |
| | $ | 2 |
| | $ | 8 |
| |
| | | | | | | | | | | | | | |
(a)
| Recorded to interest charges. |
Pre-Tax Fair Value
Gains (Losses) Recognized
During the Period in: | | |
(b)(Millions of Dollars)
| Recorded to electric operating revenues. Portions of these gains | Accumulated
Other
Comprehensive Loss | | Regulatory
(Assets) and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.Liabilities |
| Three Months Ended June 30, 2020 | | | | |
(c)
| Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. |
| | |
(d)
| Amounts for both the three and six months ended | | | |
| | | | |
| Other derivative instruments | | | | |
| | | | |
| Natural gas commodity | | $ | — | | | $ | (3) | |
| Total | | $ | — | | | $ | (3) | |
| | | | |
Six Months Ended June 30, 2019 included no settlement gains or losses on derivatives entered to mitigate natural2020 | | | | |
| Derivatives designated as cash flow hedges | | | | |
| Interest rate | | $ | (13) | | | $ | — | |
| Total | | $ | (13) | | | $ | — | |
| Other derivative instruments | | | | |
| | | | |
Natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Amounts for the three and six months endedcommodity | | $ | — | | | $ | (3) | |
| Total | | $ | — | | | $ | (3) | |
| | | | |
Three Months Ended June 30, 2018 included no such settlement gains or losses and $1 million of such settlement losses, respectively. Remaining settlement losses for the three and six months ended2019 | | | | |
| Derivatives designated as cash flow hedges | | | | |
| Interest rate | | $ | (13) | | | $ | — | |
| Total | | $ | (13) | | | $ | — | |
| Other derivative instruments | | | | |
| Electric commodity | | $ | — | | | $ | 26 | |
| Natural gas commodity | | — | | | (2) | |
| Total | | $ | — | | | $ | 24 | |
| | | | |
Six Months Ended June 30, 2019 and 2018 related to natural | | | | |
| Derivatives designated as cash flow hedges | | | | |
| Interest rate | | $ | (22) | | | $ | — | |
| Total | | $ | (22) | | | $ | — | |
| Other derivative instruments | | | | |
| Electric commodity | | $ | — | | | $ | 4 | |
Natural gas operations and were recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate.commodity | | — | | | (2) | |
| Total | | $ | — | | | $ | 2 | |
17 | | | | | | | | | | | | | | | | | | | | |
| Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from: | | | | Pre-Tax Gains
(Losses) Recognized
During the Period in Income | |
| (Millions of Dollars) | Accumulated
Other
Comprehensive Loss | | Regulatory
Assets and (Liabilities) | | | |
| Three Months Ended June 30, 2020 | | | | | | |
| Derivatives designated as cash flow hedges | | | | | | |
| Interest rate | $ | 2 | | (a) | $ | — | | | $ | — | | |
| Total | $ | 2 | | | $ | — | | | $ | — | | |
| Other derivative instruments | | | | | | |
| Commodity trading | $ | — | | | $ | — | | | $ | (3) | | (b) |
| Electric commodity | — | | | (3) | | (c) | — | | |
| Total | $ | — | | | $ | (3) | | | $ | (3) | | |
| | | | | | |
| Six Months Ended June 30, 2020 | | | | | | |
| Derivatives designated as cash flow hedges | | | | | | |
| Interest rate | $ | 4 | | (a) | $ | — | | | $ | — | | |
| Total | $ | 4 | | | $ | — | | | $ | — | | |
| Other derivative instruments | | | | | | |
| Commodity trading | $ | — | | | $ | — | | | $ | (5) | | (b) |
| Electric commodity | — | | | (7) | | (c) | — | | |
| Natural gas commodity | — | | | 5 | | (d) | (6) | | (d) |
| Total | $ | — | | | $ | (2) | | | $ | (11) | | |
| | | | | | |
| Three Months Ended June 30, 2019 | | | | | | |
| Derivatives designated as cash flow hedges | | | | | | |
| Interest rate | $ | 1 | | (a) | $ | — | | | $ | — | | |
| Total | $ | 1 | | | $ | — | | | $ | — | | |
| Other derivative instruments | | | | | | |
| Commodity trading | $ | — | | | $ | — | | | $ | 5 | | (b) |
| Total | $ | — | | | $ | — | | | $ | 5 | | |
| | | | | | |
| Six Months Ended June 30, 2019 | | | | | | |
| Derivatives designated as cash flow hedges | | | | | | |
| Interest rate | $ | 2 | | (a) | $ | — | | | $ | — | | |
| Total | $ | 2 | | | $ | — | | | $ | — | | |
| Other derivative instruments | | | | | | |
| Commodity trading | $ | — | | | $ | — | | | $ | 4 | | (b) |
| Electric commodity | — | | | 1 | | (c) | — | | |
| Natural gas commodity | — | | | (1) | | (d) | (4) | | (d) |
| Total | $ | — | | | $ | — | | | $ | — | | |
(a)Recorded to interest charges.
(b)Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.
(c)Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.
(d)Amounts for both the three and six months ended June 30, 2020 and 2019 included 0 settlement gains or losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Remaining settlement losses for both the three and six months ended June 30, 2020 and 2019 related to natural gas operations and were recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate.
Xcel Energy had no0 derivative instruments designated as fair value hedges during the three and six months ended June 30, 20192020 and 2018.2019.
Credit Related Contingent Features —��� Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as normal purchase-normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies, or for cross default contractual provisions if there was a failure under other financing arrangements related to payment terms or other covenants.
As of June 30, 20192020 and Dec. 31, 2018, $62019, there were $8 million and less than $1$7 million of derivative instruments were in a liability position with such underlying contract provisions, respectively, with no offsetting positions or posted collateral.
respectively. Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. Provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired. Xcel Energy had less than $1 million of0 collateral posted related to adequate assurance clauses in derivative contracts as of June 30, 20192020 and Dec. 31, 20182019.
Recurring Fair Value Measurements — Derivative assets and liabilities measured at fair value on a recurring basis:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 2020 | | | | | | | | | | | | Dec. 31, 2019 | | | | | | | | | | |
| | Fair Value | | | | | | Fair Value Total | | Netting (a) | | Total | | Fair Value | | | | | | Fair Value Total | | Netting (a) | | Total |
| (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | | | | | | | Level 1 | | Level 2 | | Level 3 | | | | | | |
| Current derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 5 | | | $ | 52 | | | $ | 11 | | | $ | 68 | | | $ | (50) | | | $ | 18 | | | $ | 3 | | | $ | 51 | | | $ | 24 | | | $ | 78 | | | $ | (52) | | | $ | 26 | |
| Electric commodity | | — | | | — | | | 46 | | | 46 | | | (2) | | | 44 | | | — | | | — | | | 21 | | | 21 | | | (1) | | | 20 | |
| Natural gas commodity | | — | | | 7 | | | — | | | 7 | | | — | | | 7 | | | — | | | 6 | | | — | | | 6 | | | — | | | 6 | |
| Total current derivative assets | | $ | 5 | | | $ | 59 | | | $ | 57 | | | $ | 121 | | | $ | (52) | | | 69 | | | $ | 3 | | | $ | 57 | | | $ | 45 | | | $ | 105 | | | $ | (53) | | | 52 | |
PPAs (b) | | | | | | | | | | | | 3 | | | | | | | | | | | | | 3 | |
| Current derivative instruments | | | | | | | | | | | | $ | 72 | | | | | | | | | | | | | $ | 55 | |
| Noncurrent derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 11 | | | $ | 42 | | | $ | 23 | | | $ | 76 | | | $ | (49) | | | $ | 27 | | | $ | 9 | | | $ | 38 | | | $ | 7 | | | $ | 54 | | | $ | (45) | | | $ | 9 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| Total noncurrent derivative assets | | $ | 11 | | | $ | 42 | | | $ | 23 | | | $ | 76 | | | $ | (49) | | | 27 | | | $ | 9 | | | $ | 38 | | | $ | 7 | | | $ | 54 | | | $ | (45) | | | 9 | |
PPAs (b) | | | | | | | | | | | | 11 | | | | | | | | | | | | | 13 | |
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 38 | | | | | | | | | | | | | $ | 22 | |
| | | | | June 30, 2019 | | Dec. 31, 2018 | | June 30, 2020 | | | Dec. 31, 2019 | |
| | | Fair Value | | Fair Value Total | | Netting (a) | | Total | | Fair Value | | Fair Value Total | | Netting (a) | | Total | | Fair Value | | | Fair Value Total | | Netting (a) | | Total | | Fair Value | | | Fair Value Total | | Netting (a) | | Total |
| (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Level 1 | | Level 2 | | Level 3 | | (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | | | | | | | Level 1 | | Level 2 | | Level 3 | | | | | | | Netting (a) |
| Current derivative assets | | | | | | | | | | | | | | | | | | | | | | | | | |
| Current derivative liabilities | | Current derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| | Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | | Other derivative instruments: | |
| Commodity trading | | $ | 6 |
| | $ | 84 |
| | $ | 19 |
| | $ | 109 |
| | $ | (64 | ) | | $ | 45 |
| | $ | 4 |
| | $ | 92 |
| | $ | 2 |
| | $ | 98 |
| | $ | (44 | ) | | $ | 54 |
| Commodity trading | | $ | 6 | | | $ | 54 | | | $ | 8 | | | $ | 68 | | | $ | (50) | | | $ | 18 | | | $ | 4 | | | $ | 59 | | | $ | 15 | | | $ | 78 | | | $ | (63) | | | $ | 15 | |
| Electric commodity | | — |
| | — |
| | 38 |
| | 38 |
| | (1 | ) | | 37 |
| | — |
| | — |
| | 25 |
| | 25 |
| | — |
| | 25 |
| Electric commodity | | — | | | — | | | 2 | | | 2 | | | (2) | | | — | | | — | | | — | | | 1 | | | 1 | | | (1) | | | — | |
| Natural gas commodity | | — |
| | 1 |
| | — |
| | 1 |
| | — |
| | 1 |
| | — |
| | 4 |
| | — |
| | 4 |
| | — |
| | 4 |
| Natural gas commodity | | — | | | 5 | | | — | | | 5 | | | — | | | 5 | | | — | | | 5 | | | — | | | 5 | | | — | | | 5 | |
| Total current derivative assets | | $ | 6 |
| | $ | 85 |
| | $ | 57 |
| | $ | 148 |
| | $ | (65 | ) | | 83 |
| | $ | 4 |
| | $ | 96 |
| | $ | 27 |
| | $ | 127 |
| | $ | (44 | ) | | 83 |
| |
| Total current derivative liabilities | | Total current derivative liabilities | | $ | 6 | | | $ | 59 | | | $ | 10 | | | $ | 75 | | | $ | (52) | | | 23 | | | $ | 4 | | | $ | 64 | | | $ | 16 | | | $ | 84 | | | $ | (64) | | | 20 | |
PPAs (b) | | | | | | | | | | | | 3 |
| | | | | | | | | | | | 4 |
| PPAs (b) | | | | | | | | | | | | 17 | | | | | | | | | | | | | 18 | |
| Current derivative instruments | | | | | | | | | | | | $ | 86 |
| | | | | | | | | | | | $ | 87 |
| Current derivative instruments | | $ | 40 | | | $ | 38 | |
| Noncurrent derivative assets | | | | | | | | | | | | | | | | | | | | | | | | | |
| Noncurrent derivative liabilities | | Noncurrent derivative liabilities | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | | Other derivative instruments: | |
| Commodity trading | | $ | 1 |
| | $ | 48 |
| | $ | — |
| | $ | 49 |
| | $ | (40 | ) | | $ | 9 |
| | $ | — |
| | $ | 27 |
| | $ | 5 |
| | $ | 32 |
| | $ | (14 | ) | | $ | 18 |
| Commodity trading | | $ | 4 | | | $ | 95 | | | $ | 36 | | | $ | 135 | | | $ | (20) | | | $ | 115 | | | $ | 2 | | | $ | 79 | | | $ | 32 | | | $ | 113 | | | $ | (13) | | | $ | 100 | |
| Total noncurrent derivative assets | | $ | 1 |
| | $ | 48 |
| | $ | — |
| | $ | 49 |
| | $ | (40 | ) | | 9 |
| | $ | — |
| | $ | 27 |
| | $ | 5 |
| | $ | 32 |
| | $ | (14 | ) | | 18 |
| |
| Total noncurrent derivative liabilities | | Total noncurrent derivative liabilities | | $ | 4 | | | $ | 95 | | | $ | 36 | | | $ | 135 | | | $ | (20) | | | 115 | | | $ | 2 | | | $ | 79 | | | $ | 32 | | | $ | 113 | | | $ | (13) | | | 100 | |
PPAs (b) | | | | | | | | | | | | 14 |
| | | | | | | | | | | | 16 |
| PPAs (b) | | | | | | | | | | | | 66 | | | | | | | | | | | | | 75 | |
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 23 |
| | | | | | | | | | | | $ | 34 |
| Noncurrent derivative instruments | | $ | 181 | | | $ | 175 | |
(a)
(b)During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, contracts are no longer adjusted to fair value and the previous carrying value of these contracts is being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | June 30, 2019 | | Dec. 31, 2018 |
| | | Fair Value | | Fair Value Total | | Netting (a) | | Total | | Fair Value | | Fair Value Total | | Netting (a) | | Total |
| (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | | | | Level 1 | | Level 2 | | Level 3 | | | |
| Current derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| Derivatives designated as cash flow hedges: | | | | | | | | | | | | | | | | | | | | | | | | |
| Interest rate | | $ | — |
| | $ | 28 |
| | $ | — |
| | $ | 28 |
| | $ | — |
| | $ | 28 |
| | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | 7 |
|
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | 7 |
| | 75 |
| | 15 |
| | 97 |
| | (77 | ) | | 20 |
| | 4 |
| | 88 |
| | 2 |
| | 94 |
| | (60 | ) | | 34 |
|
| Electric commodity | | — |
| | — |
| | 1 |
| | 1 |
| | (1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total current derivative liabilities | | $ | 7 |
| | $ | 103 |
| | $ | 16 |
| | $ | 126 |
| | $ | (78 | ) | | 48 |
| | $ | 4 |
| | $ | 95 |
| | $ | 2 |
| | $ | 101 |
| | $ | (60 | ) | | 41 |
|
PPAs (b) | | | | | | | | | | | | 18 |
| | | | | | | | | | | | 20 |
|
| Current derivative instruments | | | | | | | | | | | | $ | 66 |
| | | | | | | | | | | | $ | 61 |
|
| Noncurrent derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity trading | | $ | 1 |
| | $ | 31 |
| | $ | 13 |
| | $ | 45 |
| | $ | (8 | ) | | $ | 37 |
| | $ | — |
| | $ | 18 |
| | $ | 1 |
| | $ | 19 |
| | $ | 17 |
| | $ | 36 |
|
| Total noncurrent derivative liabilities | | $ | 1 |
| | $ | 31 |
| | $ | 13 |
| | $ | 45 |
| | $ | (8 | ) | | 37 |
| | $ | — |
| | $ | 18 |
| | $ | 1 |
| | $ | 19 |
| | $ | 17 |
| | 36 |
|
PPAs (b) | | | | | | | | | | | | 84 |
| | | | | | | | | | | | 93 |
|
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 121 |
| | | | | | | | | | | | $ | 129 |
|
| |
(a)
| Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at June 30, 2019 and Dec. 31, 2018. At both June 30, 2019 and Dec. 31, 2018, derivative assets and liabilities include $32 million of obligations to return cash collateral. At June 30, 2019 and Dec. 31, 2018, derivative assets and liabilities include rights to reclaim cash collateral of $13 million and $15 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. |
| |
(b)
| During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, contracts are no longer adjusted to fair value and the previous carrying value of these contracts is being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. |
Changes in Level 3 commodity derivatives:
| | | | | | | | | | | | | | |
| | Three Months Ended June 30 | | |
| (Millions of Dollars) | | 2020 | | 2019 |
| Balance at April 1 | | $ | 4 | | | $ | (7) | |
| Purchases | | 37 | | | 34 | |
| Settlements | | (25) | | | (16) | |
| Net transactions recorded during the period: | | | | |
Gains recognized in earnings (a) | | 9 | | | 7 | |
| Net gains recognized as regulatory assets and liabilities | | 9 | | | 10 | |
| Balance at June 30 | | $ | 34 | | | $ | 28 | |
| | | | |
| | Six Months Ended June 30 | | |
| (Millions of Dollars) | | 2020 | | 2019 |
| Balance at Jan. 1 | | $ | 4 | | | $ | 29 | |
| Purchases | | 49 | | | 38 | |
| Settlements | | (42) | | | (27) | |
| Net transactions recorded during the period: | | | | |
Gains (losses) recognized in earnings (a) | | 14 | | | (11) | |
| Net gains (losses) recognized as regulatory assets and liabilities | | 9 | | | (1) | |
| Balance at June 30 | | $ | 34 | | | $ | 28 | |
|
| | | | | | | | |
| | | | | |
| | | Three Months Ended June 30 |
| (Millions of Dollars) | | 2019 | | 2018 |
| Balance at April 1 | | $ | (7 | ) | | $ | 19 |
|
| Purchases | | 34 |
| | 45 |
|
| Settlements | | (16 | ) | | (20 | ) |
| Net transactions recorded during the period: | | | | |
|
Gains (losses) recognized in earnings (a) | | 7 |
| | (2 | ) |
| Net gains recognized as regulatory assets and liabilities | | 10 |
| | 22 |
|
| Balance at June 30 | | $ | 28 |
| | $ | 64 |
|
| | | | | |
| | | Six Months Ended June 30 |
| (Millions of Dollars) | | 2019 | | 2018 |
| Balance at Jan. 1 | | $ | 29 |
| | $ | 35 |
|
| Purchases | | 38 |
| | 46 |
|
| Settlements | | (27 | ) | | (32 | ) |
| Net transactions recorded during the period: | | | | |
Losses recognized in earnings (a) | | (11 | ) | | — |
|
| Net (losses) gains recognized as regulatory assets and liabilities | | (1 | ) | | 15 |
|
| Balance at June 30 | | $ | 28 |
| | $ | 64 |
|
| |
(a)(a)Amounts relate to commodity derivatives held at the end of the period.
| These amounts relate to commodity derivatives held at the end of the period. |
Xcel Energy recognizes transfers between fair value hierarchy levels as of the beginning of each period. There were no0 transfers of amounts between levels for derivative instruments for the three and six months ended June 30, 20192020 and 2018.2019.
Fair Value of Long-Term Debt
Other financial instruments for which the carrying amount did not equal fair value:
|
| | | | | | | | | | | | | | | | |
| | | June 30, 2019 | | Dec. 31, 2018 |
| (Millions of Dollars) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| Long-term debt, including current portion | | $ | 16,549 |
| | $ | 18,218 |
| | $ | 16,209 |
| | $ | 16,755 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 2020 | | | | Dec. 31, 2019 | | |
| (Millions of Dollars) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| Long-term debt, including current portion | | $ | 20,564 | | | $ | 24,327 | | | $ | 18,109 | | | $ | 20,227 | |
Fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of June 30, 20192020 and Dec. 31, 2018,2019, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.
| | |
| 9. Benefit Plans and Other Postretirement Benefits |
Components of Net Periodic Benefit Cost (Credit)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30 | | | | | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
| (Millions of Dollars) | | Pension Benefits | | | | Postretirement Health
Care Benefits | | |
| Service cost | | $ | 24 | | | $ | 22 | | | $ | — | | | $ | — | |
Interest cost (a) | | 31 | | | 36 | | | 5 | | | 6 | |
Expected return on plan assets (a) | | (52) | | | (51) | | | (5) | | | (5) | |
Amortization of prior service credit (a) | | (1) | | | (1) | | | (2) | | | (3) | |
Amortization of net loss (a) | | 25 | | | 22 | | | 1 | | | 1 | |
| | | | | | | | |
| Net periodic benefit cost (credit) | | 27 | | | 28 | | | (1) | | | (1) | |
Credits not recognized due to effects
of regulation | | 1 | | | 1 | | | 1 | | | — | |
| Net benefit cost (credit) recognized for financial reporting | | $ | 28 | | | $ | 29 | | | $ | — | | | $ | (1) | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended June 30 |
| | | 2019 | | 2018 | | 2019 | | 2018 |
| (Millions of Dollars) | | Pension Benefits | | Postretirement Health
Care Benefits |
| Service cost | | $ | 22 |
| | $ | 24 |
| | $ | — |
| | $ | 1 |
|
Interest cost (a) | | 36 |
| | 33 |
| | 6 |
| | 5 |
|
Expected return on plan assets (a) | | (51 | ) | | (52 | ) | | (5 | ) | | (6 | ) |
Amortization of prior service credit (a) | | (1 | ) | | (1 | ) | | (3 | ) | | (3 | ) |
Amortization of net loss (a) | | 22 |
| | 27 |
| | 1 |
| | 2 |
|
| Net periodic benefit cost (credit) | | 28 |
| | 31 |
| | (1 | ) | | (1 | ) |
| Credits (costs) not recognized due to the effects of regulation | | 1 |
| | (1 | ) | | — |
| | — |
|
| Net benefit cost (credit) recognized for financial reporting | | $ | 29 |
| | $ | 30 |
| | $ | (1 | ) | | $ | (1 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30 | | | | | | |
| | 2020 | | 2019 | | 2020 | | 2019 |
| (Millions of Dollars) | | Pension Benefits | | | | Postretirement Health
Care Benefits | | |
| Service cost | | $ | 45 | | | $ | 43 | | | $ | 1 | | | $ | 1 | |
Interest cost (a) | | 68 | | | 72 | | | 9 | | | 11 | |
Expected return on plan assets (a) | | (103) | | | (102) | | | (10) | | | (11) | |
Amortization of prior service credit (a) | | (2) | | | (2) | | | (4) | | | (5) | |
Amortization of net loss (a) | | 47 | | | 44 | | | 2 | | | 3 | |
| Net periodic benefit cost (credit) | | 55 | | | 55 | | | (2) | | | (1) | |
Credits not recognized due to effects
of regulation | | 2 | | | 2 | | | 1 | | | 1 | |
| Net benefit cost (credit) recognized for financial reporting | | $ | 57 | | | $ | 57 | | | $ | (1) | | | $ | — | |
|
| | | | | | | | | | | | | | | | |
| | | Six Months Ended June 30 |
| | | 2019 | | 2018 | | 2019 | | 2018 |
| (Millions of Dollars) | | Pension Benefits | | Postretirement Health
Care Benefits |
| Service cost | | $ | 43 |
| | $ | 47 |
| | $ | 1 |
| | $ | 1 |
|
Interest cost (a) | | 72 |
| | 67 |
| | 11 |
| | 11 |
|
Expected return on plan assets (a) | | (102 | ) | | (104 | ) | | (11 | ) | | (13 | ) |
Amortization of prior service credit (a) | | (2 | ) | | (2 | ) | | (5 | ) | | (5 | ) |
Amortization of net loss (a) | | 44 |
| | 55 |
| | 3 |
| | 3 |
|
| Net periodic benefit cost (credit) | | 55 |
| | 63 |
| | (1 | ) | | (3 | ) |
| Credits (costs) not recognized due to the effects of regulation | | 2 |
| | (2 | ) | | 1 |
| | — |
|
| Net benefit cost (credit) recognized for financial reporting | | $ | 57 |
| | $ | 61 |
| | $ | — |
| | $ | (3 | ) |
| |
(a) (a) Components of net periodic cost other than the service cost component are included in the line item “other (expense) income, net” in the consolidated statement of income or capitalized on the consolidated balance sheet as a regulatory asset.
| Components of net periodic cost other than the service cost component are included in the line item “other expense, net” in the consolidated statement of income or capitalized on the consolidated balance sheet as a regulatory asset. |
In January 2019,2020, contributions of $150 million were made across four4 of Xcel Energy’s pension plans. On July 1, 2019, Xcel Energy made a $4 million contribution to the Xcel Energy Inc. Non-Bargaining Pension Plan (South) and does not expect any additional pension contributions during 2019.2020.
| | |
| 10. Commitments and Contingencies |
The following include commitments, contingencies and unresolved contingencies that are material to Xcel Energy’s financial position.
Legal
Xcel Energy is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.
Xcel Energy has concluded that a loss is remote for both remaining lawsuits.
Line Extension Disputes — In December 2015, the DRC filed a lawsuit seeking monetary damages in the Denver District Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric and gas service agreements. The dispute involves claims by over fifty developers. In February 2018, the Colorado Supreme Court denied DRC’s petition to appeal the Denver District Court’s dismissal of the lawsuit, effectively terminating this litigation. However, in January 2018, DRC filed a new lawsuit in Boulder County District Court, asserting a single claim that PSCo was required to file its line extension agreements with the CPUC but failed to do so.
This claim is similar to the arguments previously raised by DRC. PSCo filed a motion to dismiss this claim, which was granted in May 2018. DRC subsequently filed an appeal to the Colorado Court of Appeals. Briefs have been filed and it is uncertain when a decision will be rendered.
PSCo has concluded that a loss is remote with respect to both of these matters as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. If a loss were sustained, PSCo believes it would be allowed to recover costs through traditional regulatory mechanisms. Amount or range in dispute is presently unknown and no accrual has been recorded for this matter.
Rate Matters
MEC Transactions — In January 2020, Xcel Energy, Inc. purchased MEC, a 760 MW natural gas combined cycle facility, for approximately $650 million from Southern Power Company (a subsidiary of Southern Company).
In July 2020, Xcel Energy sold MEC to Southwest Generation for $680 million, subject to working capital adjustments. Proceeds from the sale will primarily be used to reduce Xcel Energy’s overall financing needs.
The assets and liabilities of MEC, including plant assets and working capital, were classified as held for sale at June 30, 2020 pending the sale of the facility in July 2020. Amounts included in the consolidated balance sheet were classified as follows:
| | | | | | | | |
| (Millions of Dollars) | | June 30, 2020 |
| | |
| Prepayments and other current assets | | $ | 24 | |
| Other assets | | 644 | |
| Total assets | | 668 | |
| | |
| Other current liabilities | | 2 | |
| Other deferred credits and other liabilities | | 9 | |
| Total liabilities | | $ | 11 | |
NSP-Minnesota — Sherco — In NSP-Minnesota’s 2013 fuel reconciliation filing, the MPUC made recovery of replacement power costs associated with the 2011 incident at its Sherco Unit 3 plant provisional and subject to further review following conclusion of litigation commenced by NSP-Minnesota, SMMPA (Co-owner of Sherco Unit 3) and insurance companies against GE.
In 2018, NSP-Minnesota and SMMPA reached a settlement with GE. NSP-Minnesota has notified the MPUC of its proposal to refund the GE settlement proceeds back to customers through the FCA.
The insurance providers continued their litigation against GE and the case went to trial.
In 2018, GE prevailed in the lawsuit with the insurance companies, however, the jury found comparable fault, finding that GE was 52% and NSP-Minnesota was 48% at fault. At that point in the litigation, NSP-Minnesota was no longer involved in the case and was not present to make arguments about its role in the event. The specific issue leading to the fault apportionment was also not before the jury and not relevant to the outcome of the trial.
In January 2019, the DOC recommended that NSP-Minnesota refund $20 million of previously recovered purchased power costs to its customers, based on the jury’s apportionment of fault. The OAG recommended the MPUC withhold any decision until the underlying litigation by the insurance providers (currently under appeal) is concluded. The DOC subsequently agreedfiled comments agreeing with the OAG’s recommendation to withhold a decision pending the outcome of any appeals. NSP-Minnesota filed reply comments arguing that the DOC recommendations are without merit and that it acted prudently in operating the plant and its settlement with GE was reasonable.
In March 2019, the MPUC approved NSP-Minnesota’s proposal to refund the GE settlement proceeds back to customers through the FCA. It also decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of the pending litigation between GE and NSP-Minnesota’s insurers. The lower court’s decision was affirmed on appeal. In March 2020, NSP-Minnesota’s insurers filed a petition seeking additional review by the Minnesota Supreme Court.
On April 28, 2020, the Minnesota Supreme Court denied the insurers’ petition for further review, ending the litigation. In accordance with a prior MPUC order, NSP-Minnesota will now make a compliance filing on Aug. 21, 2020, detailing all costs that resulted from the outage and all insurance recoveries received by NSP-Minnesota in connection with the outage. The MPUC has indicated it intends to review the prudence of the Company’s actions and costs in connection with the outage now that the ligation is complete. The MPUC, however, has not specified what process it will use to complete that review.
Westmoreland Arbitration —On Nov. 14, 2014, certain insurers for Westmoreland Coal Company filed an arbitration demand against NSP-Minnesota and other entities (SMMPA and Western Fuels Association), seeking recovery of alleged business losses following the Nov. 19, 2011 incident involving a failure of a low-pressure turbine in Sherco Unit 3. The Westmoreland insurers claim NSP-Minnesota’s invocation of the force majeure clause of the applicable coal supply agreement to stop the supply of coal was improper because the incident was allegedly caused by NSP-Minnesota’s failure to conform to industry maintenance standards. Westmoreland’s insurers quantified their losses as approximately $36 million.
All parties tolled the arbitration pending resolution of a separate lawsuit brought by NSP-Minnesota, SMMPA, and their insurers against various GE entities based on the inspection and maintenance advice GE provided for Sherco Unit 3. That litigation has been resolved and notice of resolution was served July 6, 2020, triggering the arbitration to resume. NSP-Minnesota denies the claims asserted by the Westmoreland insurers, believes it properly stopped the supply of coal based upon the force majeure provision in the coal supply agreement and intends to defend the matter. It is uncertain when a final resolution will occur, but it is unlikely that an arbitration hearing will take place before 2021. At June 30, 2020, a reasonable estimate of the damages or range of damages cannot be determined.
MISO ROE Complaints — In November 2013 and February 2015, customers filed complaints against MISO TOs including NSP-Minnesota and NSP-Wisconsin.
The first complaint argued for a reduction in the base ROE in MISO transmission formula rates from 12.38% to 9.15%, and removal of ROE adders (including those for RTO membership). The second complaint sought to reduce base ROE from 12.38% to 8.67%.
In September 2016, the FERC issued an order granting a 10.32% base ROE (10.82% with the RTO adder) effective for the first complaint period of Nov. 12, 2013 to Feb. 11, 2015 and subsequent to the date of the order. The D.C. Circuit subsequently vacated and remanded FERC Opinion No. 531, which had established the ROE methodology on which the September 2016 FERC order was based.
On March 21, 2019, the FERC announced a NOI seeking public comments on whether, and if so how,refunds to revise ROE policies in light of the D.C. Circuit Court decision. FERC also initiated a NOI on whether to revise its policies on incentives for electric transmission investments, including the RTO membership incentive. Initial comments on both NOIs were due in June 2019, with reply comments due in the third quarter of 2019, pending further FERC action as early as the second half of 2019.customers.
SPP OATT Upgrade Costs — Under the SPP OATT, costs of transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade. SPP had not been charging its customers for these upgrades, even though the SPP OATT had allowed SPP to do so since 2008. In 2016, the FERC granted SPP’s request to recover these previously unbilled charges and SPP subsequently billed SPS approximately $13 million.
In July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP the right to recover these previously unbilled charges was remanded to the FERC. In February 2019, the FERC reversed its 2016 decision and ordered SPP to refund the charges retroactively collected from its transmission customers, including SPS, related to periods before Sept.September 2015.
In April 2019, several parties, includingMarch 2020, SPP and Oklahoma Gas & Electric separately filed requestspetitions for rehearing. The timingreview of a FERC response toFERC’s orders at the rehearing requests is uncertain.D.C. Circuit. SPS has intervened in both appeals in support of FERC. Any refunds received by SPS are expected to be given back to SPS customers through future rates.
In October 2017, SPS filed a separate related complaint against SPP asserting that SPP has assessed upgrade charges to SPS in violation of the SPP OATT. In March 2018, FERC issued an order denying the SPS complaint in its entirety, and finding SPP’s calculations to be consistent with the SPS Tariff. SPS filed a request for rehearing in April 2018. The FERC grantedissued a tolling order granting a rehearing for further consideration in May 2018. The timing of FERC action on the SPS rehearing is uncertain. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the amounts through future SPS customer rates.
In June 2020, the D.C. Circuit issued a decision in an unrelated proceeding (Allegheny Defense Project v. FERC), which held that FERC’s longstanding use of tolling orders to extend FERC’s deadline to act on the merits of requests for rehearing is improper. The effect on this decision on tolling orders previously issued by FERC is unclear. Environmental
MGP, Landfill and Disposal Sites
Ashland MGP Site — NSP-Wisconsin was named a responsible party for contamination at the Ashland/Northern States Power Lakefront Superfund Site (the Site) in Ashland, Wisconsin. Remediation and restoration activities are anticipated to bewas completed in 2019 and groundwaterrestoration activities were completed in 2020. Groundwater treatment activities will continue for many years.
The current cost estimate for remediation and restoration of the entire site is approximately $190$199 million. At June 30, 20192020 and Dec. 31, 2018,2019, NSP-Wisconsin had a total liability of $26$21 million and $27$23 million, respectively, for the entire site.
NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation and restoration costs as a regulatory asset. The PSCW has authorized NSP-Wisconsin rate recovery for all remediation and restoration costs incurred at the Site. In 2012, the PSCW agreed to allow NSP-Wisconsin to pre-collect certain costs, to amortize costs over 10 yearsSite and to applyapplication of a 3% carrying costcharge to the unamortized regulatory asset.
Rice Yards (Denver) MGP Landfill or Disposal SitesSite — — PSCo is cooperating with the City of Denver on an environmental investigation of the Rice Yards Site in the Central Platte Valley of Denver, Colorado, which had various historic industrial uses by multiple parties, including railroad, maintenance shop, scrap metal yard and MGP operations.
In the 1990’s, environmental remediation activities took place at the site under state oversight to accommodate the development of an amusement park and parking lots. The area is being redeveloped into residential and commercial mixed uses, andJune 2020, PSCo is in discussions withresolved claims by the current property owner regarding legal claims relatedand agreed to contribute up to a maximum of $9 million towards future environmental investigation, remediation and mitigation measures over the next 15 years.
In addition to the Rice Yards Site.
In addition,and Ashland Sites, Xcel Energy is currently investigating, remediating or remediating 11performing post-closure actions at 12 other MGP, landfill or other disposal sites across its service territories.
Xcel Energy has recognized its best estimate of costs/liabilities that will result from final resolution of these issues, however, the outcome and timing is unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of the costs incurred.
Environmental Requirements — Water and Waste
Coal Ash Regulation — Xcel Energy’s operations are subject to federal and state lawsregulations that impose requirements for handling, storage, treatment and disposal of solid waste.
Under the CCR Rule, utilities are required to complete groundwater sampling around their CCR landfills and surface impoundments. By the end of 2019, only nine ofCurrently, Xcel Energy’sEnergy has 9 regulated ash units are expected to be in operation.
Xcel Energy is conducting groundwater sampling and, where appropriate, initiating theimplementing assessment of corrective measures at certain CCR landfills and surface impoundments. In 2019, groundwater monitoring consistent with the CCR Rule was conducted. In NSP-Minnesota, 0 results above the groundwater protection standards in the rule were identified. In PSCo, statistically significant levels above background concentrations were detected at 4 locations. Subsequently, assessment monitoring samples were collected at these locations and, based on the results, PSCo is evaluating whetheroptions for corrective action is required at any CCR landfills or surface impoundments.
2 locations. At 1 location, monitoring results indicate potential offsite impacts to groundwater. Until Xcel EnergyPSCo completes its assessment, it is uncertain what impact, if any, there will be on the operations, financial condition or cash flows.
Xcel Energy evaluates contracts
In August 2018, the D.C. Circuit ruled that may contain leases, including PPAs and arrangementsthe EPA cannot allow utilities to continue to use unlined impoundments (including clay lined impoundments) for the usestorage or disposal of office spacecoal ash. In November 2019, the EPA proposed rules in response to this decision. If finalized in their current form, these rules would require NSP-Minnesota to expedite closure plans for 1 impoundment at an estimated cost of $4 million and other facilities, vehicles and equipment. Under ASC Topic 842, adopted by Xcel Energy on Jan. 1, 2019, a contract contains a lease if it conveys the exclusive right to control the useconstruction of a specific asset. A contract determinednew impoundment at the cost of $9 million. In 2019, NSP-Minnesota initiated the construction of this new impoundment, an ash pond, expected to containbe in service in 2020. Upon placing the new ash pond in service, the existing ash pond will be taken out of service, and closure activities as prescribed by the CCR Rule and the facility’s National Pollutant Discharge Elimination System permit will be initiated.
In addition, the rules proposed by the EPA under the D.C. Circuit ruling may require PSCo to expedite the closure of 1 coal ash impoundment that was not previously required to close. In March 2020, the EPA published a leaseproposed CCR Rule amendment that, if adopted, would allow unlined impoundments that ‘perform as effectively’ as lined ones to continue to operate under a state or federal CCR permit program. PSCo is evaluated furtherpursuing options to determine ifprovide alternative storage capacity consistent with the arrangement is a finance lease.CCR Rule until the generating units are retired in 2025.
ROU assets represent Xcel Energy's rights to use leased assets. Starting in 2019, the present value of future operating lease paymentsClosure costs for existing impoundments are recognized in other current liabilities and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets.
Most of Xcel Energy’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is calculated using the applicable Xcel Energy subsidiary’s estimated incremental borrowing rate (weighted-average of 4.1%). Xcel Energy has elected the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from minimum lease payments for the purposescalculation of lease accounting and disclosure.the asset retirement obligation liability.
Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the consolidated balance sheet.
Operating lease ROU assets:
|
| | | | |
| (Millions of Dollars) | | June 30, 2019 |
| PPAs | | $ | 1,642 |
|
| Other | | 201 |
|
| Gross operating lease ROU assets | | 1,843 |
|
| Accumulated amortization | | (80 | ) |
| Net operating lease ROU assets | | $ | 1,763 |
|
In 2019, ROU assets for finance leases are included in other noncurrent assets, and the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities. Prior to 2019, finance leases were included in property, plant and equipment, the current portion of long-term debt and long-term debt.
Xcel Energy’s most significant finance lease activities are related to WYCO.WYCO is a joint venture with CIG to develop and lease natural gas pipeline, storage and compression facilities. Xcel Energy Inc. has a 50% ownership interest in WYCO. WYCO leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage and transportation services to PSCo under separate service agreements.
PSCo accounts for its Totem natural gas storage service and Front Range pipeline arrangements with CIG and WYCO, respectively, as finance leases. Xcel Energy Inc. eliminates 50% of the finance lease obligation related to WYCO in the consolidated balance sheet along with an equal amount of Xcel Energy Inc.’s equity investment in WYCO.
Finance lease ROU assets:
|
| | | | |
| (Millions of Dollars) | | June 30, 2019 |
| Gas storage facilities | | $ | 201 |
|
| Gas pipeline | | 21 |
|
| Gross finance lease ROU assets | | 222 |
|
| Accumulated amortization | | (80 | ) |
| Net finance lease ROU assets | | $ | 142 |
|
Components of lease expense:
|
| | | | | | | | |
| (Millions of Dollars) | | Three Months Ended June 30, 2019 | | Six Months Ended June 30, 2019 |
| Operating leases | | | | |
| PPA capacity payments | | $ | 53 |
| | $ | 105 |
|
Other operating leases (a) | | 8 |
| | 17 |
|
Total operating lease expense (b) | | $ | 61 |
| | $ | 122 |
|
| | | | | |
| Finance leases | | | | |
| Amortization of ROU assets | | $ | 2 |
| | $ | 3 |
|
| Interest expense on lease liability | | 5 |
| | 9 |
|
| Total finance lease expense | | $ | 7 |
| | $ | 12 |
|
| |
(a)
| Includes short-term lease expense of $2 million for three months ended June 30, 2019 and $3 million for six months ended June 30, 2019. |
| |
(b)
| PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power. |
NSP-Minnesota has requested regulatory approval to purchase the MEC in the third quarter of 2019. NSP-Minnesota currently receives energy and capacity from MEC under PPAs expiring in 2026 and 2039. Pending its expected purchase by NSP-Minnesota, operating lease liabilities at June 30,Dec. 31, 2019 currently include a present value of $428remaining lease payments of approximately $400 million for PPA capacity payments.
Future commitments under operating and finance leases as ofthe MEC PPAs. At June 30, 2019:2020, NSP-Minnesota operating lease liabilities and related right-of-use assets are eliminated from Xcel Energy’s consolidated balance sheet following the completed January 2020 purchase of MEC by Xcel Energy.
|
| | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | PPA (a) (b) Operating Leases | | Other Operating Leases | | Total
Operating Leases | | Finance Leases (c) |
| 2019 | | $ | 118 |
| | $ | 12 |
| | $ | 130 |
| | $ | 6 |
|
| 2020 | | 237 |
| | 25 |
| | 262 |
| | 14 |
|
| 2021 | | 243 |
| | 24 |
| | 267 |
| | 14 |
|
| 2022 | | 226 |
| | 27 |
| | 253 |
| | 12 |
|
| 2023 | | 218 |
| | 21 |
| | 239 |
| | 12 |
|
| Thereafter | | 959 |
| | 136 |
| | 1,095 |
| | 220 |
|
| Total minimum obligation | | 2,001 |
| | 245 |
| | 2,246 |
| | 278 |
|
| Interest component of obligation | | (355 | ) | | (55 | ) | | (410 | ) | | (195 | ) |
| Present value of minimum obligation | | $ | 1,646 |
| | $ | 190 |
| | 1,836 |
| | 83 |
|
| Less current portion | | | | | | (189 | ) | | (4 | ) |
| Noncurrent operating and finance lease liabilities | | | | | | $ | 1,647 |
| | $ | 79 |
|
| | | | | | | | | |
| Weighted-average remaining lease term in years | | | | | | 9.7 |
| | 37.2 |
|
| |
(a)
| Amounts do not includeUnder certain PPAs, accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. |
| |
(b)
| PPA operating leases contractually expire at various dates through 2033. |
| |
(c)
| Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO. |
Future commitments under operating and finance leases as of Dec. 31, 2018:
|
| | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | PPA (a) (b) Operating Leases | | Other Operating Leases | | Total
Operating Leases | | Finance Leases (c) |
| 2019 | | $ | 207 |
| | $ | 32 |
| | $ | 239 |
| | $ | 14 |
|
| 2020 | | 208 |
| | 26 |
| | 234 |
| | 14 |
|
| 2021 | | 210 |
| | 25 |
| | 235 |
| | 14 |
|
| 2022 | | 197 |
| | 24 |
| | 221 |
| | 12 |
|
| 2023 | | 186 |
| | 22 |
| | 208 |
| | 12 |
|
| Thereafter | | 883 |
| | 154 |
| | 1,037 |
| | 220 |
|
| Total minimum obligation | |
|
| |
|
| |
|
| | 286 |
|
| Interest component of obligation | | | | | | | | (201 | ) |
| Present value of minimum obligation | | | | | | $ | 85 |
|
| |
(a)
| Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. |
| |
(b)
| PPA operating leases contractually expire at various dates through 2033. |
| |
(c)
| Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO. |
Variable Interest Entities
NSP-Minnesota, PSCo and SPS purchase power from IPPs andfor which the utility subsidiaries are required to reimburse the IPPs for natural gas or biomass fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. These specific PPAs create a variable interest in the associated IPP.
The Xcel Energy utility subsidiaries had approximately 3,9863,342 MW and 3,7703,986 MW of capacity under long-term PPAs as ofat June 30, 20192020 and Dec. 31, 2018,2019, respectively, with entities that have been determined to be variable interest entities.VIEs. Xcel Energy has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreementsAgreements have various expiration dates through 2041.
Other
Guarantees and Bond Indemnifications — Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum amount. As of June 30, 20192020 and Dec. 31, 2018,2019, Xcel Energy Inc. and its subsidiaries had no0 assets held as collateral related to their guarantees, bond indemnities and indemnification agreements.
Guarantees and bond indemnities issued and outstanding for Xcel Energy were $58 million and $69$62 million at June 30, 20192020 and Dec. 31, 2018, respectively.2019.
Other Indemnification Agreements — Xcel Energy Inc. and its subsidiaries provide indemnifications through various contracts. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold. Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. Maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated.
11. Other Comprehensive Loss | | |
| 11. Other Comprehensive Income (Loss) |
Changes in accumulated other comprehensive loss, net of tax, for the three and six months ended June 30, 20192020 and 2018:2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, 2020 | | | | | | | | Three Months Ended June 30, 2019 | | | | |
| (Millions of Dollars) | | Gains and Losses
on Cash Flow Hedges | | | | Defined Benefit Pension and
Postretirement Items | | Total | | Gains and Losses
on Cash Flow Hedges | | Defined Benefit Pension and
Postretirement Items | | Total |
| Accumulated other comprehensive loss at April 1 | | $ | (88) | | | | | $ | (60) | | | $ | (148) | | | $ | (66) | | | $ | (61) | | | $ | (127) | |
| Other comprehensive (loss) gain before reclassifications (net of taxes of $—, $—, $(3) and $—, respectively) | | — | | | | | — | | | — | | | (10) | | | 1 | | | (9) | |
| Losses reclassified from net accumulated other comprehensive loss: | | | | | | | | | | | | | | |
Interest rate derivatives (net of taxes of $1, $—, $— and $—, respectively) (a) | | 1 | | | | | — | | | 1 | | | 1 | | | — | | | 1 | |
Amortization of net actuarial loss (net of taxes of $—, $1, $— and $—, respectively) (b) | | — | | | | | 2 | | | 2 | | | — | | | — | | | — | |
| Net current period other comprehensive income (loss) | | 1 | | | | | 2 | | | 3 | | | (9) | | | 1 | | | (8) | |
| Accumulated other comprehensive loss at June 30 | | $ | (87) | | | | | $ | (58) | | | $ | (145) | | | $ | (75) | | | $ | (60) | | | $ | (135) | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended June 30, 2019 | | Three Months Ended June 30, 2018 |
| (Millions of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total |
| Accumulated other comprehensive loss at April 1 | | $ | (66 | ) | | $ | (61 | ) | | $ | (127 | ) | | $ | (58 | ) | | $ | (66 | ) | | $ | (124 | ) |
| Other comprehensive (loss) gain before reclassifications (net of taxes of $(3), $0, $0 and $0, respectively) | | (10 | ) | | 1 |
| | (9 | ) | | — |
| | — |
| | — |
|
| Losses reclassified from net accumulated other comprehensive loss: | | | | | | | | | | | |
|
|
Interest rate derivatives (net of taxes of $0) (a) | | 1 |
| | — |
| | 1 |
| | 1 |
| | — |
| | 1 |
|
Amortization of net actuarial loss (net of taxes of $0, $0, $0 and $1, respectively) (b) | | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Net current period other comprehensive income | | (9 | ) | | 1 |
| | (8 | ) | | 1 |
| | 1 |
| | 2 |
|
| Accumulated other comprehensive loss at June 30 | | $ | (75 | ) | | $ | (60 | ) | | $ | (135 | ) | | $ | (57 | ) | | $ | (65 | ) | | $ | (122 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Six Months Ended June 30, 2019 | | Six Months Ended June 30, 2018 |
| (Millions of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total |
| Accumulated other comprehensive loss at Jan. 1 | | $ | (60 | ) | | $ | (64 | ) | | $ | (124 | ) | | $ | (58 | ) | | $ | (67 | ) | | $ | (125 | ) |
| Other comprehensive (loss) gain before reclassifications (net of taxes of $(5), $1, $0 and $0, respectively) | | (17 | ) | | 3 |
| | (14 | ) | | — |
| | — |
| | — |
|
| Losses reclassified from net accumulated other comprehensive loss: | | | | | | | | | | | | |
Interest rate derivatives (net of taxes of $0) (a) | | 2 |
| | — |
| | 2 |
| | 1 |
| | — |
| | 1 |
|
Amortization of net actuarial loss (net of taxes of $0, $0, $0 and $1, respectively) (b) | | — |
| | 1 |
| | 1 |
| | — |
| | 2 |
| | 2 |
|
| Net current period other comprehensive income | | (15 | ) | | 4 |
| | (11 | ) | | 1 |
| | 2 |
| | 3 |
|
| Accumulated other comprehensive loss at June 30 | | $ | (75 | ) | | $ | (60 | ) | | $ | (135 | ) | | $ | (57 | ) | | $ | (65 | ) | | $ | (122 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30, 2020 | | | | | | | | Six Months Ended June 30, 2019 | | | | |
| (Millions of Dollars) | | Gains and Losses
on Cash Flow Hedges | | | | Defined Benefit Pension and
Postretirement Items | | Total | | Gains and Losses
on Cash Flow Hedges | | Defined Benefit Pension and
Postretirement Items | | Total |
| Accumulated other comprehensive loss at Jan. 1 | | $ | (80) | | | | | $ | (61) | | | $ | (141) | | | $ | (60) | | | $ | (64) | | | $ | (124) | |
| Other comprehensive (loss) gain before reclassifications (net of taxes of $(3), $—, $(5) and $1, respectively) | | (10) | | | | | — | | | (10) | | | (17) | | | 3 | | | (14) | |
| Losses reclassified from net accumulated other comprehensive loss: | | | | | | | | | | | | | | |
Interest rate derivatives (net of taxes of $1, $—, $— and $—, respectively) (a) | | 3 | | | | | — | | | 3 | | | 2 | | | — | | | 2 | |
Amortization of net actuarial loss (net of taxes of $—, $1, $— and $—, respectively) (b) | | — | | | | | 3 | | | 3 | | | — | | | 1 | | | 1 | |
| Net current period other comprehensive (loss) income | | (7) | | | | | 3 | | | (4) | | | (15) | | | 4 | | | (11) | |
| Accumulated other comprehensive loss at June 30 | | $ | (87) | | | | | $ | (58) | | | $ | (145) | | | $ | (75) | | | $ | (60) | | | $ | (135) | |
(a)Included in interest charges.
(b)Included in the computation of net periodic pension and postretirement benefit costs.
| | | | | | | | | | | | | | |
(a)
12. Segment Information | Included in interest charges. |
| | |
(b)
| Included in the computation of net periodic pension and postretirement benefit costs. |
12. Segment Information
RegulatedXcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided, including the regulated electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility operating results of NSP-Minnesota, NSP-Wisconsin and PSCo are each separately and regularly reviewed by Xcel Energy’s chief operating decision maker. Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided.
PSCo. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.
Xcel Energy has the following reportable segments:
| |
• | •Regulated Electric— The regulated electric utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. The regulated electric utility segment also includes wholesale commodity and trading operations; and - The regulated electric utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. The regulated electric utility segment also includes wholesale commodity and trading operations. |
| |
• | Regulated Natural Gas - The regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado.
|
| |
• | All Other - Operating segments with revenues below the necessary quantitative thresholds are included in this category. Those segments primarily include steam revenue, appliance repair services, non-utility real estate activities, revenues associated with processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits.
|
Xcel Energy had equity investments in unconsolidated subsidiaries of $145 million and $141$155 million as of June 30, 20192020 and Dec. 31, 2018, respectively,2019 included in the natural gas utility and all other segments.
Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments. As an integrated electric and natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment. Reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.
Certain costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators across each segment. In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.
Xcel Energy’s segment information for the three and six months ended June 30:
|
| | | | | | | | |
| | | Three Months Ended June 30 |
| (Millions of Dollars) | | 2019 | | 2018 |
| Regulated Electric | | | | |
| Operating revenues from external customers | | $ | 2,249 |
| | $ | 2,348 |
|
| Intersegment revenue | | 1 |
| | — |
|
| Total revenues | | $ | 2,250 |
| | $ | 2,348 |
|
| Net income | | 249 |
| | 264 |
|
| Regulated Natural Gas | | | | |
| Operating revenues from external customers | | $ | 308 |
| | $ | 292 |
|
| Net income | | 23 |
| | 27 |
|
| All Other | | | | |
| Total operating revenue | | $ | 20 |
| | $ | 18 |
|
| Net loss | | (34 | ) | | (26 | ) |
| | | | | |
| Consolidated Total | | | | |
| Total revenue | | $ | 2,578 |
| | $ | 2,658 |
|
| Reconciling eliminations | | (1 | ) | | — |
|
| Consolidated total revenue | | $ | 2,577 |
| | $ | 2,658 |
|
| Net income | | 238 |
| | 265 |
|
| | | | | | | | | | | | | | |
| | Three Months Ended June 30 | | |
| (Millions of Dollars) | | 2020 | | 2019 |
| Regulated Electric | | | | |
| Operating revenues from external customers | | $ | 2,286 | | | $ | 2,249 | |
| Intersegment revenue | | 1 | | | 1 | |
| Total revenues | | $ | 2,287 | | | $ | 2,250 | |
| Net income | | 289 | | | 249 | |
| Regulated Natural Gas | | | | |
| Operating revenues from external customers | | $ | 280 | | | $ | 308 | |
| | | | |
| | | | |
| Net income | | 20 | | | 23 | |
| All Other | | | | |
| Total operating revenue | | $ | 20 | | | $ | 20 | |
| Net loss | | (22) | | | (34) | |
| | | | |
| Consolidated Total | | | | |
| Total revenue | | $ | 2,587 | | | $ | 2,578 | |
| Reconciling eliminations | | (1) | | | (1) | |
| Total operating revenues | | $ | 2,586 | | | $ | 2,577 | |
| Net income | | 287 | | | 238 | |
|
| | | | | | | | |
| | | Six Months Ended June 30 |
| (Millions of Dollars) | | 2019 | | 2018 |
| Regulated Electric | | | | |
| Operating revenues from external customers | | $ | 4,574 |
| | $ | 4,617 |
|
| Intersegment revenue | | 1 |
| | 1 |
|
| Total revenues | | $ | 4,575 |
| | $ | 4,618 |
|
| Net income | | 482 |
| | 483 |
|
| Regulated Natural Gas | | | | |
| Operating revenues from external customers | | $ | 1,102 |
| | $ | 954 |
|
| Intersegment revenue | | 1 |
| | 1 |
|
| Total revenues | | $ | 1,103 |
| | $ | 955 |
|
| Net income | | 128 |
| | 121 |
|
| All Other | | | | |
| Total operating revenue | | $ | 42 |
| | $ | 38 |
|
| Net loss | | (57 | ) | | (48 | ) |
| | | | | |
| Consolidated Total | | | | |
| Total revenue | | $ | 5,720 |
| | $ | 5,611 |
|
| Reconciling eliminations | | (2 | ) | | (2 | ) |
| Consolidated total revenue | | $ | 5,718 |
| | $ | 5,609 |
|
| Net income | | 553 |
| | 556 |
|
| | | | | | | | | | | | | | |
| | Six Months Ended June 30 | | |
| (Millions of Dollars) | | 2020 | | 2019 |
| Regulated Electric | | | | |
| Operating revenues from external customers | | $ | 4,489 | | | $ | 4,574 | |
| Intersegment revenue | | 1 | | | 1 | |
| Total revenues | | $ | 4,490 | | | $ | 4,575 | |
| Net income | | 516 | | | 482 | |
| Regulated Natural Gas | | | | |
| Operating revenues from external customers | | $ | 863 | | | $ | 1,102 | |
| Intersegment revenue | | 1 | | | 1 | |
| Total revenues | | $ | 864 | | | $ | 1,103 | |
| Net income | | 111 | | | 128 | |
| All Other | | | | |
| Total operating revenue | | $ | 45 | | | $ | 42 | |
| Net loss | | (45) | | | (57) | |
| | | | |
| Consolidated Total | | | | |
| Total revenue | | $ | 5,399 | | | $ | 5,720 | |
| Reconciling eliminations | | (2) | | | (2) | |
| Total operating revenues | | $ | 5,397 | | | $ | 5,718 | |
| Net income | | 582 | | | 553 | |
Item
| | | | | | | | | | | | | | |
| ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | | | | |
The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy’s financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited consolidated financial statements and the related notes to consolidated financial statements.
Due to the seasonality of Xcel Energy’s operating results, quarterly financial results are not an appropriate base from which to project annual results. The demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months, and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, Xcel Energy’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.
Non-GAAP Financial Measures
The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as electric margin, natural gas margin, ongoing earnings and ongoing diluted EPS. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from measures calculated and presented in accordance with GAAP. Xcel Energy’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation, and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.
Electric and Natural Gas Margins
Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for electric fuel and purchased power and the cost of natural gas are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Management believes electric and natural gas margins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses. These margins can be reconciled to operating income, a GAAP measure, by including other operating revenues, cost of sales -— other, O&M expenses, conservation and DSM expenses, depreciation and amortization and taxes (other than income taxes).
Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)
GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items.
Ongoing diluted EPS is calculated by dividing the net income or loss of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss of such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.
We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries.
For the three and six months ended June 30, 20192020 and 2018,2019, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.
The only common equity securities that are publicly traded are common shares of Xcel Energy Inc. Diluted earnings and EPS of each subsidiary discussed below do not represent a direct legal interest in the assets and liabilities allocated to such subsidiary but rather represent a direct interest in our assets and liabilities as a whole.
GAAP and ongoing diluted EPS for Xcel Energy:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30 | | | | Six Months Ended June 30 | | |
| Diluted Earnings (Loss) Per Share | | 2020 | | 2019 | | 2020 | | 2019 |
| PSCo | | $ | 0.21 | | | $ | 0.20 | | | $ | 0.45 | | | $ | 0.47 | |
| NSP-Minnesota | | 0.22 | | | 0.19 | | | 0.43 | | | 0.41 | |
| SPS | | 0.14 | | | 0.11 | | | 0.22 | | | 0.22 | |
| NSP-Wisconsin | | 0.02 | | | 0.02 | | | 0.09 | | | 0.06 | |
| Equity earnings of unconsolidated subsidiaries | | 0.01 | | | 0.01 | | | 0.02 | | | 0.02 | |
Regulated utility (a) | | 0.60 | | | 0.53 | | | 1.20 | | | 1.18 | |
| Xcel Energy Inc. and Other | | (0.07) | | | (0.06) | | | (0.10) | | | (0.11) | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Total (a) | | $ | 0.54 | | | $ | 0.46 | | | $ | 1.10 | | | $ | 1.07 | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended June 30 | | Six Months Ended June 30 |
| Diluted Earnings (Loss) Per Share | | 2019 | | 2018 | | 2019 | | 2018 |
| PSCo | | $ | 0.20 |
| | $ | 0.24 |
| | $ | 0.47 |
| | $ | 0.50 |
|
| NSP-Minnesota | | 0.19 |
| | 0.18 |
| | 0.41 |
| | 0.40 |
|
| SPS | | 0.11 |
| | 0.11 |
| | 0.22 |
| | 0.18 |
|
| NSP-Wisconsin | | 0.02 |
| | 0.03 |
| | 0.06 |
| | 0.09 |
|
| Equity earnings of unconsolidated subsidiaries | | 0.01 |
| | 0.01 |
| | 0.02 |
| | 0.02 |
|
Regulated utility (a) | | 0.53 |
| | 0.58 |
| | 1.18 |
| | 1.19 |
|
| Xcel Energy Inc. and other | | (0.06 | ) | | (0.06 | ) | | (0.11 | ) | | (0.10 | ) |
Total (a) | | $ | 0.46 |
| | $ | 0.52 |
| | $ | 1.07 |
| | $ | 1.09 |
|
| |
(a) (a) Amounts may not add due to rounding.
| Amounts may not add due to rounding. |
Summary of Earnings
Xcel Energy — Xcel Energy’s earnings decreased $0.06increased $0.08 per share for the second quarter of 20192020 and $0.02$0.03 per share year-to-date. Earnings reflect management’s actions to reduce O&M to offset the impact from COVID-19 and favorable weather, partially offset by higher electricdepreciation and natural gas marginsinterest charges. Income taxes were lower primarily due to non-fuel ridershigher PTCs, which are credited to customers, resulting in lower electric margin and regulatory rate outcomes, more than offset by 5 cents per share of unfavorable weather, increased depreciation, interest and operating and maintenance expenses. do not materially impact earnings.
PSCo — Earnings decreased $0.04 per share for the second quarter of 2019 and $0.03 per share year-to-date. The decrease in year-to-date earnings was driven by higher O&M and depreciation partially offset by the timing of gas rates in 2018 and higher gas sales.
NSP-Minnesota — Earnings increased $0.01 per share for the second quarter of 2020 and decreased $0.02 per share year-to date. The decrease in year-to-date earnings was driven by lower sales and demand revenue primarily due to COVID-19, higher depreciation, interest charges and lower natural gas margins due to unfavorable weather, partially offset by higher AFUDC, an increase in electric margins (regulatory outcomes offset lower sales due to COVID-19) and lower O&M.
NSP-Minnesota — Earnings increased $0.03 per share for the second quarter of 2020 and $0.02 year-to-date. The increase in year-to-date earnings primarily reflects lower O&M and income taxes, partially offset by lower electric margins (reflecting lower sales from COVID-19) and natural gas margins as well as higher depreciation. Lower electric margins were due primarily to increased PTCs flowed back to customers (offset in income tax) and decreased sales, partially offset by non-fuel riders.
SPS — Earnings increased $0.03 per share for the second quarter of 2020 and were flat year-to-date. Year-to-date earnings were driven by lower O&M and income taxes, offset by lower electric margin and increased depreciation. Lower electric margins were attributable to lower sales from COVID-19, increased PTCs flowed back to customers (offset in income tax) and a 2019 NMPRC revised order eliminating a $10 million retroactive refund of tax reform benefits, partially offset by an increase in wholesale transmission revenue.
NSP-Wisconsin — Earnings were flat for the second quarter of 2020 and $0.01increased $0.03 per share year-to-date. The increase in year-to-date earnings primarily reflectswas driven by lower O&M and income taxes, as well as higher electric margins driven by rate casemargin (due primarily to regulatory outcomes which offset lower sales from COVID-19), partially offset by increased depreciation and O&M expenses.
SPS — Earnings were flat for the second quarter of 2019 and increased $0.04 per share year-to-date. Year-to-date results reflect higher electric margin attributable to rate case outcomes, sales growth and lower purchased capacity costs, despite unfavorable weather. Higher electric margin and AFUDC associated with the Hale County wind project were partially offset by increased depreciation, O&M and interest expenses.
NSP-Wisconsin — Earnings decreased $0.01 per share for the second quarter of 2019 and $0.03 per share year-to-date, largelynatural gas margins due to unfavorable weather higher depreciation and O&M expenses.increased depreciation.
Xcel Energy Inc. and otherOther — Xcel Energy Inc. and other primarilyPrimarily includes financing costs at the holding company.
Changes in GAAP and Ongoing Diluted EPS
Components significantly contributing to changes in 20192020 EPS compared with the same period in 2018:2019:
| | | | | | | | | | | | | | |
| Diluted Earnings (Loss) Per Share | | Three Months Ended June 30 | | Six Months Ended June 30 |
| GAAP and ongoing diluted EPS — 2019 | | $ | 0.46 | | | $ | 1.07 | |
| | | | |
| Components of change — 2020 vs. 2019 | | | | |
Lower ETR (a) | | 0.07 | | | 0.10 | |
| Lower O&M | | 0.05 | | | 0.08 | |
| Higher AFUDC | | 0.03 | | | 0.04 | |
Higher electric margin (b) | | 0.02 | | | 0.02 | |
| Higher depreciation and amortization | | (0.05) | | | (0.09) | |
| Higher interest charges | | (0.03) | | | (0.04) | |
| Lower natural gas margins | | — | | | (0.03) | |
| Lower other income (expense), net | | — | | | (0.02) | |
| Other (net) | | (0.01) | | | (0.03) | |
| GAAP and ongoing diluted EPS — 2020 | | $ | 0.54 | | | $ | 1.10 | |
|
| | | | | | | | |
| Diluted Earnings (Loss) Per Share | | Three Months Ended June 30 | | Six Months Ended June 30 |
| GAAP and ongoing diluted EPS — 2018 | | $ | 0.52 |
| | $ | 1.09 |
|
| | | | | |
| Components of change — 2019 vs. 2018 | | | | |
| Higher electric margins | | 0.03 |
| | 0.14 |
|
Lower ETR (a) | | 0.03 |
| | 0.10 |
|
| Higher natural gas margins | | 0.01 |
| | 0.05 |
|
| Higher depreciation and amortization | | (0.09 | ) | | (0.16 | ) |
| Higher O&M | | (0.01 | ) | | (0.07 | ) |
| Higher interest charges | | (0.02 | ) | | (0.05 | ) |
| Higher taxes (other than income taxes) | | (0.01 | ) | | (0.01 | ) |
| Other (net) | | — |
| | (0.02 | ) |
| GAAP and ongoing diluted EPS — 2019 | | $ | 0.46 |
| | $ | 1.07 |
|
| |
(a) (b)The period-over-period change in electric margin was negatively impacted by reductions in sales and demand. See table below: | | | | | | | | | | | | | | | | Diluted Earnings (Loss) Per Share | | Three Months Ended June 30 | | Six Months Ended June 30 | | Electric margin (excluding reductions in sales and demand) | | $ | 0.09 | | | $ | 0.09 | | Reductions in sales and demand (a) | | (0.07) | | | (0.07) | | | Higher electric margins | | $ | 0.02 | | | $ | 0.02 | |
(a) Sales decline excludes weather impact, net of decoupling/sales true-up and decrease in demand revenue is net of sales true-up. | Includes flow back of PTCs and timing of tax reform regulatory decisions, which are primarily offset in revenue. |
Statement of Income Analysis
The following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.
Estimated Impact of Temperature Changes on Regulated Earnings — Unusually—Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, and the amount of natural gas or electricity historically used per degree of temperature. Weathertemperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance.
Degree-day or Temperature-Humidity Index (THI)THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. Heating degree-days (HDD)HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. Cooling degree-days (CDD)CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather.
Normal weather conditions are defined as either the 20-year10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates.
Percentage increase (decrease) in normal and actual HDD, CDD and THI:
| | | | Three Months Ended June 30 | | Six Months Ended June 30 | | Three Months Ended June 30 | | | Six Months Ended June 30 | |
| | 2019 vs.
Normal | | 2018 vs.
Normal | | 2019 vs.
2018 | | 2019 vs.
Normal | | 2018 vs.
Normal | | 2019 vs.
2018 | | 2020 vs.
Normal | | 2019 vs.
Normal | | 2020 vs.
2019 | | 2020 vs.
Normal | | 2019 vs.
Normal | | 2020 vs.
2019 |
| HDD | 16.9 | % | | 0.1 | % | | 15.0 | % | | 12.8 | % | | 0.3 | % | | 11.0 | % | HDD | 2.2 | % | | 16.9 | % | | (11.8) | % | | (4.1) | % | | 12.8 | % | | (14.4) | % |
| CDD | (45.2 | ) | | 59.1 |
| | (71.4 | ) | | (45.5 | ) | | 59.7 |
| | (65.1 | ) | CDD | 22.4 | | | (45.2) | | | 191.2 | | | 22.5 | | | (45.5) | | | 139.9 | |
| THI | (26.7 | ) | | 108.1 |
| | (64.6 | ) | | (26.9 | ) | | 107.4 |
| | (64.5 | ) | THI | 15.0 | | | (26.7) | | | 63.6 | | | 14.7 | | | (26.9) | | | 63.6 | |
Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30 | | Six Months Ended June 30 |
| | 2019 vs.
Normal | | 2018 vs.
Normal | | 2019 vs.
2018 | | 2019 vs.
Normal | | 2018 vs.
Normal | | 2019 vs.
2018 |
| Retail electric | $ | (0.024 | ) | | $ | 0.065 |
| | $ | (0.089 | ) | | $ | (0.005 | ) | | $ | 0.067 |
| | $ | (0.072 | ) |
| Firm natural gas | 0.004 |
| | 0.002 |
| | 0.002 |
| | 0.022 |
| | 0.003 |
| | 0.019 |
|
| Total (excluding decoupling) | $ | (0.020 | ) | | $ | 0.067 |
| | $ | (0.087 | ) | | $ | 0.017 |
| | $ | 0.070 |
| | $ | (0.053 | ) |
Decoupling — Minnesota | 0.006 |
| | (0.030 | ) | | 0.036 |
| | 0.001 |
| | (0.032 | ) | | 0.033 |
|
| Total (adjusted for decoupling) | $ | (0.014 | ) | | $ | 0.037 |
| | $ | (0.051 | ) | | $ | 0.018 |
| | $ | 0.038 |
| | $ | (0.020 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30 | | | | | | Six Months Ended June 30 | | | | |
| 2020 vs.
Normal | | 2019 vs.
Normal | | 2020 vs.
2019 | | 2020 vs.
Normal | | 2019 vs.
Normal | | 2020 vs.
2019 |
| Retail electric | $ | 0.028 | | | $ | (0.024) | | | $ | 0.052 | | | $ | 0.017 | | | $ | (0.005) | | | $ | 0.022 | |
| Decoupling and sales true-up | (0.014) | | | 0.006 | | | (0.020) | | | (0.009) | | | 0.001 | | | (0.010) | |
| Electric total | $ | 0.014 | | | $ | (0.018) | | | $ | 0.032 | | | $ | 0.008 | | | $ | (0.004) | | | $ | 0.012 | |
| Firm natural gas | 0.001 | | | 0.004 | | | (0.003) | | | (0.006) | | | 0.022 | | | (0.028) | |
| Total | $ | 0.015 | | | $ | (0.014) | | | $ | 0.029 | | | $ | 0.002 | | | $ | 0.018 | | | $ | (0.016) | |
Sales Growth (Decline) — Sales growth (decline) for actual and weather-normalized sales in 20192020 compared to the same period in 2018:2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30 | | | | | | | | |
| | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy |
Actual (a) | | | | | | | | | | |
| Electric residential | | 13.5 | % | | 10.2 | % | | 13.4 | % | | 10.8 | % | | 11.9 | % |
| Electric C&I | | (8.3) | | | (13.2) | | | (7.5) | | | (12.3) | | | (10.2) | |
| Total retail electric sales | | (1.7) | | | (6.6) | | | (4.4) | | | (6.5) | | | (4.5) | |
| Firm natural gas sales | | (13.0) | | | 0.4 | | | N/A | | (3.8) | | | (8.5) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30 | | | | | | | | |
| | PSCo (b) | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy |
Weather-normalized (a) | | | | | | | | | | |
| Electric residential | | 6.1 | % | | 5.7 | % | | 3.3 | % | | 4.9 | % | | 5.4 | % |
| Electric C&I | | (10.4) | | | (14.2) | | | (8.6) | | | (13.3) | | | (11.5) | |
| Total retail electric sales | | (5.4) | | | (8.5) | | | (6.9) | | | (8.6) | | | (7.1) | |
| Firm natural gas sales | | (7.4) | | | 2.7 | | | N/A | | 3.1 | | | (3.9) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30 | | | | | | | | |
| | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy |
Actual (a) | | | | | | | | | | |
| Electric residential | | 5.7 | % | | 2.1 | % | | 5.4 | % | | 1.0 | % | | 3.8 | % |
| Electric C&I | | (4.0) | | | (8.5) | | | (2.2) | | | (6.4) | | | (5.4) | |
| Total retail electric sales | | (1.0) | | | (5.4) | | | (1.1) | | | (4.3) | | | (2.9) | |
| Firm natural gas sales | | (8.2) | | | (10.4) | | | N/A | | (12.0) | | | (9.1) | |
|
| | | | | | | | | | | | | | | |
| | | Three Months Ended June 30 |
| | | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy |
| Actual | | | | | | | | | | |
| Electric residential | | (6.5 | )% | | (10.7 | )% | | (13.2 | )% | | (9.0 | )% | | (9.4 | )% |
| Electric C&I | | (1.4 | ) | | (6.2 | ) | | 2.6 |
| | (2.5 | ) | | (2.3 | ) |
| Total retail electric sales | | (2.9 | ) | | (7.5 | ) | | (0.5 | ) | | (4.2 | ) | | (4.2 | ) |
| Firm natural gas sales | | 19.6 |
| | (1.2 | ) | | N/A |
| | (10.7 | ) | | 10.5 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30 | | | | | | | | |
| | PSCo (b) | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy |
Weather-normalized (a) | | | | | | | | | | |
| Electric residential | | 3.4 | % | | 2.7 | % | | 1.9 | % | | 3.0 | % | | 2.9 | % |
| Electric C&I | | (5.0) | | | (8.7) | | | (2.7) | | | (6.5) | | | (5.8) | |
| Total retail electric sales | | (2.4) | | | (5.3) | | | (2.1) | | | (3.8) | | | (3.5) | |
| Firm natural gas sales | | (1.4) | | | 2.6 | | | N/A | | 3.3 | | | 0.2 | |
| | | | | | | | | | | | | | Six Months Ended June 30 (Leap Year Adjusted) | |
| | | Three Months Ended June 30 | | PSCo (b) | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy |
| | | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy | |
| Weather-normalized | | | | | | | | | | | |
Weather-normalized (a) | | Weather-normalized (a) | | | | | | | | | | |
| Electric residential | | 0.3 | % | | 0.8 | % | | 1.9 | % | | 1.7 | % | | 0.8 | % | Electric residential | | 2.8 | % | | 2.2 | % | | 1.3 | % | | 2.4 | % | | 2.3 | % |
| Electric C&I | | 0.7 |
| | (3.6 | ) | | 4.5 |
| | (0.6 | ) | | — |
| Electric C&I | | (5.5) | | | (9.2) | | | (3.3) | | | (7.1) | | | (6.4) | |
| Total retail electric sales | | 0.6 |
| | (2.4 | ) | | 3.9 |
| | — |
| | 0.2 |
| Total retail electric sales | | (3.0) | | | (5.8) | | | (2.7) | | | (4.4) | | | (4.1) | |
| Firm natural gas sales | | 5.3 |
| | 4.8 |
| | N/A |
| | (7.9 | ) | | 4.4 |
| Firm natural gas sales | | (2.2) | | | 1.7 | | | N/A | | 2.3 | | | (0.7) | |
|
| | | | | | | | | | | | | | | |
| | | Six Months Ended June 30 |
| | | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy |
| Actual | | | | | | | | | | |
| Electric residential | | (1.7 | )% | | (4.0 | )% | | (4.2 | )% | | (2.8 | )% | | (3.1 | )% |
| Electric C&I | | (0.4 | ) | | (3.7 | ) | | 3.4 |
| | (2.4 | ) | | (0.8 | ) |
| Total retail electric sales | | (0.8 | ) | | (3.8 | ) | | 1.9 |
| | (2.5 | ) | | (1.5 | ) |
| Firm natural gas sales | | 17.1 |
| | 5.7 |
| | N/A |
| | (0.8 | ) | | 11.9 |
|
|
| | | | | | | | | | | | | | | |
| | | Six Months Ended June 30 |
| | | PSCo | | NSP-Minnesota | | SPS | | NSP-Wisconsin | | Xcel Energy |
| Weather-normalized | | | | | | | | | | |
| Electric residential | | 0.3 | % | | 0.5 | % | | 2.8 | % | | 0.9 | % | | 0.8 | % |
| Electric C&I | | 0.4 |
| | (2.5 | ) | | 4.6 |
| | (1.6 | ) | | 0.2 |
|
| Total retail electric sales | | 0.4 |
| | (1.6 | ) | | 4.1 |
| | (0.9 | ) | | 0.4 |
|
| Firm natural gas sales | | 4.7 |
| | 1.1 |
| | N/A |
| | (3.7 | ) | | 3.0 |
|
Weather-normalized Electric Sales Growth (Decline)
PSCo — (a)Higher residential sales and lower C&I sales were primarily attributable to COVID-19.
(b)CPUC approved a historical 10-year weather normalization approach for retail electric, effective March 1, 2020.
Weather-normalized and leap-year adjusted electric sales growth (decline) — year-to-date (excluding leap day)
•PSCo — Residential sales rose based on higher use per customer from stay-at-home mandates and an increased number of customers. The C&I decline was due to lower use offsetting an increase in the number of C&I customers. The decline in C&I sales was primarily due to the shutdown of the economy from COVID-19, decreases in the manufacturing and service industries, partially offset by an increase in the energy sector.
•NSP-Minnesota — Residential sales growth reflects higher use per customer additions, partiallyfrom stay-at-home mandates and increased customer additions. The drop in C&I sales was as a result of customer growth offset by lower use per customer. C&I growth was due to an increase in customers and higher use per customer, predominately from the fabricated metal and metal mining industries.
NSP-Minnesota — Higher residential sales growth reflects customer additions, partially offset by lower use per customer. Decline in C&I sales was due to lower use per customer (self-generation), which was partially offset by an increase in customers. Decreased sales to C&I customers were driven bydue to the shutdown of the economy from COVID-19 and declines in the energy, manufacturing and manufacturingservices sectors.
SPS — Residential sales grew largelyincreased due to customer growth and higher use per customer and customer additions. Higher C&I sales was primarily due to increased use per customer, driven by the oil and natural gas industry in the Permian Basin.
NSP-Wisconsin — Residential sales growth was primarily attributable to customer additions and higher use per customer.from stay-at-home mandates. The decline in C&I sales was due to shutdowns of the economy from COVID-19, declines in oil and natural gas extraction due to lower commodity prices and lower manufacturing, agriculture & food and services.
•NSP-Wisconsin — Residential sales growth was attributable to higher use per customer from stay-at-home mandates and customer additions. The decline in C&I was largely due to the shutdown of the economy from COVID-19 and decreased sales to the mining, manufacturing and food services sectors, partially offset by customer additions.sector.
Weather-normalized Natural Gas Sales Growthand leap-year adjusted natural gas sales growth (decline) — year-to-date (excluding leap day)
•Natural gas sales reflect an increase in the number of customers combined with higherlower customer use.use due to the shutdown of the economy from COVID-19.
Electric Margin
Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium used in the generation of electricity. However, these price fluctuations have minimal impact on electric margin due to fuel recovery mechanisms that recover fuel expenses.
In addition, electric customers receive a credit for PTCs generated in a particular period.
Electric revenues and margin:
| | | | | Three Months Ended June 30 | | Six Months Ended June 30 | | Three Months Ended June 30 | | | Six Months Ended June 30 | |
| (Millions of Dollars) | | 2019 | | 2018 | | 2019 | | 2018 | (Millions of Dollars) | | 2020 | | 2019 | | 2020 | | 2019 |
| Electric revenues | | $ | 2,249 |
| | $ | 2,348 |
| | $ | 4,574 |
| | $ | 4,617 |
| Electric revenues | | $ | 2,286 | | | $ | 2,249 | | | $ | 4,489 | | | $ | 4,574 | |
| Electric fuel and purchased power | | (813 | ) | | (935 | ) | | (1,727 | ) | | (1,867 | ) | Electric fuel and purchased power | | (833) | | | (813) | | | (1,630) | | | (1,727) | |
| Electric margin | | $ | 1,436 |
| | $ | 1,413 |
| | $ | 2,847 |
| | $ | 2,750 |
| Electric margin | | $ | 1,453 | | | $ | 1,436 | | | $ | 2,859 | | | $ | 2,847 | |
Changes in electric margin:
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | Three Months Ended June 30,
2020 vs. 2019 | | Six Months Ended June 30,
2020 vs. 2019 |
| Regulatory rate outcomes (Colorado, Wisconsin and New Mexico) | | $ | 21 | | | $ | 34 | |
| Wholesale transmission revenue (net) | | 20 | | | 25 | |
| Non-fuel riders | | 11 | | | 24 | |
| Estimated impact of weather (net of decoupling/sales true-up) | | 21 | | | 8 | |
| PTCs flowed back to customers (offset by a lower ETR) | | (31) | | | (53) | |
Sales and demand (a) | | (47) | | | (46) | |
| New Mexico tax reform related regulatory settlement (2019) | | — | | | (10) | |
| Other (net) | | 22 | | | 30 | |
| Total increase in electric margin | | $ | 17 | | | $ | 12 | |
|
| | | | | | | | |
| (Millions of Dollars) | | Three Months Ended June 30,
2019 vs. 2018 | | Six Months Ended June 30,
2019 vs. 2018 |
Non-fuel riders (a) | | $ | 21 |
| | $ | 57 |
|
| Regulatory rate outcomes (Minnesota, New Mexico, North and South Dakota) | | 19 |
| | 47 |
|
| Lower purchased capacity costs | | 9 |
| | 15 |
|
| Demand revenue | | 11 |
| | 13 |
|
| Implementation of lease accounting standard (offset in interest expense and amortization) | | 5 |
| | 11 |
|
| Wholesale transmission revenue (net) | | 3 |
| | 11 |
|
| Estimated impact of weather (net of Minnesota decoupling) | | (40 | ) | | (32 | ) |
| Timing of tax reform regulatory decisions (offset in income tax) | | (6 | ) | | (19 | ) |
Other (net) | | 1 |
| | (6 | ) |
| Total increase in electric margin | | $ | 23 |
| | $ | 97 |
|
| |
(a) (a)Sales decline excludes weather impact, net of decoupling/sales true-up and decrease in demand revenue is net of sales true-up.
| Includes approximately $20 million and $32 million, respectively, of additional PTC benefit (grossed-up for tax) as compared to the same periods in 2018, which are flowed back to customers. |
Natural Gas Margin
Natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas has minimal impact on natural gas margin due to cost recovery mechanisms.
Natural gas revenues and margin:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30 | | | | Six Months Ended June 30 | | |
| (Millions of Dollars) | | 2020 | | 2019 | | 2020 | | 2019 |
| Natural gas revenues | | $ | 280 | | | $ | 308 | | | $ | 863 | | | $ | 1,102 | |
| Cost of natural gas sold and transported | | (86) | | | (112) | | | (371) | | | (591) | |
| Natural gas margin | | $ | 194 | | | $ | 196 | | | $ | 492 | | | $ | 511 | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended June 30 | | Six Months Ended June 30 |
| (Millions of Dollars) | | 2019 | | 2018 | | 2019 | | 2018 |
| Natural gas revenues | | $ | 308 |
| | $ | 292 |
| | $ | 1,102 |
| | $ | 954 |
|
| Cost of natural gas sold and transported | | (112 | ) | | (104 | ) | | (591 | ) | | (479 | ) |
| Natural gas margin | | $ | 196 |
| | $ | 188 |
| | $ | 511 |
| | $ | 475 |
|
Changes in natural gas margin:
| | | (Millions of Dollars) | | Three Months Ended June 30,
2019 vs. 2018 | | Six Months Ended June 30,
2019 vs. 2018 | (Millions of Dollars) | | Three Months Ended June 30,
2020 vs. 2019 | | Six Months Ended June 30,
2020 vs. 2019 |
| Retail rate increase (Colorado) | | $ | — |
| | $ | 12 |
| |
| Estimated impact of weather | | 1 |
| | 12 |
| Estimated impact of weather | | $ | (2) | | | $ | (19) | |
| Transport sales | | Transport sales | | — | | | (2) | |
| Regulatory rate outcomes (Wisconsin) | | Regulatory rate outcomes (Wisconsin) | | — | | | (2) | |
| Retail sales decline | | Retail sales decline | | (2) | | | (1) | |
| Infrastructure and integrity riders | | 2 |
| | 7 |
| Infrastructure and integrity riders | | 4 | | | 5 | |
| Retail sales growth | | 2 |
| | 4 |
| |
| Transport sales | | 1 |
| | 3 |
| |
| Conservation revenue (offset by expenses) | | (1 | ) | | (3 | ) | |
| Conservation revenue (offset in expenses) | | Conservation revenue (offset in expenses) | | 2 | | | 3 | |
| Other (net) | | 3 |
| | 1 |
| Other (net) | | (4) | | | (3) | |
| Total increase in natural gas margin | | $ | 8 |
| | $ | 36 |
| |
| Total decrease in natural gas margin | | Total decrease in natural gas margin | | $ | (2) | | | $ | (19) | |
Non-Fuel Operating Expenses and Other Items
O&M Expenses — O&M expenses increased $8decreased $36 million, or 1.4%6.1%, for the second quarter of 2019 and $49$55 million, or 4.3%4.6%, year-to-date.year-to-date, largely reflecting management actions to reduce costs to offset the impact of lower sales from COVID-19. Significant changes are summarized below:as follows:
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | Three Months Ended June 30,
2020 vs. 2019 | | Six Months Ended June 30,
2020 vs. 2019 |
| Distribution | | $ | (20) | | | $ | (30) | |
| Employee benefits | | 6 | | | (10) | |
| Transmission | | (5) | | | (6) | |
| Generation | | (4) | | | (6) | |
| Strategic initiatives | | — | | | 6 | |
| Other (net) | | (13) | | | (9) | |
| Total decrease in O&M expenses | | $ | (36) | | | $ | (55) | |
|
| | | | | | | | |
| (Millions of Dollars) | | Three Months Ended June 30,
2019 vs. 2018 | | Six Months Ended June 30,
2019 vs. 2018 |
| Distribution | | $ | 4 |
| | $ | 23 |
|
| Business systems | | 7 |
| | 11 |
|
| Gas operations | | 3 |
| | 4 |
|
| Plant generation | | (4 | ) | | 3 |
|
| Other (net) | | (2 | ) | | 8 |
|
| Total increase in O&M expenses | | $ | 8 |
| | $ | 49 |
|
•Distribution expenses declined due to cost mitigation efforts including allocation of workforce, material and supply management, performance of maintenance and other items;
•Employee benefits were lower year-to-date primarily due to change in deferred compensation liability, offset in Other Income (Expense);
•Transmission expenses declined due to a reduction in labor related amounts and cost mitigation initiatives;
•Generation expenses were lower from timing of maintenance and overhauls at power plants and cost mitigation efforts, partially offset by an increase in wind related amounts;
•Strategic initiative amounts were higher due to storms, labor and overtime;
Business systems costs were higheryear-to-date due to increased spending on customer experience transformation program expenses;expenses and advanced grid infrastructure; and
Natural gas operation expenses increased due to pipeline maintenance.•Other primarily includes deferred amounts associated with the Texas 2019 electric rate case and the outcome of the CPUC’s rehearing of the Colorado 2019 electric rate case.
Depreciation and Amortization — Depreciation and amortization increased $62$34 million, or 16.4%7.7%, for the second quarter of 2019 and $112$64 million, or 14.7%7.3%, year-to-date.year-to-date. Increase was primarily driven by the Rush CreekHale, Lake Benton, Foxtail and Blazing Star I wind project being placed in-service (recovered in riders), additional amortization of a prepaid pension assetfacilities going into service, as well as normal system expansion. In addition, depreciation rates were increased in Colorado related to tax reform settlements (offsetand New Mexico as part of regulatory outcomes in income taxes) and other capital investments.2020.
Taxes (Other thanOther Income Taxes)(Expense) — Taxes (other than Other income taxes)(expense) increased $5$3 million or 3.6%, for the second quarter of 2019 and $10decreased $13 million or 3.5%, year-to-date. Increase was primarilyDecrease is due to higher property taxesthe performance of rabbi trust investments, which is offset in Colorado and Minnesota (netO&M expense (deferred compensation).
AFUDC, Equity and Debt — AFUDC decreased $7increased $19 million for the second quarter of 2019 and $11$23 million year-to-date. DecreaseIncrease was primarily due to the Rush Creekadditional AFUDC recorded on various wind project being placed in-service in 2018, partially offset by the Hale wind project, which went into service in June 2019, and other capital investments.projects currently under construction.
Interest Charges — Interest charges increased $14$19 million, or 8.0%10.1%, for the second quarter of 2019 and $33$28 million, or 9.5%,7.4% year-to-date. Increase was primarily due to higher debt levels to fund capital investments, changes inpartially offset by lower long-term and short-term interest rates and implementation of lease accounting standard (offset in electric margin).rates.
Income Taxes — Income taxes decreased $30$37 million for the second quarter of 2019 compared with 2018. The decreasequarter. Decrease was primarily driven by lower pretax earnings, an increase in wind PTCs and an increase in plant regulatory differences. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income. The ETR was (4.7%) for the second quarter of 2020 compared with 9.2% for the same period in 2019.
Income taxes decreased $68 million for the first six months of 2020. Decrease was primarily driven by an increase in wind PTCs, lower pretax earnings and an increase in plant-related regulatory differences. Wind PTCs flow backare credited to customers and do not have a material impact on net income. The ETR was 9.2%(3.4%) for the second quarter of 2019first six months ending June 30, 2020 compared with 16.9%8.1% for the same period in 2018, largely due to the adjustments above.2019.
Income taxes decreased $65 million for the first six months of 2019 compared with 2018. The decrease was primarily driven by an increase in wind PTCs, an increase in plant-related regulatory differences, lower pretax earnings and a reversal of a valuation allowance. Wind PTCs flow back to customers and do not have a material impact on net income. The ETR was 8.1% for the first six months of 2019 compared with 17.0% for the same period in 2018, largely due to the adjustments above. See Note 6 to the consolidated financial statements for further information.
Regulation
FERC and State Regulation
—
| | |
| Public Utility Regulation |
The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and WGI. The electric and natural gas rates charged to customers of Xcel Energy Inc.’s utility subsidiaries and WGI are approved by the FERC or the regulatory commissions in the states in which they operate.
The rates are designed to recover plant investment, operating costs and an allowed return on investment. Xcel Energy Inc.’s utility subsidiaries request changes in rates for utility services through filings with governing commissions.
Changes in operating costs can affect Xcel Energy’s financial results, depending on the timing of rate case filings and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital. In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy’s results of operations.
Recently Filed Regulatory Proceedings
NSP-Wisconsin —Rate Case Settlement —In May 2019, NSP-Wisconsin filed an application with the PSCW seeking approval of a rate case settlement with various intervenors for 2020-2021.
For NSP-Wisconsin’s electric utility, the settlement agreement results in no change to base rates through Dec. 31, 2021. For the natural gas utility, there would be a $3.2 million (4.6%) decrease to base rates, effective Jan. 1, 2020, and no additional changes to base rates through Dec. 31, 2021.
Key elements of the settlement include:
Electric:
Allowed ROE of 10.0%;
Allowed equity ratio of 52.5%;
Retain expected fuel cost savings from new wind farms for the NSP System;
Allow deferral of pension settlement costs, if any, for 2019-2021;
Utilize a portion of tax reform benefits to offset revenue deficiency;
Allow deferral of certain large customer non-fuel cost of service impacts and bad debt expense in 2019-2021; and
Apply an earnings sharing mechanism for 2020 and 2021. The mechanism would return to customers 50% of earnings between 10.25% and 10.75% ROE and 100% of earnings equal to or in excess of 10.75% ROE.
Natural Gas:
Utilize tax reform benefits of $22.3 million to offset a portion of the regulatory asset for remediation of the MGP site in Ashland, WI.
On Aug. 1, 2019, the PSCW verbally approved the settlement agreement as filed with one minor modification, to remove the deferral of pension settlement accounting costs for 2021. NSP-Wisconsin anticipates a final written order in September 2019.
PSCo — Colorado 2019 Electric Rate Case — In May 2019, PSCo filed a request with the CPUC seeking a net rate increase of approximately $158 million, or 5.7%. The filing also requests the transfer of $249 million of rider revenue to base rates, which will not impact overall customer bills as the revenue is currently being recovered through various riders. The request is based on a ROE of 10.35%, an equity ratio of 56.46%, a historic test year ended Dec. 31, 2018 (adjusted for 2019 capital investment) and incorporates the full impact of tax reform. PSCo has requested rates effective Jan. 1, 2020.
|
| | | | |
| Revenue Request (Millions of Dollars) | | 2020 |
| Changes since 2014 rate case: | | |
| Plant-related growth 2013-2018 | | $ | 85 |
|
| O&M savings, sales growth and other cost reductions | | (89 | ) |
| Forecasted 2019 capital additions | | 49 |
|
| Advanced Grid Intelligence and Security grid modernization | | 39 |
|
| Updated cost of capital | | 32 |
|
| Previously approved depreciation rates | | 28 |
|
| Incremental wildfire mitigation | | 14 |
|
| Net increase to revenue | | 158 |
|
| Previously authorized costs: | | |
CACJA, TCA and Rush Creek (a) | | 249 |
|
Total base revenue request (c) | | $ | 408 |
|
| | | |
Expected year-end rate base (b) | | $ | 8,221 |
|
| |
(a)
| Roll-in of CACJA, TCA and Rush Creek Wind Project (excluding PTCs) amounts into base rates will not impact total revenue as costs are currently recovered from customers through riders or the fuel clause. |
| |
(b)
| Base rate request does not include the impact of the proposed Colorado Energy Plan. |
| |
(c)
| Amounts may not add due to rounding. |
The procedural schedule is as follows:
Answer testimony — Sept. 6, 2019
Rebuttal testimony — Oct. 8, 2019
Evidentiary hearing — Nov. 4-13, 2019
Statement of position — Nov. 22, 2019
SPS — New Mexico 2019 Electric Rate Case — In July 2019, SPS filed an electric rate case with the NMPRC seeking an increase in retail electric base rates of approximately $51 million. The rate request is based on a ROE of 10.35%, a 54.77% equity ratio, a rate base of approximately $1.3 billion and a historic test year with rate base additions through Aug. 31, 2019. SPS anticipates final rates will go into effect in the second or third quarter of 2020.
SPS' net revenue increase to New Mexico consumers is expected to be approximately $26 million, or 5.7%, due to fuel cost reductions and PTCs attributable to wind energy provided by the Hale Wind Project. PTCs are being credited to customers through the fuel clause.
The following table summarizes SPS’ base rate increase request:
|
| | | | |
| Revenue Request (Millions of Dollars) | | |
| Hale Wind Farm | | $ | 28 |
|
| Other plant investment | | 22 |
|
| Wholesale sales reduction | | 17 |
|
| Allocator changes due to load growth | | 15 |
|
| Depreciation rate change (including Tolk) | | 15 |
|
| Base rate sales growth | | (41 | ) |
| Other, net | | (5 | ) |
| New revenue request | | $ | 51 |
|
The procedural schedule is as follows:
Intervention deadline — Sept. 16, 2019
Filing of stipulation, if any — Nov. 15, 2019
Staff and intervenor testimony or testimony in support of a stipulation — Nov. 22, 2019
Testimony in opposition to a stipulation, if any — Dec. 6, 2019
Rebuttal testimony — Dec. 20, 2019
Public hearing begins — Jan. 7, 2020
End of 9-month suspension — April 30, 2020
Other Pending and Recently Concluded Regulatory Proceedings
|
| | | | | | | | | | |
Mechanism | | Utility Service | | Amount Requested (in millions) | | Filing
Date
| | Approval | | Additional Information |
NSP-Minnesota (MPUC) |
TCR | | Electric | | $98 | | November
2017
| | Pending | | In May 2019, the MPUC issued a verbal order setting an ROE of 9.06% and recovery of 2017-2018 expenses related to advanced grid investments. A final order is expected in the third quarter of 2019. |
2018 GUIC | | Natural Gas | | $23 | | November 2017 | | Pending | | In May 2019, the MPUC issued a verbal order setting an ROE of 9.04%. A final order is expected in the third quarter of 2019. |
2019 GUIC | | Natural Gas | | $29 | | November 2018 | | Pending | | Proposed ROE of 10.25%. Timing of the MPUC decision is uncertain. |
RES | | Electric | | $23 | | November 2017 | | Pending | | In May 2019, the MPUC issued a verbal order setting an ROE of 9.06%. A final order is expected in the third quarter of 2019. |
PSCo (CPUC) |
Rate Case | | Steam | | $7 | | May
2019
| | Pending | | In May 2019, PSCo filed an unopposed Settlement Agreement with CPUC Staff and the City of Denver. The settlement reflects a ROE of 9.67% for AFUDC purposes, an equity ratio of 56.04% and utilization of tax reform benefits. Final rates would be effective in October 2020, with an initial step increase in October 2019. In July 2019, the Administrative Law Judge recommended that the settlement agreement be approved without modification. Settlement is pending a CPUC decision. |
Rate Case Appeal | | Natural Gas | | N/A | | April 2019 | | Pending | | In April 2019, PSCo filed an appeal seeking judicial review of the CPUC’s prior ruling regarding PSCo’s last natural gas rate case (approved in December 2018). Appeal requests review of the following: denial of a return on the prepaid pension and retiree medical assets; the use of a capital structure that is not based on the actual historical test year level; and the use of an average rate base methodology rather than a year-end rate base methodology. The District Court of Denver County has adopted a briefing schedule that will conclude in October 2019. Timeline on a final ruling is unknown at this point. |
SPS (PUCT) |
Rate Case | | Electric | | $54 | | August 2017 | | Received | | In November 2018, SPS filed an application with the PUCT requesting permission to recover $5.4 million in unbilled TCRF revenue from January 23, 2018 through June 9, 2018. Application was approved in an order dated June 13, 2019. |
SPS (NMPRC) |
Rate Case | | Electric | | $43 | | October 2017 | | Received | | In February 2019, SPS and the NMPRC settled SPS' appeal to the NMSC regarding NMPRC's previous rate case order, including a $10.2 million refund of retroactive TCJA benefits. As a result, the NMPRC issued revised orders eliminating the retroactive refund and SPS reversed its previously recorded regulatory liability. The order also increased the ROE from 9.1% to 9.56% and the equity ratio from 51% to 53.97%, resulting in a prospective annual base rate increase of $4.5 million (incremental to $8.1 million approved in the initial order). New rates were effective March 11, 2019. |
See Rate Matters within Note 10 to the consolidated financial statements for further information.
NSP-Minnesota — MEC Acquisition — In November 2018, NSP-Minnesota reached an agreement with Southern Power Company to purchase the 760 MW natural gas CC facility for approximately $650 million. NSP-Minnesota currently purchases the energy and capacity of this facility through PPAs. The acquisition is projected to provide net customer savings of approximately $50 million to $150 million over the life of the plant.
In May 2019, NSP-Minnesota entered into a partial settlement agreement with several environmental organizations and the LIUNA. Under the terms of the agreement, the settling parties supported the MEC acquisition and NSP-Minnesota agreed to include (in its preferred plan in the Minnesota resource plan filing) early retirement of the Sherco 3 and King coal plants, as well as 3,000 MW of solar additions before 2030.
In May 2019, the FERC approved the purchase. In July 2019, the DOC and OAG recommended the MPUC deny approval of the Mankato acquisition. The DOC and OAG also recommended that if the MPUC were to approve the transaction, that the Commission disallow all or a portion of the acquisitions adjustment as well as require certain other customer protections. The MPUC is expected to hold hearings and make a decision in the third quarter.
NSP-Minnesota — Minnesota Resource Plan —In July 2019, NSP-Minnesota filed its Minnesota resource plan, which runs through 2034. The preferred plan would result in an 80% carbon reduction by 2030 and puts NSP on a path to achieving its vision of being 100% carbon-free by 2050. The preferred plan includes the following:
Extends the life of the Monticello nuclear plant from 2030 to 2040;
Continues to run the Prairie Island nuclear plant through current end of life (2033 and 2034);
Includes the MEC acquisition and construction of the Sherco CC natural gas plant;
Includes the early retirement of the King coal plant (511 MW) in 2028 and the Sherco 3 coal plant (517 MW) in 2030;
Adds approximately 1,700 MW of firm peaking (CT, pumped hydro, battery storage, DR, etc.);
Adds approximately 1,200 MW of wind replacement; and
Adds approximately 4,000 MW of solar.
Intervening parties will provide recommendations and comments on the resource plan. The MPUC is anticipated to make a final decision on the resource plan in late 2020 or the first half of 2021.
NSP-Minnesota —Jeffers Wind and CommunityWind North Repowering Acquisition— In December 2018, NSP-Minnesota filed a request with the MPUC seeking approval to acquire the Jeffers and Community Wind North wind facilities in western Minnesota from Longroad Energy. The wind farms, currently contracted under PPAs with NSP-Minnesota, will have approximately 70 MW of capacity after being repowered. The repowering and acquisition are expected to be complete by December 2020 and qualify for the 100% PTC benefit. The $135 million asset acquisition is projected to provide customer savings of approximately $7 million over the life of the facilities, compared to the amended PPAs. The FERC approved the acquisition in July 2019.
The DOC filed initial comments in support of NSP-Minnesota continuing to contract for the assets under the amended PPAs, but not the acquisition, pending additional information, including a purchase and sales agreement. NSP-Minnesota subsequently filed additional information, including an executed purchase and sale agreement, to address DOC concerns. Reply comments are due in August, with an MPUC decision expected in the second half of 2019.
Public Utility Regulation
Except to the extent noted below, and in Regulation above, the circumstances set forth in Public Utility Regulation included in Item 17 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 20182019 and in Item 2 of Xcel Energy Inc.’sEnergy’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2019,2020 appropriately represent, in all material respects, the current status of public utility regulation and are incorporated by reference. NSP-Minnesota
Pending and Recently Concluded Regulatory Proceedings
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Mechanism | | Utility Service | | Amount Requested (in millions) | | Filing
Date | | Approval | | Additional Information |
| MPUC | | | | | | | | | | |
| 2020 TCR | | Electric | | $82 | | November 2019 | | Pending | | In November 2019, NSP-Minnesota filed the 2020 TCR Rider. The filing included an ROE of 9.06%. Timing of an MPUC ruling is uncertain. |
| 2020 GUIC | | Natural Gas | | $21 | | November 2019 | | Pending | | In November 2019, NSP-Minnesota filed the 2020 GUIC Rider with the MPUC. The filing included an ROE of 9.04%. Timing of an MPUC ruling is uncertain. |
| 2020 RES | | Electric | | $102 | | November 2019 | | Pending | | In November 2019, NSP-Minnesota filed the 2020 RES Rider with the MPUC. The requested amount includes a true-up for the 2019 rider of $38 million and the 2020 requested amount of $64 million. The filing included an ROE of 9.06%. Timing of an MPUC ruling is uncertain. |
NSP-Minnesota — Minnesota Resource Plan —In July 2019,NSP-Minnesota filed its Minnesota resource plan, which runs through 2034. The plan would result in an 80% carbon reduction by 2030 (from 2005) and puts NSP-Minnesota on a path to achieving its vision of being 100% carbon-free by 2050.
In June 2020, NSP-Minnesota filed a supplement to its resource plan, including new modeling scenarios required by the MPUC. The updated preferred resource plan reflects the following:
•Retirement of all coal generation by 2030 with reduced operations at some units prior to retirement, including the early retirement of the King coal plant (511 MW) in 2028 and the Sherco 3 coal plant (517 MW) in 2030;
•Extending the life of the Monticello nuclear plant from 2030 to 2040;
•Continuing to run the Prairie Island nuclear plant through current end of life (2033 and 2034);
•Construction of the Sherco combined cycle natural gas plant;
•The addition of 3,500 MW of solar;
•The addition of 2,250 MW of wind;
•2,600 MW of firm peaking (combustion turbine, pumped hydro, battery storage, demand response etc.);
•Achieving 780 GWh in energy efficiency savings annually through 2034; and
•Adding 400 MW of incremental demand response by 2023, and a total of 1,500 MW of demand response by 2034.
Initial comments are due Oct. 30, 2020 and reply comments are due Jan. 15, 2021. The MPUC is anticipated to make a final decision in the first half of 2021.
Minnesota Relief and Recovery— In 2020, the MPUC opened a Relief and Recovery docket and invited utilities in the state to submit potential projects that would create jobs and help jump start the economy to offset the impacts of COVID-19. In June 2020, NSP-Minnesota filed a Relief & Recovery proposal which identified approximately $3 billion of capital investment which may assist in Minnesota’s economic recovery from COVID-19. The filing included the following components:
•A wind repowering solicitation that could result in 800 to 1,000 MW with an estimated incremental investment of $1.0 to $1.4 billion;
•A 460 MW solar facility with an incremental investment of approximately $650 million;
•Incremental electric vehicle investment and rebates with an estimated cost of $155 million;
•Accelerated transmission investment of $180 million;
•Accelerated distribution investment of $615 million; and
•Accelerated natural gas investment of $50 million.
The MPUC scheduled a planning meeting to determine the procedural process and next steps.
NSP-Minnesota — Mower Wind Facility —In August 2019, NSP-Minnesota filed a petition with the MPUC to acquire the Mower wind facility from affiliates of NextEra Energy, Inc. The facility is currently contracted under a PPA with NSP-Minnesota through 2026. Mower is expected to continue to have approximately 99 MW of capacity following a planned repowering. The acquisition would occur after repowering, which is expected to be completed in 2020 and qualify for the full PTC. NSP-Minnesota will need approval from both the MPUC and FERC to complete the transaction. The MPUC is expected to rule on the request in the third quarter of 2020.
Minnesota State ROFR Statute Complaint — In September 2017, LSP Transmission filed a complaint in the Minnesota District Court against the Minnesota Attorney General, MPUC and DOC. The complaint was in response to MISO assigning NSP-Minnesota and ITC Midwest, LLC to jointly own a new Mankato-Winnebago 345 KV transmission line (estimatedfrom Mankato to Winnebago, Minnesota. The project is estimated to cost $140 million and projected to be in-service by the end of $108 million),2021. It was assigned to NSP-Minnesota and ITC Midwest as the incumbent utilities, consistent with a Minnesota state ROFR statute.
The complaint challenged the constitutionality of the state ROFR statute and is seeking declaratory judgment that the statute violates the Commerce Clause of the U.S. Constitution and should not be enforced.
The Minnesota state agencies and NSP-Minnesota filed motions to dismiss. In June 2018, the Minnesota District Court granted the defendants’Minnesota state agencies and NSP-Minnesota’s motions
to dismiss with prejudice. LSP Transmission filed an appeal in July 2018. It is uncertain when a decision will be rendered.
MISO Generator Replacement Tariff Change — In February 2019, MISO filed2020, the Eighth Circuit Court of Appeals upheld the Minnesota District Court decision to modifydismiss. In June 2020, the generator interconnection provisions of its tariff to allow generator replacements at existing generation sites. The tariff changes would facilitate the proposed Sherco 1 and 2 coal to natural gas conversion project. Xcel Energy and other parties filed comments in support of the tariff changes. NextEra Energy and the Sierra Club, among others, protested the proposal. In May 2019, FERC issued an order approving the tariff revisions.Eighth Circuit denied LSP Transmission’s petition for rehearing.
Nuclear Power Operations
NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. See Note 12 to the consolidated financial statements of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 20182019, for further information. The circumstances set forth in Nuclear Power Operations and Waste Disposal included in Item 1 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 20182019, appropriately represent, in all material respects, the current status of nuclear power operations, and are incorporated by reference. NSP-Wisconsin
20182019 Electric Fuel Cost Recovery — NSP-Wisconsin’s electric fuel costs for 20182019 were lower than authorized in rates and outside the 2% annual tolerance band, primarily due to increased sales to other utilities compared to the forecast used to set authorized rates. Under the fuel cost recovery rules, NSP-Wisconsin may retain approximately $3.5$3 million of fuel costs and defer the amount of over-recovery in excess of the 2% annual tolerance band for future refund to customers. In March 2019,2020, NSP-Wisconsin filed with the PSCW to provide a refundindicating over-collections of approximately $3.7$10 million to customers and proposed for itrefunds to be issued in September 2019.2020.
2021 Electric Fuel Cost Recovery —In June 2020, NSP-Wisconsin filed an application with the PSCW to update its 2021 fuel costs and return biomass fuel savings, which would decrease retail electric rates for 2021 by approximately $14 million. The PSCW will decide on the application later in 2020.
PSCo
Pending and Recently Concluded Regulatory Proceedings
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Mechanism | | Utility Service | | Amount Requested (in millions) | | Filing
Date | | Approval | | Additional Information |
| CPUC | | | | | | | | | | |
| Rate Case | | Natural Gas | | $127 | | February 2020 | | Pending | | In February 2020, PSCo filed a rate case with the CPUC seeking a net increase to retail gas rates of $126.8 million, reflecting a $144.5 million increase in base rate revenue, partially offset by $17.7 million of costs previously authorized through the Pipeline Integrity rider. The request was based on a 9.95% ROE, an equity ratio of 55.81% and a historic test year as of Sept. 30, 2019, adjusted for known and measurable differences for the 12-month period ended Sept. 30, 2020. In June 2020, PSCo revised its net increase to $121 million. In July 2020, PSCo, the CPUC Staff and various intervenors filed a comprehensive unopposed settlement, which results in a net increase to retail gas rates of $77.3 million, reflecting a $94.1 million increase in base rate revenue, partially offset by $16.8 million of costs previously authorized through the Pipeline Integrity rider. The settlement is based on: •A ROE of 9.20%; •An equity ratio of 55.62%; and •A historic test year as of Sept. 30, 2019, utilizing a year-end rate base, and incorporating a known and measurable adjustment for the Tungsten to Black Hawk pipeline as of April 30, 2020. Rates will be implemented on April 1, 2021 and will be retroactively effective back to November 2020. In July 2020, the ALJ granted an unopposed motion to schedule a hearing for Aug. 13, 2020 to review the settlement. |
| Rate Case | | Electric | | $158 | | May 2019 | | Received | | In 2019, PSCo filed a request with the CPUC seeking a net rate increase of $108.4 million, based on a requested ROE of 10.2% and an equity ratio of 55.6%. In February 2020, the CPUC issued a written decision, resulting in an estimated $34.9 million net base rate revenue increase. The CPUC decision included a 9.3% ROE, an equity ratio of 55.61%, based on a current test year ended Aug. 31, 2019, implementation of decoupling in 2020 and other items. In May 2020, the CPUC deliberated on PSCo’s request for rehearing and revised its prior decision on the test year calculation, return on prepaid pension and medical assets, a disallowance of a capital investment for the Comanche Unit 3 superheater and Board compensation. In July 2020, the CPUC’s written decision was received. As a result, electric rates will increase approximately $12 million, retroactive back to Feb. 25, 2020. In addition, as a part of the rehearing, the CPUC plans to discuss the merits of opening an investigation of Comanche Unit 3 performance. |
| Rate Case Appeal | | Natural Gas | | N/A | | April 2019 | | Pending | | In April 2019, PSCo filed an appeal seeking judicial review of the CPUC’s prior ruling regarding PSCo’s last natural gas rate case (approved in December 2018). The appeal requested review of the following: denial of a return on the prepaid pension and retiree medical assets; the use of a capital structure not based on the actual historical test year; and use of an average rate base methodology rather than a year-end rate base methodology. In March 2020, The District Court of Denver County ruled in favor of allowing the prepaid pension assets to be included in rate base; but it upheld the CPUC treatment of the retiree medical assets and capital structure methodology. The CPUC did not appeal the decision allowing inclusion of the prepaid pension assets in rate base. |
PSCo 2020 Rider Filings
In July 2020, PSCo filed Wildfire and Advanced Grid rider requests with the CPUC instead of filing a comprehensive electric rate case in 2020.
Wildfire Protection Rider — In 2018,Seeks to establish a Wildfire Protection Rider to recover incremental costs associated with system investments to reduce wildfire risk. The rider would be effective no later than June 2021 and continue through 2025. Wildfire Protection capital additions are projected to total approximately $325 million. Forecasted annual revenue requirements from 2021 through 2025 are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 |
| Forecasted annual revenue requirement | | $ | 17 | | | $ | 24 | | | $ | 29 | | | $ | 32 | | | $ | 34 | |
Advanced Grid Rider —Seeks to establish an Advanced Grid Rider to recover incremental costs associated with the NMPRCAdvanced Grid Intelligence and PUCT approved SPS’ proposal to add 1,230 MW of new wind generation, including constructionSecurity Initiative (AGIS). The rider would be effective no later than May 2021 and ownershipcontinue through 2025. The PSCo portion of the 478AGIS initiative is projected to total approximately $850 million of capital additions. Forecasted annual revenue requirements from 2021 through 2025 are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2021 | | 2022 | | 2023 | | 2024 | | 2025 |
| Forecasted annual revenue requirement | | $ | 53 | | | $ | 69 | | | $ | 83 | | | $ | 89 | | | $ | 99 | |
PSCo — Comanche Unit 3
PSCo is part owner of Comanche Unit 3, a 750 MW, hale and 522 MW Sagamore wind farms. The Hale wind project was placed into commercial operation incoal-fueled electric generating unit. PSCo is the operating agent under the joint ownership agreement. In June 2019.
SPS2020, the unit experienced loss of turbine oil during start-up which damaged the plant. It is currently waiting to receive the transmission cost estimate from SPP for Sagamore, which is necessary to determine the final cost of the project before construction can start. Sagamore is expected to go into service in late 2020. SPS’ capital investment for Hale and Sagamore is expected to be approximately $1.6 billion.
Texas State (ROFR) Request for Declaratory Order — In 2017, SPS and SPP filed a joint petition with the PUCT for a declaratory order regarding SPS’ ROFR. SPS contendedanticipated that Texas law grants an incumbent electric utility the ROFR to construct new transmission facilities located in the utility’s service area. The PUCT subsequently issued an order finding that SPS does not possess an exclusive right to construct and operate transmission facilities. SPS filed an appealComanche Unit 3 will recommence operations in the fourth quarter of 2018. Subsequent2020. Replacement and repair of damaged systems in excess of a $2 million deductible are expected to be recovered through insurance policies. PSCo has obtained replacement power for a portion of the unit’s output through purchase power agreements.
Boulder Municipalization
In 2011, Boulder passed a ballot measure authorizing the formation of an electric municipal utility, subject to certain conditions. Subsequently, there have been various legal proceedings in multiple venues with jurisdiction over Boulder’s plan. In 2014, the Boulder City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility and the Colorado Court of Appeals ruled in PSCo’s favor, vacating a lower court decision. In June 2018, the Colorado Supreme Court rejected Boulder’s request to dismiss the case and remanded it to the Boulder District Court. The case was then settled in June 2019 after Boulder agreed to repeal the ordinance establishing the utility.
Boulder has filed multiple separation applications with the CPUC, which have been challenged by PSCo and other intervenors. In September 2017, the CPUC issued a written decision, agreeing with several key aspects of PSCo’s position. The CPUC has approved the designation of some electrical distribution assets for transfer, subject to Boulder completing certain filings.
In the fourth quarter of 2018, the Boulder City Council also adopted an Ordinance authorizing Boulder to begin negotiations for the acquisition of certain property or to otherwise condemn that appeal,property after Feb. 1, 2019. In the first quarter of 2019, Boulder sent PSCo a notice of intent to acquire certain electric distribution assets. In the third quarter of 2019, Boulder filed its condemnation litigation, which was later dismissed by the Boulder District Court in MaySeptember 2019 on the grounds that Boulder had not completed the pre-requisite CPUC process and filings. Boulder is currently appealing this order. In October 2019, the CPUC approved the subsequent filings regarding asset transfers outside of substations, reaffirmed its 2017 decision on assets outside of substations and closed the CPUC proceeding.
In December 2019, Boulder filed a new condemnation action despite its ongoing appeal of the last condemnation case. PSCo subsequently filed a motion to dismiss or stay the new condemnation action. In February 2020, Boulder filed an application under section 210 of the Federal Power Act asking FERC to order PSCo to interconnect its facilities with a future Boulder municipal utility under Boulder’s preferred terms and conditions.
In July 2020, PSCo reached a settlement with certain Boulder officials that would end the city’s effort to municipalize. The settlement, if approved, would result in a 20-year franchise arrangement (with multiple opt-out conditions), an energy partnership, an undergrounding agreement and establish how the municipalization would move forward if Boulder exercised an opt-out. The settlement will require approval by the Boulder City Council in August 2020 and will further require approval by the citizens of Boulder in a ballot referendum in November 2020.
SPS
Pending and Recently Concluded Regulatory Proceedings
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Mechanism | | Utility Service | | Amount Requested (in millions) | | Filing
Date | | Approval | | Additional Information |
| NMPRC | | | | | | | | | | |
| Rate Case | | Electric | | $31 | | July 2019 | | Received | | In July 2019, SPS filed an electric rate case with the NMPRC seeking an increase in retail electric base rates of approximately $51 million. The rate request was based on an ROE of 10.35%, an equity ratio of 54.77%, a rate base of approximately $1.3 billion and a historic test year with rate base additions through Aug. 31, 2019. In December 2019, SPS revised its base rate increase request to approximately $47 million, based on an ROE of 10.10% and updated information. The request also included an increase of $14.6 million for accelerated depreciation including the early retirement of the Tolk coal plant in 2032.
In January 2020, SPS and various parties filed an uncontested comprehensive stipulation. The stipulation includes a base rate revenue increase of $31 million, an ROE of 9.45% and an equity ratio of 54.77%. The stipulation also includes an acceleration of depreciation on the Tolk coal plant to reflect early retirement in 2037, which results in a total increase in depreciation expense of $8 million. The parties to the stipulation agreed not to oppose the full application of depreciation rates associated with the 2032 retirement date in SPS’ next base rate case. On May 11, 2020, the Hearing Examiner issued a Certification of Stipulation recommending approval of the uncontested comprehensive stipulation without modification. On May 20, 2020, the NMPRC approved the stipulation without modification. New rates and tariffs were effective beginning May 28, 2020. |
| PUCT | | | | | | | | | | |
| Rate Case | | Electric | | $141 | | August 2019 | | Pending | | In August 2019, SPS filed an electric rate case with the PUCT seeking an increase in retail electric base rates of approximately $141 million. The filing requests an ROE of 10.35%, a 54.65% equity ratio, rate base of approximately $2.6 billion and utilizes a historic 12 month period that ended June 30, 2019. SPS’ request was subsequently revised in March 2020 to approximately $130 million, based on a requested ROE of 10.1%, a 54.62% equity ratio, rate base of approximately $2.6 billion and historic test year ended June 30, 2019.
On May 20, 2020, SPS, the PUCT Staff and various intervenors reached an uncontested settlement, which includes: •An electric rate increase of $88 million and a reset of the Transmission Cost Recovery Factor to zero; •ROE of 9.45% and equity ratio of 54.62% for AFUDC purposes; •Depreciation rates: ◦Tolk - 2037 end-of-life date; ◦Hale - 25-year end-of-life date; ◦All other generating units - end-of-life dates as proposed by SPS; and ◦Transmission - 35% of the incremental change between existing depreciation rates and rates proposed by SPS. •Ring-fencing measures like those in other recent PUCT settlements, including: ◦Credit agreements and indentures (e.g., no cross-default provisions); ◦Financial covenants; ◦Restrictions on pledging of assets and securing debt; ◦Maintaining stand-alone credit facility and ratings; and ◦Affiliate and non-affiliate limitations. Final rates are expected to be retroactively applied as of Sept. 12, 2019. A decision from the PUCT is anticipated in the third quarter of 2020. |
Texas legislature passed andState ROFR Litigation — In May 2019, the Governor signed into law Senate Bill 1938, thus making SPS’ appeal moot. A motion is pending at the Court of Appeals to dismiss the appeal for mootness. Senate Bill 1938which grants incumbent utilities a ROFR to build transmission infrastructure when the transmissionit directly interconnects to the utility’s existing facility. In June 2019, a complaint was filed in the United States District Court for the Western District of Texas claiming the new ROFR law set forth in Senate bill 1938 to be unconstitutional. SPS expectsIn February 2020, the federal court complaint was dismissed by the district court. In March 2020, the district court ruling was appealed to intervene in this litigation in supportthe United States Court of Appeals for the PUCT and the Senate Bill 1938.Fifth Circuit. The parties are awaiting a decision.
Texas Fuel ReconciliationRefund —Fuel and purchased power costs are recoverable in Texas through a fixed fuel factor, which is part of SPS’ rates. The PUCT rule requires refunding or surcharging of under and over-recovered amounts, including interest, when they exceed 4% of the utility’s annual fuel costs.
SPS’ 2019 total fuel and purchased power costs were over-collected by approximately $39 million. As a result, SPS filed a request with the PUCT to refund the amount to customers. In December 2018,April 2020, interim rates were granted by a Texas ALJ. This case is pending final review and approval by the PUCT.
New Mexico FPPCAC Continuation — In October 2019, SPS filed an application to the PUCTNMPRC to approve SPS’ continued use of its FPPCAC and for reconciliation of fuel costs for the period Jan.Sept. 1, 2016,2015, through June 30, 2018, where it2019, which will be determineddetermine whether all fuel costs incurred during the period wereare eligible for recovery. Parties inSPS also proposed that it annually review its average New Mexico Deferred Fuel and Purchased Power balance and requests the proceeding have asserted that certain Texas retailNMPRC approve an Annual Deferred Fuel Balance True-Up. The proposed true-up is designed to maintain the Deferred Fuel and Purchased Power balance within a bandwidth of plus or minus 5% of annual New Mexico fuel costs of upand purchased power costs. A public hearing is scheduled to approximately $4 million, should not be found to be reasonable or prudent, in particular regarding two purchase power agreements for solar power. The hearing was held in July 2019; we are unable to predict the outcome of this proceeding at this time.begin on Aug. 20, 2020.
Environmental MattersRegulation
In JuneJuly 2019, the EPA issuedadopted the final ACEAffordable Clean Energy rule, which requires states to replacedevelop plans for greenhouse gas reductions from coal-fired power plants. The state plans, due to the Obama-era Clean Power Plan. The final ACE rule mayEPA in July 2022, will evaluate and potentially require implementation of heat rate improvement projectsimprovements at some of ourexisting coal-fired power plants. It is not yet known what the costs associated with the final rule might be untilhow these state plans are developed to implement the final regulation.will affect our existing coal plants, but they could require substantial additional investment, even in plants slated for retirement. Xcel Energy believes, based on prior state commission practice, the cost of these initiatives or replacement generation would be recoverable through rates.
| | |
| Derivatives, Risk Management and Market Risk |
Xcel Energy Inc. and its subsidiariesWe are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.
See Note 8 to the consolidated financial statements for further discussion of market risks associated with derivatives.
Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, when necessary, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While Xcel Energy expectswe expect that the counterparties will perform under the contracts underlying its derivatives, the contracts expose Xcel Energyus to some credit and non-performance risk.
Though no material non-performance risk currently exists with the counterparties to Xcel Energy’s commodity derivative contracts, distress in the financial markets may in the future impact that risk to the extent it impacts those counterparties. Distress in the financial markets may also impact counterparty risk, the fair value of the securities in the nuclear decommissioning fund and master pension trust, as well asfund and Xcel Energy’s ability to earn a return on short-term investments of excess cash.investments.
Commodity Price Risk — Xcel Energy Inc.’s utility subsidiariesWe are exposed to commodity price risk in theirour electric and natural gas operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and for various fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Xcel Energy’sOur risk management policy allows it to manage commodity price risk within each rate-regulated operation to the extent such exposure exists.per commission approved hedge plans.
Wholesale and Commodity Trading Risk — Xcel Energy Inc.’s utility subsidiaries conductconducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Xcel Energy’sOur risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.committee.
At June 30, 2019, the fair values by source forFair value of net commodity trading contract assets werecontracts as follows:of June 30, 2020:
| | | | | Futures / Forwards | | Futures / Forwards Maturity | |
| (Millions of Dollars) | | Source of Fair Value | | Maturity
Less Than 1 Year | | Maturity 1 to 3 Years | | Maturity 4 to 5 Years | | Maturity
Greater Than 5 Years | | Total Futures/
Forwards Fair Value | (Millions of Dollars) | | Less Than 1 Year | | 1 to 3 Years | | 4 to 5 Years | |
Greater Than 5 Years | | Total Fair Value |
NSP-Minnesota (a) | | NSP-Minnesota (a) | | $ | — | | | $ | — | | | $ | 3 | | | $ | 3 | | | $ | 6 | |
NSP-Minnesota | | 1 |
| | $ | (3 | ) | | $ | 6 |
| | $ | 2 |
| | $ | — |
| | $ | 5 |
| | — | | | (2) | | | (4) | | | (5) | | | (11) | |
| NSP-Minnesota | | 2 |
| | 9 |
| | (2 | ) | | (2 | ) | | (4 | ) | | 1 |
| |
| PSCo | | 1 |
| | 2 |
| | 2 |
| | — |
| | — |
| | 4 |
| | (1) | | | (40) | | | (15) | | | — | | | (56) | |
| | | | | $ | 8 |
| | $ | 6 |
| | $ | — |
| | $ | (4 | ) | | $ | 10 |
| | $ | (1) | | | $ | (42) | | | $ | (16) | | | $ | (2) | | | $ | (61) | |
| | | | | Options | | Options Maturity | |
| (Millions of Dollars) | | Source of Fair Value | | Maturity
Less Than 1 Year | | Maturity 1 to 3 Years | | Maturity 4 to 5 Years | | Maturity
Greater Than 5 Years | | Total Futures/
Forwards Fair Value | (Millions of Dollars) | | Less Than 1 Year | | 1 to 3 Years | | 4 to 5 Years | |
Greater Than 5 Years | | Total Fair Value |
| NSP-Minnesota | | 2 |
| | $ | 4 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 6 |
| |
NSP-Minnesota (b) | | NSP-Minnesota (b) | | $ | — | | | $ | 3 | | | $ | — | | | $ | — | | | $ | 3 | |
PSCo (b) | | PSCo (b) | | — | | | (1) | | | — | | | — | | | (1) | |
| | | | | $ | 4 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 6 |
| | $ | — | | | $ | 2 | | | $ | — | | | $ | — | | | $ | 2 | |
1 — (a)Prices actively quoted or based on actively quoted prices.
2 —(b) Prices based on models and other valuation methods.
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing mechanisms for the six months ended June 30, were as follows:30:
| | | (Millions of Dollars) | | 2019 | | 2018 | (Millions of Dollars) | | 2020 | | 2019 |
| Fair value of commodity trading net contract assets outstanding at Jan. 1 | | $ | 17 |
| | $ | 16 |
| |
| Fair value of commodity trading net contract (liabilities) assets outstanding at Jan. 1 | | Fair value of commodity trading net contract (liabilities) assets outstanding at Jan. 1 | | $ | (59) | | | $ | 17 | |
| Contracts realized or settled during the period | | (8 | ) | | (4 | ) | Contracts realized or settled during the period | | (7) | | | (8) | |
| Commodity trading contract additions and changes during the period | | 7 |
| | 5 |
| Commodity trading contract additions and changes during the period | | 7 | | | 7 | |
| Fair value of commodity trading net contract assets outstanding at June 30 | | $ | 16 |
| | $ | 17 |
| |
| Fair value of commodity trading net contract (liabilities) assets outstanding at June 30 | | Fair value of commodity trading net contract (liabilities) assets outstanding at June 30 | | $ | (59) | | | $ | 16 | |
At June 30, 2020, a 10% increase in market prices for commodity trading contracts would increase pre-tax income from continuing operations by approximately $12 million, whereas a 10% decrease would decrease pre-tax income from continuing operations by approximately $12 million. At June 30, 2019, a 10% increase in market prices for commodity trading contracts would decrease pretaxpre-tax income from continuing operations by approximately $2 million, whereas a 10% decrease would increase pretaxpre-tax income from continuing operations by approximately $2 million. At June 30, 2018, a 10% increase in market prices for commodity trading contracts would decrease pretax income from continuing operations by an immaterial amount, whereas a 10% decrease would increase pretax income from continuing operations by approximately $1 million.
Xcel Energy Inc.’sThe utility subsidiaries’ wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as Value at Risk (VaR). VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time under normal market conditions.
The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchase, normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:
|
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Three Months Ended June 30 | | VaR Limit | | Average | | High | | Low |
| 2019 | | $ | 1.05 |
| | $ | 3.00 |
| | $ | 0.93 |
| | $ | 1.26 |
| | $ | 0.68 |
|
| 2018 | | 0.11 |
| | 3.00 |
| | 0.16 |
| | 0.44 |
| | 0.06 |
|
In November 2018, management temporarily increased the VaR limit to accommodate a 10-year transaction. NSP-Minnesota has been systematically hedging the transaction and the consolidated VaR returned below $3 million in early January 2019. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Three Months Ended June 30 | | VaR Limit | | Average | | High | | Low |
| 2020 | | $ | 0.8 | | | $ | 3.0 | | | $ | 0.9 | | | $ | 1.1 | | | $ | 0.6 | |
| 2019 | | 1.1 | | | 3.0 | | | 0.9 | | | 1.3 | | | 0.7 | |
Nuclear Fuel Supply — NSP-Minnesota is scheduled to take delivery ofhas contracted for approximately 49% of its remaining 2019 and approximately 50%51% of its 2020 enriched nuclear material requirements from sources that could be impacted by events in Ukraine and extended sanctions against entities doing business with Iran. Those sanctions may impact the supply of enriched nuclear material supplied from Russia. Long-term, through 2024,2030, NSP-Minnesota is scheduled to take delivery of approximately 35%30% of its average enriched nuclear material requirements from these sources. Alternate potential sources provide the flexibility to manage NSP-Minnesota’s nuclear fuel supply. NSP-Minnesota periodically assesses if further actions are required to assure a secure supply of enriched nuclear material.
Disruptions in third party nuclear fuel supply contracts due to bankruptcies or change of contract assignments have not materially impacted NSP-Minnesota’s operational or financial performance.
Interest Rate Risk — Xcel Energy is subject to the risk of fluctuating interest rates in the normal course of business. Xcel Energy’srate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.
At June 30, 20192020 and 2018,2019, a 100-basis-point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pretaxpre-tax interest expense annually by approximately $14 million and $17 million, and $8 million, respectively.
See Note 8 to the consolidated financial statements for a discussion of Xcel Energy Inc. and its subsidiaries’ interest rate derivatives.
NSP-Minnesota also maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate risk and equity price risk. At June 30, 2019, theThe fund wasis invested in a diversified portfolio of cash equivalents, debt securities, equity securities, and other investments.
These investments may be used only for activities related topurpose of decommissioning NSP-Minnesota’s nuclear decommissioning. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, any realizedgenerating plants.
Realized and unrealized gains and losses on securities in the nuclear decommissioning fund including any other-than-temporary impairments,investments are deferred as a componentan offset of theNSP-Minnesota’s regulatory asset for nuclear decommissioning. Since the accounting for nuclear decommissioning recognizes that costs are recovered through rates, fluctuationscosts. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings.earnings due to the application of regulatory accounting.
Changes in discount rates and expected return on plan assets impact the value of pension and postretirement plan assets and/or benefit costs.
Credit Risk — Xcel Energy Inc. and its subsidiaries areis also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. Xcel Energy Inc. and its subsidiaries maintainmaintains credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.
At June 30, 2020, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $27 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $2 million. At June 30, 2019, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $14 million, while a decrease in prices of 10% would have resulted in an increase in credit exposure of $16 million. At June 30, 2018, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $24 million, while a decrease in prices of 10% would have resulted in an increase in credit exposure of $6 million.
Xcel Energy Inc. and its subsidiaries conduct standardconducts credit reviews for all counterparties. Xcel Energycounterparties and employs additional credit risk control, mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures.provisions. Credit exposure is monitored and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase Xcel Energy’sour credit risk.
Xcel Energy follows accountinguses derivative contracts such as futures, forwards, interest rate swaps, options and disclosure guidance onFTRs to manage commodity price and interest rate risk. Derivative contracts, with the exception of those designated as normal purchase-normal sale contracts, are reported at fair value.
The Company’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value measurements that contains a hierarchy for inputs used in measuring fair value and requires disclosure of the observability of the inputs used in these measurements. accounting.
See Note 8 to the consolidated financial statements for further discussion of the fair value hierarchy and the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.
Commodity Derivatives — Xcel Energy continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment and the typically short duration of these contracts, thetransactions. The impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at June 30, 2019. 2020.
Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are deferred as other comprehensive income or deferred as regulatory assets and liabilities. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Xcel Energy also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities. The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair value of commodity derivative liabilities at June 30, 2019.2020.
Liquidity and Capital Resources | | |
| LIQUIDITY AND CAPITAL RESOURCES |
| | | | | Six Months Ended June 30 | | Six Months Ended June 30 | |
| (Millions of Dollars) | | 2019 | | 2018 | (Millions of Dollars) | | 2020 | | 2019 |
| Cash provided by operating activities | | $ | 1,334 |
| | $ | 1,437 |
| Cash provided by operating activities | | $ | 1,148 | | | $ | 1,334 | |
Net cash provided by operating activities decreased $103$186 million for the six months ended June 30, 20192020 compared with the six months ended June 30, 2018.prior year. Decrease (excluding amounts related to non-cash operating activities (e.g., depreciation and amortization and deferred tax expenses) was primarily due to: increased refunds associated with TCJA, higher purchased gas payable amounts in December 2018 (price and volume increased due to colder weather), decreases in purchased power accounts payable and changes in accounts payable due to timing, partially offset by changes inlower collections on accounts receivable (due to milder weather in 2019).as a result of the COVID-19 pandemic and reduced O&M expenditures.
| | | | | Six Months Ended June 30 | | Six Months Ended June 30 | |
| (Millions of Dollars) | | 2019 | | 2018 | (Millions of Dollars) | | 2020 | | 2019 |
| Cash used in investing activities | | $ | (1,708 | ) | | $ | (1,865 | ) | Cash used in investing activities | | $ | (2,580) | | | $ | (1,708) | |
Net cash used in investing activities decreased $157increased $872 million for the six months ended June 30, 20192020 compared with the six months ended June 30, 2018. Decreaseprior year. Increase was primarily attributable to Rush Creek being placed into service in 2018 and Hale being placed into service in June 2019, partially offsetdriven by additional capital expenditures (primarily for Foxtail and Blazing Star wind facilities, nuclear refueling costs and transmission investments.projects) as well as the purchase of MEC in January 2020.
| | | | | Six Months Ended June 30 | | Six Months Ended June 30 | |
| (Millions of Dollars) | | 2019 | | 2018 | (Millions of Dollars) | | 2020 | | 2019 |
| Cash provided by financing activities | | $ | 580 |
| | $ | 677 |
| Cash provided by financing activities | | $ | 2,818 | | | $ | 580 | |
Net cash provided by financing activities decreased $97increased $2,238 million for the six months ended June 30, 20192020 compared with the six months ended June 30, 2018. Decreaseprior year. Increase was primarily attributable to repayments of previously existing long-term debt and lower proceeds from issuanceissuances of long-term debt, partially offset by higher net proceeds from short-term borrowings needed for subsidiary equity infusions to maintain required equity ratios.debt.
Capital Requirements
Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios.
Pension Fund — Xcel Energy’s pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities, and alternative investments, including private equity, real estate and hedge funds.
In July 2019, Xcel Energy made a $4 million contribution to the Xcel Energy Inc. Non-Bargaining Pension Plan (South);
•In January 2019,2020, contributions of $150 million were made across four of Xcel Energy’s pension plans;plans.
•In 2018,2019, contributions of $150$154 million were made across four of Xcel Energy’s pension plans; andplans.
•For future years, contributions will be made as deemed appropriate based on evaluation of various factors including the funded status of the plans, minimum funding requirements, interest rates and expected investment returns.
