UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
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| ☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 20192020 or
or
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| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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| 001-03789 |
| (Commission File Number) |
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| SOUTHWESTERN PUBLIC SERVICE COMPANY |
| (Exact name of registrant as specified in its charter) |
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| New Mexico | 75-0575400 |
| (State or Other Jurisdiction of Incorporation or Organization) | (IRS Employer Identification No.)
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| 790 South Buchanan Street, | Amarillo, | Texas
| | | 79101 | |
(Address of Principal Executive Offices)
| | (Zip Code) | |
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| (303) | 571-7511 | | | |
| (Registrant’s Telephone Number, Including Area Code) |
Securities registered pursuant to Section 12(b) of the Act:
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| Title of each class | | Trading Symbol | | Name of each exchange on which registered |
| N/A | | N/A | | N/A |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒ Yes ☐ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes ☒ No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act. ☐ Large accelerated Filer ☐ Accelerated Filer ☒ Non-accelerated Filer☐ Smaller Reporting Company ☐ Emerging Growth Company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No
As of Feb. 21, 2020,17, 2021, 100 shares of common stock, par value $1.00 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm – Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the 20202021 Annual Meeting of Shareholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 6, 2020.2021. Such information set forth under such heading is incorporated herein by this reference hereto.
Southwestern Public Service Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).
TABLE OF CONTENTS
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| PART I | | |
| Item 1 — | | |
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| Item 1A — | | |
| Item 1B — | | |
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PART III | | |
Item 1 — | | |
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Item 1A — | | |
Item 1B — | | |
Item 2 — | | |
Item 3 — | | |
Item 4 — | | |
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PART II | | |
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| Item 7 — | | |
| Item 7A — | | |
| Item 8 — | | |
| Item 9 — | | |
| Item 9A — | | |
| Item 9B — | | |
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| PART III | | |
| Item 10 — | | |
| Item 11 — | | |
| Item 12 — | | |
| Item 13 — | | |
| Item 14 — | | |
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| PART IV | | |
| Item 15 — | | |
| Item 16 — | | |
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This Form 10-K is filed by SPS.Southwestern Public Service Company, a New Mexico corporation (SPS). SPS is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available on various filings with the SEC.Securities and Exchange Commission. This report should be read in its entirety.
PART I
Definitions of Abbreviations
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| Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former) |
| NSP-Minnesota | Northern States Power Company, a Minnesota corporation |
| NSP-Wisconsin | Northern States Power Company, a Wisconsin corporation |
| PSCo | Public Service Company of Colorado |
| SPS | Southwestern Public Service Company |
| Utility subsidiaries | NSP-Minnesota, NSP-Wisconsin, PSCo and SPS |
| Xcel Energy | Xcel Energy Inc. and its subsidiaries |
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| Federal and State Regulatory Agencies |
| D.C. Circuit | United States Court of Appeals for the District of Columbia Circuit |
| EPA | United States Environmental Protection Agency |
| FERC | Federal Energy Regulatory Commission |
| IRS | Internal Revenue Service |
| NERC | North American Electric Reliability Corporation |
| NMPRC | New Mexico Public Regulation Commission |
NPRMPHMSA | Notice of Proposed Rulemaking |
PHMSA | Pipeline and Hazardous Materials Safety Administration |
| PUCT | Public Utility Commission of Texas |
| SEC | Securities and Exchange Commission |
| TCEQ | Texas Commission on Environmental Quality |
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| Electric and Resource Adjustment Clauses |
| DCRF | Distribution cost recovery factor |
| DSM | Demand side management |
EEEECRF | Energy efficiency |
EECRF | Energy efficiency cost recovery factor |
| FPPCAC | Fuel and purchased power cost adjustment clause |
| PCRF | Power cost recovery factor |
| RPS | Renewable portfolio standards |
| TCRF | Transmission cost recovery factor (recovers transmission infrastructure improvement costs and changes in wholesale transmission charges) |
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| Other |
| ADIT | Accumulated deferred income taxes |
| AFUDC | Allowance for funds used during construction |
| ALJ | Administrative Law Judge |
| ARO | Asset retirement obligation |
| ASC | FASB Accounting Standards Codification |
| ASU | FASB Accounting Standards Update |
| BART | Best available retrofit technology |
| CEO | Chief executive officer |
| CFO | Chief financial officer |
| C&I | Commercial and Industrial |
CorpsCOVID-19 | U.S. Army Corps of EngineersNovel coronavirus |
| CWIP | Construction work in progress |
| DSM | Demand side management |
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| ELG | Effluent limitations guidelines |
| ETR | Effective tax rate |
| FASB | Financial Accounting Standards Board |
| FTR | Financial transmission right |
| GAAP | Generally accepted accounting principles |
| GHG | Greenhouse gas |
| IM | Integrated Marketplace |
| IPP | Independent power producing entity |
| IRP | Integrated Resource Plan |
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| ITC | |
ITC | Investment tax credit |
| MGP | Manufactured gas plant |
| Moody’s | Moody’s Investor Services |
| NAAQS | National Ambient Air Quality Standard |
| Native load | Customer demand of retail and wholesale customers whereby a utility has an obligation to serve under statute or long-term contract.contract |
| NAV | Net asset value |
| NOL | Net operating loss |
| O&M | Operating and maintenance |
| OATT | Open Access Transmission Tariff |
| PPA | Purchased power agreement |
PRPPTC | Potentially responsible party |
PTC | Production tax credit |
| REC | Renewable energy credit |
| ROE | Return on equity |
| ROFR | Right-of-first-refusal |
| ROU | Right-of-use |
| RTO | Regional Transmission Organization |
| SERP | Supplemental executive retirement plan |
SO2 | Sulfur dioxide |
| SPP | Southwest Power Pool, Inc. |
Standard & Poor’sS&P | Standard & Poor’s Global Ratings Services |
| TCJA | 2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act |
| VIE | Variable interest entity |
| WOTUS | Waters of the U.S. |
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| Measurements |
| KV | Kilovolts |
| KWh | Kilowatt hours |
| MMBtu | Million British thermal units |
| MW | Megawatts |
| MWh | Megawatt hours |
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Measurements |
KV | Kilovolts |
KWh | Kilowatt hours |
MMBtu | Million British thermal units |
MW | Megawatts |
MWh | Megawatt hours |
ppb | Parts per billion |
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Forward-Looking Statements
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Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including future sales, future bad debt expense, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings and expectations regarding regulatory proceedings, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information.
The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 20192020 (including risk factors listed from time to time by SPS in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K hereto), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: uncertainty around the impacts and duration of the COVID-19 pandemic; operational safety; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee work force and third-party contractor factors; ability to recover costs,costs; changes in regulation and subsidiaries’ ability to recover costs from customers;regulation; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of SPS to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; our subsidiaries’ ability to make dividend payments; tax laws; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; and costs of potential regulatory penalties.
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Where to Find More Information
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SPS is a wholly owned subsidiary of Xcel Energy Inc., and Xcel Energy’s website address is www.xcelenergy.com. Xcel Energy makes available, free of charge through its website, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the SEC. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically at http://www.sec.gov. The information on Xcel Energy’s website is not a part of, or incorporated by reference in, this annual report on Form 10-K.
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| Electric customers | 0.4 million | | | SPS was incorporated in 1921 under the laws of New Mexico. SPS conducts business in Texas and New Mexico and generates, purchases, transmits, distributes and sells electricity. |
| Total assets | $7.98.9 billion | | |
Rate baseBase (estimated) | $4.95.4 billion | | |
| ROE (net income / average stockholder's equity) | 9.71%9.54% | | |
| Electric generating capacity | 4,8045,232 MW | | |
Electric transmission lines (conductor miles)
| 38,41840,019 miles | | |
Electric distribution lines (conductor miles)
| 21,81021,984 miles | | | |
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Electric operations consist of energy supply, generation, transmission and distribution activities. SPS had electric sales volume of 30,89431,084 (millions of KWh), 395,8280.4 million customers and electric revenues of $1,825.8$1,870 (millions of dollars) for 2019.2020.
Sales/Revenue Statistics(a)
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| | 2020 | | 2019 |
| KWH sales per retail customer | | 51,694 | | | 53,123 | |
| Revenue per retail customer | | $ | 2,925 | | | $ | 3,147 | |
| Residential revenue per KWh | | 9.77 | ¢ | | 10.04 | ¢ |
| Large C&I revenue per KWh | | 3.65 | ¢ | | 4.01 | ¢ |
| Small C&I revenue per KWh | | 6.99 | ¢ | | 7.17 | ¢ |
| Total retail revenue per KWh | | 5.66 | ¢ | | 5.92 | ¢ |
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| | | 2019 | | 2018 |
| KWH sales per retail customer | | 53,123 |
| | 52,074 |
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| Revenue per retail customer | | $3,147 |
| | $3,124 |
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| Residential revenue per KWh | |
| 10.04 | ¢ | |
| 9.92 | ¢ |
| Large C&I revenue per KWh | |
| 4.01 | ¢ | |
| 4.08 | ¢ |
| Small C&I revenue per KWh | |
| 7.17 | ¢ | |
| 7.22 | ¢ |
| Total retail revenue per KWh | |
| 5.92 | ¢ | |
| 6.00 | ¢ |
Owned and Purchased Energy Generation — 20192020
Electric Energy Sources
Total electric generation by source (including energy market purchases) for the year ended Dec. 31, 2019:
*Distributed generation from the Solar*Rewards® program is not included (approximately 12.914 million KWh for 2019)2020). RenewableCarbon–Free Energy Sources
SPS’ renewablecarbon–free energy portfolio includes wind and solar power from both owned generating facilities and PPAs. RenewableCarbon–free percentages will vary year over year based on system additions, weather, system demand and transmission constraints.
See Item 2 — Properties for further information.
RenewableCarbon–free energy as a percentage of total energy for 2019:2020:
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(a)
| Includes biomass and hydroelectric. |
Wind Energy Sources
Owned — Owned and operated wind farms with corresponding capacity:
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| 2020 | | 2019 |
| Wind Farms | | Capacity (a) | | Wind Farms | | Capacity (b) |
| 2 | | 967 MW | | 1 | | 460 MW |
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| 2019 | | 2018 |
| Wind Farms | | Capacity | | Wind Farms | | Capacity |
| 1 | | 478 MW | | — | | — |
(b) Summer 2019 net dependable capacity.
PPAs — Number of PPAs with capacity range: | | | 2019 | | 2018 | |
| 2020 | | 2020 | | 2019 |
| PPAs | | Range | | PPAs | | Range | PPAs | | Range | | PPAs | | Range |
| 18 | | 0.7 MW - 250.0 MW | | 18 | | 0.7 MW - 250.0 MW | 18 | | 1 MW — 250 MW | | 18 | | 1 MW — 250 MW |
Capacity — Wind capacity:
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| 2019 | | 2018 |
| 2,045 MW | | 1,565 MW |
Average Cost (PPAs) — Average cost per MWh of wind energy under existing PPAs:
Wind Energy Development
SPS placed approximately 460500 MW of owned wind into service during 2019:
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Project | | Capacity |
Hale | | 460 MW |
SPS currently has approximately 522 MW of wind under development or construction with an estimated completion date of 2020:
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| Project | | Capacity | | Estimated Completion(a)(b) |
| Sagamore | | 522507 MW | | 2020 |
(a)Summer 2020 net dependable capacity.
(b)Values disclosed are the maximum generation levels for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).
Solar Energy Sources
Solar energy PPAs:
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| Type | | Capacity |
| Distributed Generation | | 1011 MW |
| Utility-Scale | | 191190 MW |
| Total | | 201 MW |
Average Cost (PPAs) — Average cost per MWh of solar energy under existing PPAs:
Fossil Fuel Energy Sources
SPS’ fossil fuel energy portfolio includes coal and natural gas power from both owned generating facilities and PPAs.
See Item 2 — Properties for further information.
Coal Energy Sources
SPS has twoowns and operates coal plantsunits with approximately 2,100 MW of total 20192020 net summer dependable capacity.
SPS plans to continue to evaluate its coal fleet for other potential
Approved and proposed early coal plant retirements as partretirements:
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| Approved / Authorized |
| Year | | Plant Unit | | Capacity |
| 2024 | | Harrington(a) | | 1,018 MW |
(a)Reflects expected conversion from coal to natural gas following the TCEQ order that Harrington cease use of state resource plans or other regulatory proceedings.coal fuel by Jan. 1, 2025, pending PUCT and NMPRC review.
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| Proposed |
| Year | | Plant Unit | | Capacity |
| 2032 | | Tolk 1 | | 532 MW |
| 2032 | | Tolk 2 | | 535 MW |
Coal Fuel Cost
Delivered cost per MMBtu of coal consumed for owned electric generation and percentage of total fuel requirements:
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| | Coal |
| | Cost | | Percent |
| 2020 | | $ | 2.28 | | | 40 | % |
| 2019 | | 2.19 | | | 45 | |
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| | | Coal |
| | | Cost | | Percent |
| 2019 | | $ | 2.19 |
| | 45 | % |
| 2018 | | 2.04 |
| | 56 |
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Natural Gas Energy Sources
SPS has eight natural gas plants with approximately 2,300 MW of total 2019 net summer dependable capacity.
Natural gas supplies, transportation and storage services for power plants are procured to provide an adequate supply of fuel. Remaining requirements are procured through a liquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to natural gas indices. Natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes or payments in lieu of delivery.
Natural Gas Cost
Delivered cost per MMBtu of natural gas consumed for owned electric generation and percentage of total fuel requirements:
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| | | Natural Gas |
| | | Cost | | Percent |
| 2019 | | $ | 1.14 |
| | 55 | % |
| 2018 | | 2.24 |
| | 44 |
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Capacity and Demand
Uninterrupted system peak demand and occurrence date:
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| System Peak Demand (in MW) |
| 2019 | | 2018 |
| 4,261 |
| | Aug. 5 | | 4,648 |
| | July 19 |
Transmission
Transmission lines deliver electricity over long distances from power sources to transmission substations closer to homes and businesses. A strong transmission system ensures continued reliable and affordable service, ability to meet state and regional energy policy goals, and support a diverse generation mix, including renewable energy. SPS owns more than 38,400 conductor miles of transmission lines across its service territory.
During 2019, SPS completed the following transmission projects:
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Project | | Miles | | Size |
TUCO-Yoakum-Hobbs | | 64 |
| | 345 KV |
NEF-Cardinal | | 15 |
| | 115 KV |
Potash Junction-Livingston Ridge | | 15 |
| | 115 KV |
Mustang-Shell | | 9 |
| | 115 KV |
North Loving-South Loving | | 3 |
| | 115 KV |
Cunningham-Monument Tap | | 7 |
| | 115 KV |
Upcoming transmission projects:
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| Project | | Miles | | Size | | Completion Date |
| TUCO-Yoakum-Hobbs | | 106 |
| | 345 KV | | 2020 |
| Eddy-Kiowa | | 34 |
| | 345 KV | | 2020 |
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Public Utility Regulation |
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction |
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Regulatory Body | | Additional Information on Regulatory Authority |
PUCT | | Retail electric operations, rates, services, construction of transmission or generation and other aspects of electric operations.
Texas municipalities have original jurisdiction over rates in those communities. The municipalities’ rate setting decisions are subject to PUCT review.
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NMPRC | | Retail electric operations, rates services, construction of transmission or generation and other aspects of electric operations. |
FERC | | Wholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce. |
SPP RTO and SPP IM Wholesale Market | | SPS is a transmission-owning member of the SPP RTO and operates within the SPP RTO and SPP IM wholesale market. SPS is authorized to make wholesale electric sales at market-based prices. |
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Mechanism | | Additional Information |
DCRF | | Recovers distribution costs not included in rates in Texas. |
EECRF | | Recovers costs for energy efficiency programs in Texas. |
EE Rider | | Recovers costs for energy efficiency programs in New Mexico. |
FPPCAC | | Adjusts monthly to recover fuel and purchased power costs in New Mexico. |
PCRF | | Allows recovery of purchased power costs not included in Texas rates. |
RPS | | Recovers deferred costs for renewable energy programs in New Mexico. |
TCRF | | Recovers transmission infrastructure improvement costs and changes in wholesale transmission charges not included in Texas base rates. |
Fixed Fuel and Purchased Recovery Factor | | Provides for recovery of energy expenses. Regulations require refunding or surcharging over- or under- recovery amounts, including interest, when they exceed 4% of the utility’s annual fuel and purchased energy costs on a rolling 12-month basis, if this condition is expected to continue. |
Wholesale Fuel and Purchased Energy Cost Adjustment | | SPS recovers production, fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased energy cost adjustment clause accepted by the FERC. Wholesale customers also pay the jurisdictional allocation of production costs. |
Resource Plan
In December 2018, the NMPRC issued a final order accepting SPS’ IRP.
SPS is forecasting a surplus capacity of 382 MW in 2028, but a capacity deficit of approximately 2,896 MW in 2038. SPS’ optimal resource plan for the planning period incorporates the addition of wind, simple cycle combustion turbine generation, combined cycle energy and entering PPAs. Various factors may impact this IRP, which could potentially require updates to the action plan and will be the subject of future IRPs, including:
New and revised environmental regulations;
Impacts of variability due to participation in the SPP;
Customer expectations;
Technological advances;
Groundwater aquifer depletion at SPS’ Tolk Station;
Aging generation fleet;
Load growth and gas price variability;
Changes to tax credits and incentives; and
Changes to renewable portfolio standard acquisitions.
SPS is required to file an IRP in New Mexico every three years and will file its next IRP in July 2021.
Purchased Power Arrangements and Transmission Service Providers
SPS expects to use electric generating stations, power purchases, DSM and new generation options to meet its system capacity requirements.
Purchased Power — SPS purchases power from other utilities and IPPs. Long-term purchased power contracts typically require periodic capacity and energy charges. SPS also makes short-term purchases to meet system load and energy requirements to replace owned generation, meet operating reserve obligations or obtain energy at a lower cost.
Purchased Transmission Services — SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers.
Natural Gas
SPS does not provide retailhas eight natural gas service, but purchasesplants with approximately 2,200 MW of total 2020 net summer dependable capacity.
Natural gas supplies, transportation and transportsstorage services for power plants are procured to provide an adequate supply of fuel. Remaining requirements are procured through a liquid spot market. Generally, natural gas for its generation facilities and operates natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines. SPSsupply contracts have variable pricing that is subject to the jurisdiction of the FERC with respecttied to natural gas transactions in interstate commerceindices. Natural gas supply and the PHMSA and PUCTtransportation agreements include obligations for pipeline safety compliance.
Wholesale and Commodity Marketing Operations
SPS conducts various wholesale marketing operations, including the purchase and/or delivery of specified volumes or payments in lieu of delivery.
Natural Gas Cost
Delivered cost per MMBtu of natural gas consumed for owned electric generation and salepercentage of electric capacity,total fuel requirements:
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| | Natural Gas |
| | Cost | | Percent |
| 2020 | | $ | 1.43 | | | 60 | % |
| 2019 | | 1.14 | | | 55 | |
Capacity and Demand
Uninterrupted system peak demand and occurrence date:
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| System Peak Demand (in MW) |
| 2020 | | 2019 |
| 4,195 | | | July 14 | | 4,261 | | | Aug. 5 |
Transmission
Transmission lines deliver electricity over long distances from power sources to transmission substations closer to homes and businesses. A strong transmission system ensures continued reliable and affordable service, ability to meet state and regional energy ancillary servicespolicy goals, and energy related products.support for a diverse generation mix, including renewable energy. SPS uses physical and financial instruments to minimize commodity price and credit risk and to hedge sales and purchases.owns more than 40,000 conductor miles of transmission lines across its service territory.
During 2020, SPS completed the following transmission projects: |
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| Project | | Miles | | Size |
| TUCO-Yoakum Co. | | 107 | | | 345 KV |
| Eddy Co.-Kiowa | | 34 | | | 345 KV |
| Mustang-Seminole | | 20 | | | 115 KV |
| Loving South-Phantom | | 21 | | | 115 KV |
Upcoming transmission projects: | | | | | | | | | | | | | | | | | | | | |
| Project | | Miles | | Size | | Completion Date |
| Roadrunner-China Draw | | 41 | | | 345 KV | | 2021 |
Distribution
Distribution lines allow electricity to travel at lower voltages from substations directly to homes and businesses. SPS has a vast distribution network, owning and operating approximately 22,000 conductor miles of distribution lines across our service territory, both above ground and underground. To continue providing reliable, affordable electric service and enable more flexibility for customers, we are working to digitize the distribution grid, while at the same time keeping it secure.
See Item 2 - Properties for further information.
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| Public Utility Regulation |
See Item 7 for discussion of public utility regulation.
Seasonality
Demand for electric power is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, SPS’ operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.
Competition
SPS is subject to public policies that promote competition and development of energy markets. SPS’ industrial and large commercial customers have the ability to generate their own electricity. In addition, customers may have the option of substituting other fuels or relocating their facilities to a lower cost region.
Customers have the opportunity to supply their own power with distributed generation including solar generation and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them.
Several states have incentives for the development of rooftop solar, community solar gardens and other distributed energy resources. Distributed generating resources are potential competitors to SPS’ electric service business with these incentives and federal tax subsidies.
The FERC has continued to promote competitive wholesale markets through open access transmission and other means. SPS’ wholesale customers can purchase their output from generation resources of competing suppliers or non-contracted quantities and use the transmission systemssystem of Xcel Energy Inc.’s utility subsidiariesSPS on a comparable basis to serve their native load.
FERC Order No. 1000 established competition for construction and operation of certain new electric transmission facilities. State utilities commissions have also created resource planning programs that promote competition for electricity generation resources used to provide service to retail customers.
SPS has franchise agreements with cities subject to periodic renewal; however, a city could seek alternative means to access electric power, such as municipalization. No municipalization activities are occurring presently.
While facing these challenges, SPS believes its rates and services are competitive with alternatives currently available.
Environmental Regulation
Our facilities are regulated by federal and state environmental agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various companyCertain SPS activities require registrations, permits, licenses, inspections and approvals from these agencies. SPS has received necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems.
Our facilities have been designed and constructed to operate in compliance with applicable environmental standards and related monitoring and reporting requirements. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or what effect future laws or regulations may have.
WeSPS must comply with emission levels that may be required to incur capital expenditures inrequire the future for remediationpurchase of MGP and other sites if it is determined that prior compliance efforts are not sufficient.emission allowances.
There are significant present and present/future environmental regulations to encourage use of clean energy technologies and regulate emissions of GHGs. SPS has undertaken numerous initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals.
If future Future environmental regulations do not take into consideration investments already made or if additional initiatives or emission reductions are required,may result in substantial costs may be incurred.costs.
In July 2019, the EPA adopted the Affordable Clean Energy rule, which requiresrequired states to develop plans by 2022 for GHG reductions from coal-fired power plants. The state plans, due toIn a Jan. 19, 2021 decision, the U.S. Court of Appeals for the D.C. Circuit issued a decision vacating and remanding the Affordable Clean Energy rule. That decision, if not successfully appealed or reconsidered, would allow the EPA in July 2022, will evaluate and potentially require heat rate improvements at existingto proceed with alternate regulation of coal-fired plants.power plants, either reviving the Clean Power Plan or proposing additional regulation. It is not yet known how these state plans will affect SPS’ existing coal plants,too early to predict an outcome, but theynew rules could require substantial additional investment, even in plants slated for retirement. SPS believes, based on prior state commission practice,practices, the cost of these initiatives or replacement generation would be recoverable through rates.
In October 2020, the TCEQ approved an agreement that ensures SPS will convert the Harrington plant from coal to natural gas by Jan. 1, 2025. This conversion is necessary to attain Federal Clean Air Act standards for emissions of SO2.
SPS seeks to address climate change and potential climate change regulation through efforts to reduce its GHG emissions in a balanced, cost-effective manner.
As of Dec. 31, 2019,2020, SPS had 1,1581,141 full-time employees and no part-time employees, of which 779769 were covered under collective-bargaining agreements.
Xcel Energy, which includes SPS, is subject to a variety of risks, many of which are beyond our control. Risks that may adversely affect the business, financial condition, results of operations or cash flows are described below. These risks should be carefully considered together with the other information set forth in this report and future reports that Xcel Energy files with the SEC.
Oversight of Risk and Related Processes
TheSPS’ Board of Directors is responsible for the oversight of material risk and maintaining an effective risk monitoring process. Management and the Board of Directors have responsibility for overseeing the identification and mitigation of key risks.
At a threshold level, SPS maintains a robust compliance program through promoting a culture of compliance beginning with the tone at the top. The risk mitigation process includes adherence to our code of conduct and compliance policies, operation of formal risk management structures and overall business management. SPS further mitigates inherent risks through formal risk committees and corporate functions such as internal audit, and internal controls over financial reporting and legal.
Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Identification and risk analysis occurs formally through risk assessment conducted by senior management, the financial disclosure process, hazard risk procedures, internal audit and compliance with financial and operational controls.
Management also identifies and analyzes risk through the business planning process, development of goals and establishment of key performance indicators, including identification of barriers to implementing our strategy. The business planning process also identifies likelihood and mitigating factors to prevent the assumption of inappropriate risk to meet goals.
Management communicates regularly with the Board of Directors and its sole stockholder regarding risk. Senior management presents and communicates a periodic risk assessment to the Board of Directors, providing information on the risks that management believes are material, including financial impact, timing, likelihood and mitigating factors. The Board of Directors regularly reviews management’s key risk assessments, which includes areas of existing and future financial, operational and security risks.
Overall, the oversight, management and mitigation of risk is an integral and continuous part of the Board of Directors’ governance of SPS. Processes are in place to ensure appropriate risk oversight, as well as identification and consideration of new risks.
Risks Associated with Our Business
Operational Risks
Our electric transmission and distribution and gas operations involve numerous risks that may result in accidents and other operating risks and costs.
Our natural gas transmission activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses. Our natural gas transmission activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. We maintain insurance against some, but not all, of these risks and losses. The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations and cash flows.
Other uncertainties and risks inherent in operating and maintaining SPS’ facilities include, but are not limited to:
•Risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned.
•Failures in the availability, acquisition or transportation of fuel or other necessary supplies.
•The impact of unusual or adverse weather conditions and natural disasters, including, but not limited to, tornadoes, icing events, floods and droughts.
•Performance below expected or contracted levels of output or efficiency (e.g., performance guarantees).
•Availability of replacement equipment.
•Availability of adequate water resources and ability to satisfy water intake and discharge requirements.
•Inability to identify, manage properly or mitigate equipment defects.
•Use of new or unproven technology.
•Risks associated with dependence on a specific type of fuel or fuel source, such as commodity price risk, availability of adequate fuel supply and transportation and lack of available alternative fuel sources.
•Increased competition due to, among other factors, new facilities, excess supply, shifting demand and regulatory changes.
Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the Department of Transportation’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with the PHMSAthese regulations and systematically monitor and renew infrastructure over time, however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations.
Our natural gas and electric transmission and distribution operations and natural gas transmission operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services.
Our utility operations are subject to long-term planning and project risks.
Most electric utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of when they are brought in-service dates and typically subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. Our long-term resource plan is dependent on our ability to obtain required approvals, develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.
In addition, the long-term nature of both our planning and our asset lives are subject to risk. The electric utility sector is undergoing a period of significant change. For example,change (e.g, increases in energy efficiency, wider adoption of lower cost renewable generation, distributed generation and shifts away from coalfossil fuel generation to decrease carbon emissions and increasing use of natural gas in electric generation driven by lower natural gas prices. renewable generation).
Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, as well asand potentially stranded costs if SPS iswe are not able to fully recover costs and investments.
Changing customer expectations and technologies are requiring significant investments in advanced grid infrastructure, which increases exposure to technology obsolescence.
Evolving Additionally, evolving stakeholder preference for lower emissionemissions from generation sources and end-uses, like heating, may put pressure on our ability to recover capital investments in natural gas generation and delivery.
The magnitude and timing of resource additions and changes in customer demand may not coincide whilewith evolving customer preference for resource generation may change,resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. Additionally, multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets.
We are subject to longer-term availability of inputs such as coal, natural gas uranium and water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.
We are subject to commodity risks and other risks associated with energy markets and energy production.
In the event fuel costs increase, customer demand could decline and bad debt expense may rise, which may have a material impact on our results of operations. Despite existing fuel recovery mechanisms, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows.flows and liquidity.
A significant disruption in supply could cause us to seek alternative supply services at potentially higher costs and supply shortages may not be fully resolved, which could cause disruptions in our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments could negatively impact our cash flows and results of operations.
We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result, we are subject to market supply and commodity price risk.
Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability. The management of risks associated with hedging and trading is based, in part, on programs and procedures which utilize historical prices and trends.
Due to the inherent uncertainty involved in price movements and potential deviation from historical pricing, SPS is unable to fully assure that its risk management programs and procedures would be effective to protect against all significant adverse market deviations. In addition, SPS cannot fully assure that its controls will be effective against all potential risks, including, without limitation, employee misconduct. If such controls are not effective, SPS’ results of operations, financial condition or cash flows could be materially impacted.
Failure to attract and retain a qualified workforce could have an adverse effect on operations.
Certain specializedSpecialized knowledge is required of our technical employees for construction and operation of transmission, generation and distribution assets. Our business strategy is dependent on our ability to recruit, retain and motivate employees. CompetitionThere is competition and a tightening market for skilled employees is high in the areas of business operations.employees. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. We have seen a tightening of supply for engineers and skilled laborers in certain markets and are implementing plans to retain these employees. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.
Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.
We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance standards, progress payments, insurance requirements and security for performance. Poor vendor performance could impact ongoing operations, restoration operations, our reputation and could introduce financial risk or risks of fines.
We are a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.
All of the members of our Board of Directors, as well as many of our executive officers, are officers of Xcel Energy Inc. Our Board or Directors makes determinations with respect to a number of significant corporate events, including the payment of our dividends.
We have historically paid quarterly dividends to Xcel Energy Inc. In 2020, 2019 2018 and 20172018 we paid $332.7$313 million, $131.0$333 million and $108.8$131 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs. This could adversely affect our liquidity. The most restrictive dividend limitation for SPS is imposed by its state regulatory commissions. State regulatory commissions indirectly limit the amount of dividends that
SPS can pay Xcel Energy Inc., by requiring a minimum equity-to-total capitalization ratio.
See Note 5 to the financial statements for further information.
Financial Risks
Our profitability depends on our ability to recover costs from our customers and changes in regulation may impair our ability to recover costs from our customers.
We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.
The profitability of our operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on our capital investment. Our rates are generally regulated and based on an analysis of our costs incurred in a test year. We are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates we are allowed to charge may or may not match our costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.
There can also be no assurance that our regulatory commissions will judge all our costs to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair our ability to recover costs historically collected from customers, or we could exceed caps on capital costs (e.g., wind projects) required by commissions and result in less than full recovery.
Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.
In a continued low interest rate environment there has been increased downward pressure on allowed ROE. Conversely, higher than expected inflation or tariffs may increase costs of construction and operations. Also, rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers.
Adverse regulatory rulings or the imposition of additional regulations could have an adverse impact on our results of operations and materially affect our ability to meet our financial obligations, including debt payments.
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.
We cannot be assured that our current credit ratings will remain in effect, or that a rating will not be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, significantly lower returns on equity, changes to equity ratios and impacts of tax policy may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.
Any credit ratings downgrade could lead to higher borrowing costs and could impact our ability to access capital markets. Also, we may enter into contracts that require posting of collateral or settlement of applicable contracts if credit ratings fall below investment grade.
We are subject to capital market and interest rate risks.
Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Capital markets are global and impacted by issues and events throughout the world. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital market disruption and financial market distress could prevent us from issuing short-term commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results.
We are subject to credit risks.
Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and local economies in the geographic areas we serve, including local unemployment rates.
Credit risk also includes the risk that various counterparties that owe us money or product will become insolvent and may breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and incur losses.
We may at times have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, such as(e.g., SPP, PJM Interconnection, LLC, Midcontinent Independent System Operator, Inc. and Electric Reliability Council of Texas,Texas), in which any credit losses are socialized to all market participants.
We have additional indirect credit exposure to financial institutions in the form offrom letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract.
As we are a subsidiary of Xcel Energy Inc. we may be negatively affected by events impacting the credit or liquidity of Xcel Energy Inc. and its affiliates.
If either Standard & Poor’sS&P or Moody’s were to downgrade Xcel Energy Inc.’s debt securities below investment grade, it would increase Xcel Energy Inc.’s cost of capital and restrict its access to the capital markets. This could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.
As of Dec. 31, 2019,2020, Xcel Energy Inc. and its utility subsidiaries had approximately $17.4$19.6 billion of long-term debt and $1.3$1.0 billion of short-term debt and current maturities. Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.
Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees.
As of Dec. 31, 2019,2020, Xcel Energy had guarantees outstanding with a $2 million maximum stated amount of approximately $2.0 million and immaterial exposure. Xcel Energy also had additional guarantees of $60.4$60 million at Dec. 31, 20192020 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time. If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.
Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.
We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related toof these plans. Estimates and assumptions may change. In addition, the Pension Protection Act changedsets the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and related contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year due to high numbers of retirements or employees leaving would trigger settlement accounting and could require SPS to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future liabilitiesobligations and benefit costs.
Increasing costs associated with health care plans may adversely affect our results of operations.
Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs.
Federal tax law may significantly impact our business.
SPS collects through regulated rates estimated federal, state and local tax payments.payments through regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. ThereIf tax rates are increased, there could be timing delays before regulated rates provide for realizationrecovery of such tax changesincreases in revenues. In addition, certain IRS tax policies such as tax normalization may impact our ability to economically deliver certain types of resources relative to market prices.
Macroeconomic Risks
Economic conditions impact our business.
Our operations are affected by local, national and worldwide economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay their bills which could lead to additional bad debt expense.
Additionally, SPS faces competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies.
We operate in a capital intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates.
We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.
The global outbreak of COVID-19 is impacting countries, communities, supply chains and markets. A high degree of uncertainty continues to exist regarding the pandemic, the duration and magnitude of business restrictions, re-shut downs, if any, and the level and pace of economic recovery. While we are implementing contingency plans, there are no guarantees these plans will be sufficient to offset the impact of COVID-19.
Although the impact of the pandemic to the 2020 results was largely mitigated due to management’s actions, we cannot ultimately predict whether it will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact of the virus on the health of our employees, our supply chain or our ability to recover higher costs associated with managing through the pandemic. The impact of COVID-19 may exacerbate other risks discussed herein, which could have a material effect on us. The situation is evolving and additional impacts may arise.
Operations could be impacted by war, terrorism or other events.
Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows.
The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have already incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.
A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, our brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility.
We also face the risks of possible loss of business due to significant events such as severe storm,storms, severe temperature extremes, wildfires, widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a disruption of work force within our operating systems (or on a neighboring system).workforce disruption.
The recent coronavirus outbreak in China is an example of howIn addition, major catastrophic events throughout the world may disrupt our business. While we are a domestic company, the CompanyXcel Energy participates in a global supply chain, which includes materials and components that are sourced from China.globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to reliably serve our customers.
Disruption due to events such as those noted aboveA major disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material impact on our results of operations, financial condition or cash flows.
SPS participates in biennial grid security and emergency response exercises (GridEx). These efforts, led by the NERC, test and further develop the coordination, threat sharing and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid.
A cyber incident or security breach could have a material effect on our business.
We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors and other individuals.
Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error. Our industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States and individuals. Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability.
Our generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers’ operations, could also negatively impact our business.
Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. Cyber security incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.
We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability.
Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.
Our electric utility business is seasonal and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations, or cash flows.
Public Policy Risks
We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.
Legislative and regulatory responses related to climate change and new interpretations of existing lawsmay create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. SuchInternational agreements could additionally lead to future federal or state regulations.
In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. The Biden Administration will establish a new nationally determined contribution for the United States. The Paris Agreement could result in future additional GHG reductions in the United States. In addition, the Biden Administration has announced plans to implement new climate change programs, including potential regulation of GHG emissions targeting the utility industry.
The Biden Administration has also announced a one year suspension of new oil and natural gas drilling on federal lands to allow for a review of oil and gas leasing regulations. The form of these regulations is uncertain, but, depending on the requirements imposed in the short and long term, they could impose substantial costs on our system.oil and gas customers or result in substantial increases to the cost of fuel we use in our electricity and gas businesses.
Many states and localities continue to pursue their own climate policies. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation or retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies.
We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.
Although the United States has not adopted any international or federal GHG emission reduction targets, many states and localities may continue to pursue climate policies in the absence of federal mandates. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation or retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. While those actions likely would have put Xcel Energy in a good position to meet federal or international standards being discussed, the lack of federal action does not adversely impact these state-endorsed actions and plans.
If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.
Increased risks of regulatory penalties could negatively impact our business.
The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. The FERC can impose penalties of up to $1.3 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties. In the event of serious incidents, these agencies have become more active in pursuingmay pursue penalties. SomeIn addition, certain states additionally have the authority to impose substantial penalties. If a serious reliability, cyber or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows.
Environmental Risks
We are subject to environmental laws and regulations, with which compliance could be difficult and costly.
We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements.
Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Environmental regulations may also lead to shutdown of existing facilities. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate (i.e., clean-up) sites where our past activities, or the activities of other parties, caused environmental contamination.
Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.
We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or the O&M costs incurred to comply with the requirements.
In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.
We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.
Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events.
Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues.
Climate change may impact a region’sthe economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers, which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.
Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers.
To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Periods of extreme temperatures could impact our ability to meet demand. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations. Drought conditions also contribute to the increase in wildfire risk from our electric generation facilities. While we carry liability insurance, given an extreme event, if SPS was found to be liable for wildfire damages, amounts that potentially exceed our coverage could negatively impact our results of operations, financial condition or cash flows. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of unitspower plants and increase the price paidcost for energy. We may not recover all costs related to mitigating these physical and financial risks.
|
| |
| ITEM 1B — UNRESOLVED STAFF COMMENTS |
None.
Virtually all of the utility plant property of SPS is subject to the lien of its first mortgage bond indenture.
| | | | | | | | | | | | | | | | | | | | | | | |
| Station, Location and Unit | | Fuel | | Installed | | MW (a) | |
| Steam: | | | | | | | |
| Cunningham-Hobbs, NM, 2 Units | | Natural Gas | | 1957 - 1965 | | 225 | | |
Harrington-Amarillo, TX, 3 Units (b) | | Coal | | 1976 - 1980 | | 1,018 | | |
| Jones-Lubbock, TX, 2 Units | | Natural Gas | | 1971 - 1974 | | 486 | | |
| Maddox-Hobbs, NM, 1 Unit | | Natural Gas | | 1967 | | 112 | | |
| Nichols-Amarillo, TX, 3 Units | | Natural Gas | | 1960 - 1968 | | 457 | | |
| Plant X-Earth, TX, 4 Units | | Natural Gas | | 1952 - 1964 | | 298 | | |
Tolk-Muleshoe, TX, 2 Units (d) | | Coal | | 1982 - 1985 | | 1,067 | | |
| Combustion Turbine: | | | | | | | |
| Cunningham-Hobbs, NM, 2 Units | | Natural Gas | | 1997 | | 207 | | |
| Jones-Lubbock, TX, 2 Units | | Natural Gas | | 2011 - 2013 | | 334 | | |
| Maddox-Hobbs, NM, 1 Unit | | Natural Gas | | 1963 - 1976 | | 61 | | |
| Wind: | | | | | | | |
| Hale-Plainview, TX, 239 Units | | Wind | | 2019 | | 460 | | (c) |
| Sagamore-Dora, NM, 240 Units | | Wind | | 2020 | | 507 | | (c) |
| | | | Total | | 5,232 | | |
(a) Summer 2020 net dependable capacity.
(b) Harrington is expected to be converted to natural gas by the end of 2024.
(c) Values disclosed are the generation levels at the point-of-interconnection for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero)
(d) Tolk Unit 1 and 2 are expected to be retired in 2032.
|
| | | | | | | | |
Station, Location and Unit | | Fuel | | Installed | | MW (a) | |
| Steam: | | | | | | | |
| Cunningham-Hobbs, NM, 2 Units | | Natural Gas | | 1957 - 1965 | | 189 |
| |
| Harrington-Amarillo, TX, 3 Units | | Coal | | 1976 - 1980 | | 1,018 |
| |
| Jones-Lubbock, TX, 2 Units | | Natural Gas | | 1971 - 1974 | | 486 |
| |
| Maddox-Hobbs, NM, 1 Unit | | Natural Gas | | 1967 | | 112 |
| |
| Nichols-Amarillo, TX, 3 Units | | Natural Gas | | 1960 - 1968 | | 457 |
| |
| Plant X-Earth, TX, 4 Units | | Natural Gas | | 1952 - 1964 | | 411 |
| |
| Tolk-Muleshoe, TX, 2 Units | | Coal | | 1982 - 1985 | | 1,067 |
| |
| Combustion Turbine: | | | | | | | |
| Cunningham-Hobbs, NM, 2 Units | | Natural Gas | | 1997 | | 209 |
| |
| Jones-Lubbock, TX, 2 Units | | Natural Gas | | 2011 - 2013 | | 334 |
| |
| Maddox-Hobbs, NM, 1 Unit | | Natural Gas | | 1963 - 1976 | | 61 |
| |
| Wind: | | | | | | | |
Hale-Plainview, TX, 239 Units (b) | | Wind | | 2019 | | 460 |
| |
| | | | | Total | | 4,804 |
| |
| |
(a)
| Summer 2019 net dependable capacity. |
| |
(b)
| Values disclosed are the maximum generation levels for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero). |
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2019:
|
| | | | |
| Conductor Miles | |
345 KVTransmission | 9,566 |
|
230345 KV | 9,78411,019 |
|
115230 KV | 14,6629,795 |
|
| 115 KV | 14,830 | |
| Less than 115 KV | 26,2164,375 |
|
| Total Transmission | 40,019 | |
| |
| Distribution | |
| Less than 115 KV | 21,984 | |
| |
| Total | 62,003 | |
SPS had 452457 electric utility transmission and distribution substations at Dec. 31, 2019.2020.
Natural gas utility mains at Dec. 31, 2019:
|
| | | | |
| Miles | |
| Transmission | 20 |
|
Distribution | — |
|
|
| |
ITEM 3 — LEGAL PROCEEDINGS |
SPS 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. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on SPS’ financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.
See Note 10 to the financial statements, Item 1 and Item 7 for further information.
|
| |
ITEM 4 — MINE SAFTEY DISCLOSURES |
None.
PART II
|
| |
ITEM 5 — MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASEPURCHASES OF EQUITY SECURITIES |
SPS is a wholly owned subsidiary of Xcel Energy Inc. and there is no market for its common equity securities.
See Note 5 to the financial statements for further information.
The dividends declared during 20192020 and 20182019 were as follows:
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2020 | | 2019 |
| First quarter | | $ | 76 | | | $ | 58 | |
| Second quarter | | 55 | | | 84 | |
| Third quarter | | 136 | | | 114 | |
| Fourth quarter | | 54 | | | 78 | |
|
| | | | | | | | |
| (Millions of Dollars) | | 2019 | | 2018 |
| First quarter | | $ | 57.5 |
| | $ | 33.3 |
|
| Second quarter | | 83.4 |
| | 30.7 |
|
| Third quarter | | 114.6 |
| | 40.0 |
|
| Fourth quarter | | 78.3 |
| | 45.4 |
|
|
| |
ITEM 6 —SELECTED FINANCIAL DATA |
This is omittedOmitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
|
| |
ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Discussion of financial condition and liquidity for SPS is omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis and the results of operations for the current year as set forth in general instructions I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
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 and ongoing earnings. 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.
SPS’ 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 Margins
Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues. Management believes electric 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)
Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items.
We use these non-GAAP financial measures to evaluate and provide details of SPS’ core earnings and underlying performance.
We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of SPS. For the years ended Dec. 31, 20192020 and Dec. 31, 2018,2019, there were no adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings.
20192020 Comparison with 20182019
SPS’ net income was approximately $263.1$295 million for 2019,2020, compared with net income of $213.3$263 million for 2018.2019. The increase was primarily due to higher electric margins attributablemargin (wholesale transmission revenue and regulatory outcomes offset lower sales due to purchased capacity costs, regulatory rate outcomes, demand revenue, higher AFUDC related to the Hale wind farmCOVID-19) and lower income taxes,O&M expenses, partially offset by increased depreciation, interest expense and depreciation expense.taxes (other than income taxes).
Electric Margin
Electric fuel and purchased power expenses tendare impacted by fluctuations in the price of natural gas and coal. However, these fluctuations have minimal impact on margin due to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Changes in fuel or purchased power costs can impact earnings as the fuel and purchased power cost recovery mechanisms of the Texas and New Mexico jurisdictions may not allowmechanisms. In addition, electric customers receive a credit for complete recovery of all expenses. Electric revenuesPTCs generated, which reduce electric revenue and margin for 2018 are before and after the impact of the TCJA:
(offset by lower tax expense). |
| | | | | | | | |
| (Millions of Dollars) | | 2019 | | 2018 |
| Electric revenues before TCJA impact | | $ | 1,825.8 |
| | $ | 1,988.1 |
|
| Electric fuel and purchased power before TCJA impact | | (875.4 | ) | | (1,050.1 | ) |
| Electric margin before TCJA impact | | $ | 950.4 |
| | $ | 938.0 |
|
| TCJA impact (offset as a reduction in income tax) | | — |
| | (48.3 | ) |
| Electric margin | | $ | 950.4 |
| | $ | 889.7 |
|
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2020 | | 2019 |
| Electric revenues | | $ | 1,870 | | | $ | 1,826 | |
| Electric fuel and purchased power | | (835) | | | (875) | |
| Electric margin | | $ | 1,035 | | | $ | 951 | |
The following tables summarize the components of the changes in electric margin for the year ended Dec. 31, 2019:2020:
| | | | | | | | |
| (Millions of Dollars) | | 2020 vs. 2019 |
Regulatory rate outcomes (Texas and New Mexico) (a) | | $ | 107 | |
| Wholesale transmission revenue (net) | | 26 | |
| Purchased capacity costs | | 8 | |
| Estimated impact of weather | | 7 | |
| PTCs flowed back to customers (offset by lower ETR) | | (42) | |
| New Mexico tax reform related regulatory settlement (2019) | | (10) | |
| Firm wholesale generation | | (9) | |
| Sales and demand | | (8) | |
| Other (net) | | 5 | |
| Total increase in electric margin | | $ | 84 | |
|
| | | | |
| (Millions of Dollars) | | 2019 vs. 2018 |
| Purchase capacity costs | | $ | 40.7 |
|
| Regulatory rate outcomes | | 24.7 |
|
| Demand revenue | | 24.7 |
|
| Wholesale transmission revenue | | 13.7 |
|
| Sales growth | | 5.9 |
|
| Non-fuel riders | | 4.3 |
|
| Firm wholesale | | (26.2 | ) |
| PTC sharing | | (16.0 | ) |
| Estimated weather impact | | (5.2 | ) |
| Other (net) | | (5.9 | ) |
| Total increase in electric margin | | $ | 60.7 |
|
Non-Fuel Operating Expense and Other Items
O&M Expenses — O&M expense decreased $10 million, or 3.5%, for2020 compared with the prior year. The decrease was due to management actions to reduce costs to offset the impact of lower sales from COVID-19, including allocation of workforce, material and supply management and timing of maintenance activities, as well as plant outages in 2019. The decrease was partially offset by an increase in wind related O&M expenses from our renewable expansion and recognition of previously deferred amounts related to the 2019 Texas Electric Rate Case.
Depreciation and Amortization — Depreciation and amortization expense increased $20.3$65 million, or 9.7%28.3%, for 20192020 compared with the prior year. The increase was primarily due to the Hale wind farm being placed into service and increased capital investments.
AFUDC, Equity and Debt— AFUDC increaseddriven by $11.1 million, or 39.6% for 2019 compared with the prior year. The increase was primarily due to the Hale and Sagamore wind farms.farms being placed into service in June 2019 and December 2020, respectively, in addition to system expansion. The increase is also due to new FERC transmission rates implemented in March 2020 and implementation of new depreciation rates in New Mexico and Texas as part of regulatory outcomes in 2020.
Interest Charges — Interest charges increased 14.8$20 million, or 17.5%20.2% for 20192020 compared with the prior year. The increase was primarily due to higher debt levels to fund capital investments.
Income Taxes — Income tax expense decreased $13.3$36 million for 2019 compared with the prior year.2020. The decrease was primarily driven by an increase in wind PTCs; partially offset by higher pretax income.PTCs and an increase in plant-related regulatory differences. Wind PTCs are largely credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income. The ETR was 8.9%(3.5)% for 2020 compared with 9.0% for 2019, compared with 15.4% for 2018. The lower ETR in 2019 was primarilylargely due to the itemsadjustments referenced above.
2018 Comparison
| | |
| Public Utility Regulation |
The FERC and state and local regulatory commissions regulate SPS. SPS is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with 2017respect to the rates of electric distribution companies in New Mexico, and Texas.
A discussion ofRates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in rates for utility services through filings with governing commissions. Changes in operating costs can affect SPS’ 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 SPS’ results of operationsoperations.
See Rate Matters within Note 10 to the financial statements for further information.
Summary of Regulatory Agencies / RTO and liquidityAreas of Jurisdiction | | | | | | | | |
| Regulatory Body / RTO | | Additional Information |
| PUCT | | Retail electric operations, rates, services, construction of transmission or generation and other aspects of SPS’ electric operations. The municipalities in which SPS operates in Texas have original jurisdiction over rates in those communities. The municipalities’ rate setting decisions are subject to PUCT review. |
| NMPRC | | Retail electric operations, retail rates and services and the construction of transmission or generation. |
| FERC | | Wholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce. |
| SPP RTO and SPP IM Wholesale Market | | SPS is a transmission owning member of the SPP RTO and operates within the SPP RTO and SPP IM wholesale market. SPS is authorized to make wholesale electric sales at market-based prices. |
Recovery Mechanisms | | | | | | | | |
| Mechanism | | Additional Information |
| DCRF | | Recovers distribution costs not included in rates in Texas. |
| EECRF | | Recovers costs for energy efficiency programs in Texas. |
| Energy Efficiency Rider | | Recovers costs for energy efficiency programs in New Mexico. |
| FPPCAC | | Adjusts monthly to recover actual fuel and purchased power costs in New Mexico. |
| PCRF | | Allows recovery of purchased power costs not included in Texas rates. |
| RPS | | Recovers deferred costs for renewable energy programs in New Mexico. |
| TCRF | | Recovers certain transmission infrastructure improvement costs and changes in wholesale transmission charges not included in Texas base rates. |
| Fixed Fuel and Purchased Recovery Factor | | Provides for the over- or under-recovery of energy expenses in Texas. Regulations require refunding or surcharging over- or under- recovery amounts, including interest, when they exceed 4% of the utility’s annual fuel and purchased energy costs on a rolling 12-month basis, if this condition is expected to continue. |
| Wholesale Fuel and Purchased Energy Cost Adjustment | | SPS recovers fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased energy cost adjustment clause accepted by the FERC. Wholesale customers also pay the jurisdictional allocation of production costs. |
Pending and
capital resources from the year ended Dec. 31, 2017 to Dec. 31, 2018 can be found in Part II, “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year 2018, which was filed with the SEC on Feb. 22, 2019. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.
Regulation
FERC and State Regulation — The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, asset transactions and mergers, accounting practices and certain other activities of SPS, including enforcement of NERC mandatory electric reliability standards. State and local agencies have jurisdiction over many of SPS’ activities, including regulation of retail rates and environmental matters.
Xcel Energy, which includes SPS, attempts to mitigate the risk of regulatory penalties through formal training on prohibited practices and a compliance function that reviews interaction with the markets under FERC and Commodity Futures Trading Commission jurisdictions.
PendingRecently Concluded Regulatory Proceedings
|
| | | | | | | | | | | | | | | | | | | |
MechanismProceeding | | Utility Service | | Amount Requested (in millions) | | Filing Date | | Approval | | Additional Information |
SPS (NMPRC)2019 New Mexico Electric Rate Case | | $31 | | July 2019 | | Received |
| 2019 Texas Electric Rate Case | | Electric88 | | $51August 2019 | | July 2019Received |
| 2021 New Mexico Electric Rate Case | | Pending88 | | 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 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.
On Jan. 13, 2020, SPS and various parties filed an uncontested comprehensive stipulation. The stipulation includes a base rate revenue increase of $31 million, based on 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 Signatories will not oppose the full application of depreciation rates associated with the 2032 retirement date in SPS’ next base rate case. SPS anticipates final rates will go into effect in the second or third quarter of 2020.
January 2021 | | Pending |
| 2021 Texas Electric Rate Case | | 143 | | February 2021 | | Pending |
Additional Information:
2019 New Mexico Electric Rate Case — In May 2020, the NMPRC approved a settlement between SPS and intervening parties, which reflects the following terms: a base rate increase of $31 million, an ROE of 9.45% and an equity ratio of 54.77%. New rates and tariffs were effective in May 2020.
2019 Texas Electric Rate Case
— In August 2019,2020, the PUCT approved a settlement between SPS and intervening parties, which reflects the following terms: a rate increase of $88 million; ROE of 9.45% and equity ratio of 54.62% for AFUDC purposes. In December 2020, SPS filed to surcharge the final under-recovered amount, estimated to be approximately $72 million, offset by the recognition of previously deferred costs.
2021 New Mexico Electric Rate Case — On Jan. 4, 2021, SPS filed an electric rate case with the PUCTNMPRC seeking an increase in retail electric base rates of approximately $141$88 million. SPS' net rate increase to New Mexico customers is expected to be approximately $48 million, or 10%, as a result of offsetting fuel cost reductions and PTCs attributable to wind energy provided by the Sagamore wind project. PTCs are being credited to customers through the fuel clause.
The filing requests anrequest is based on a historic test year ended Sept. 30, 2020, including expected capital additions through Feb. 28, 2021, a ROE of 10.35%, a 54.65%an equity ratio aof 54.72% and retail rate base of approximately $2.6$1.9 billion (total company rate base of approximately $6.0 billion).
Additionally, the request includes the effect of approximately 400 MW of reduced peak load in 2021 from a wholesale transmission customer and is built onchanges to depreciation rates to reflect a 12 month period that ended June 30, 2019. In September 2019, SPS filed an updatereduction to the electric rate case and revised its requested increaseservice lives of SPS’ Tolk power plant (from 2037 to $136.5 million.
On Feb. 10, 2020, the Alliance of Xcel Municipalities (AXM), Texas Industrial Energy Consumers (TIEC), Office of Public Utility Counsel (OPUC)2032) and the Department of Energy (DOE), filed testimony along with several other parties.
On Feb. 18, 2020,coal handling assets at the PUCT Staff filed testimony that included certain adjustments and various ring-fencing measures.
Proposed modifications to SPS’ request:
Harrington facility (to 2024).
|
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Staff | | AXM | | OPUC | | TIEC | | DOE |
| SPS Direct Testimony | | $ | 136.5 |
| | $ | 136.5 |
| | $ | 136.5 |
| | $ | 136.5 |
| | $ | 136.5 |
|
| | | | | | | | | | | |
| Recommended base rate adjustments: | | | | | | | | |
| ROE | | (22.1 | ) | | (24.2 | ) | | (15.2 | ) | | (20.5 | ) | | (23.8 | ) |
| Capital structure | | (6.9 | ) | | (10.4 | ) | | — |
| | (6.9 | ) | | (3.1 | ) |
| Tolk/Harrington O&M disallowance | | — |
| | (6.6 | ) | | — |
| | — |
| | — |
|
Distribution and Transmission Capital Disallowances (a) | | (6.5 | ) | | — |
| | — |
| | — |
| | — |
|
| Depreciation expense | | (7.5 | ) | | (14.5 | ) | | (8.3 | ) | | (20.4 | ) | | — |
|
| Excess ADIT unprotected plant | | — |
| | — |
| | (6.9 | ) | | — |
| | — |
|
| Income Tax Expense Differences | | (11.6 | ) | | — |
| | — |
| | — |
| | — |
|
| Other, net | | (6.8 | ) | | (6.1 | ) | | (0.4 | ) | | (0.6 | ) | | — |
|
| Total Adjustments | | (61.4 | ) | | (61.8 | ) | | (30.8 | ) | | (48.4 | ) | | (26.9 | ) |
| Total proposed revenue change | | $ | 75.1 |
| | $ | 74.7 |
| | $ | 105.7 |
| | $ | 88.1 |
| | $ | 109.6 |
|
|
| | | | | | | | | | | | | | | |
| Recommended Position | | Staff | | AXM | | OPUC (b) | | TIEC | | DOE |
| ROE | | 9.1 | % | | 9.0 | % | | — | % | | 9.2 | % | | 9.0 | % |
| Equity Ratio | | 51.00 | % | | 50.00 | % | | — | % | | 51.00 | % | | 53.00 | % |
| |
(a)
The NMPRC suspended new rates for nine months beyond the 30-day notice period, consistent with historic practice. | Staff recommends exclusion of approximately $134 million in transmission, distribution, and general plant in service in this rate case resulting in an approximate $7 million decrease to the revenue requirement. |
| |
(b)
| OPUC did not provide a recommendation for an ROE or equity ratio. For illustrative purposes an ROE of 9.5% was used. |
The next steps in the procedural schedule are expected to be as follows:
•Staff and intervenor testimony — May 17, 2021.
•Rebuttal testimony — March 11, 2020; andJune 9, 2021.
•Deadline to file stipulation — June 23, 2021.
•Public hearing beginsor hearing on stipulation — March 30, 2020.July 26 - Aug. 6, 2021.
•End of nine month suspension — Nov. 3, 2021.
A PUCTNMPRC decision and implementation of final rates is anticipated in the thirdfourth quarter of 2021.
2021 Texas Rate Case— On Feb. 8, 2021, SPSfiled an electric rate case with the PUCT and its 81 municipalities with original rate jurisdiction seeking an increase in base rates of approximately $143 million. SPS' net rate increase to Texas customers is expected to be approximately $74 million, or 9.2%, as a result of offsetting $69 million in fuel cost reductions and PTCs from the Sagamore wind project.
The request is primarily driven by additional capital investment in new and upgraded electric facilities and equipment since SPS’ previous rate case in 2019, including the 522 MW Sagamore wind project.
The request is based on an ROE of 10.35%, an equity ratio of 54.60% (based on actual capital structure), a Texas retail rate base of approximately $3.3 billion and a historic test year based on the 12-month period ended Dec. 31, 2020 (with the final three months based on estimates). In March 2021, SPS will file to update estimates to actuals through Dec. 31, 2020.
Additionally, the request includes the effect of approximately 400 MW from a wholesale transmission customer and changes to depreciation rates to reflect a reduction to the service lives of SPS’ Tolk power plant (from 2037 to 2032) and the coal handling assets of the Harrington facility (to 2024).
Summary of SPS’ request:
| | | | | | | | |
| Rate Request (Millions of Dollars) | | |
| Sagamore wind project | | $ | 67 | |
| Other capital investments | | 25 | |
| Cost of capital | | 20 | |
| Property taxes | | 8 | |
| Reduced sales, partially offset by changes in O&M | | 8 | |
| Allocator changes | | 4 | |
| Depreciation rate change | | 3 | |
| Other, net | | 8 | |
| Total rate request | | $ | 143 | |
| Fuel cost reductions and PTCs — Sagamore wind project | | (69) | |
| Net rate increase | | $ | 74 | |
SPS is requesting the PUCT set current rates as temporary on March 15, 2021. Once final rates are approved, a surcharge will be requested from March 15, 2021 through the effective date of new base rates. A PUCT decision is expected in the first quarter of 2022.
Texas State ROFR
Litigation — In May 2019, the Governor signed a ROFR bill into law, Senate Bill 1938, which grants incumbent utilities a ROFR to build transmission infrastructure when it 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 to be unconstitutional. The Texas Attorney General has made a motion to dismissIn February 2020, the federal court complaint. Acomplaint was dismissed by the district court. In March 2020, the district court ruling on the dismissal motion is expected in the first quarter of 2020.
See Rate Matters within Note 10was appealed to the financial statements for further information.
Fifth Circuit. A decision is pending.
New Mexico FPPCAC Continuation — In December 2020, the Hearing Examiner recommended the NMPRC approve SPS’ request for the continued use of the FPPCAC and the reconciliation of its fuel costs for the reporting period (September 2015 through June 2019). Additionally, the Hearing Examiner recommended the NMPRC deny the proposed 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 and purchased power costs. A decision is pending.
Resource Plan — SPS is required to file an IRP in New Mexico every three years and will file its next IRP in July 2021.
Purchased Power Arrangements and Transmission Service Providers
SPS expects to use electric generating stations, power purchases, DSM and new generation options to meet its system capacity requirements.
Purchased Power — SPS purchases power from other utilities and IPPs. Long-term purchased power contracts typically require periodic capacity and energy charges. SPS also makes short-term purchases to meet system load and energy requirements to replace owned generation, meet operating reserve obligations or obtain energy at a lower cost.
Purchased Transmission Services — SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers.
Natural Gas
SPS does not provide retail natural gas service, but purchases and transports natural gas for its generation facilities and operates natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines. SPS is subject to the jurisdiction of the FERC with respect to natural gas transactions in interstate commerce and the PHMSA and PUCT for pipeline safety compliance.
Wholesale and Commodity Marketing Operations
SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. SPS uses physical and financial instruments to minimize commodity price and credit risk and to hedge sales and purchases.
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ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Derivatives, Risk Management and Market Risk
SPS is 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 financial statements for further information.
SPS 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, 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 SPS expects that the counterparties will perform under the contracts underlying its derivatives, the contracts expose SPS to somecertain credit and non-performance risk.
Distress in the financial markets may impact counterparty risk, the fair value of the securities in the pension fund, and SPS’ ability to earn a return on short-term investments.
Commodity Price Risk — SPS is exposed to commodity price risk in its electric 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. Commodity price risk is also managed through the use of financial derivative instruments.
SPS’ risk management policy allows it to manage commodity price risk per commission approved hedge plans.
Wholesale and Commodity Trading Risk — SPS conducts wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments, including derivatives. SPS’ risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee.
Interest Rate Risk — SPS is subject to interest rate risk. SPS’ 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.
A 100-basis-point change in the benchmark rate on SPS’ variable rate debt would have a $3 million and no impact on annual pretax interest expense annually in 2020 and 2019, and $0.4 million in 2018, respectively.
See Note 8 to the financial statements for further information.
Credit Risk — SPS is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. SPS maintains credit policies intended to minimize overall credit risk and actively monitorsmonitor these policies to reflect changes and scope of operations.
At Dec. 31, 2020, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $1 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $1 million. At Dec. 31, 2019, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $1.2$1 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $1.2$1 million. At Dec. 31, 2018, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $1.5 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $1.5 million.
SPS conducts credit reviews for all counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination 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 SPS’ credit risk.
Fair Value Measurements
SPS uses derivative contracts such as futures, forwards, interest rate swaps, options and FTRs 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. SPS’ investments held in rabbi trusts, pension and other postretirement funds are also subject to fair value accounting.
Commodity Derivatives — SPS continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions. Given the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, 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 recorded 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. The impact of discounting commodity derivative liabilities for credit risk was immaterial at Dec. 31, 2019.2020.
See Note 8 to the financial statements for further information. Natural Gas Fuel and Electricity Purchases
In February 2021, the United States experienced winter storm Uri and extreme cold temperatures in the central United States. This severe weather event increased the demand for natural gas used in our electric business. Certain operational assets were impacted by extreme cold temperatures and the cold further impacted the availability of renewable generation across the region (which typically acts as a hedge against commodity prices) contributing to extremely high market prices for natural gas and electricity. As a result, electric and natural gas fuel costs increased approximately $200 million. These amounts are preliminary estimates through Feb. 16, 2021 and are subject to final settlement.
SPS has fuel recovery mechanisms in all of its states to recover the increased cost of natural gas and electricity. However, given the impact of these higher costs to our customers during a pandemic, we expect our regulators to undertake a heightened review and we intend to work with our commissions to recover these costs over time to help mitigate the impacts on customer bills. SPS is taking action to increase planned debt issuances to ensure adequate liquidity for the timing difference between fuel payments and revenue collection from customers and to address any potential need to post collateral.
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| ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
See 15-1 for an index of financial statements included herein.
See Note 1312 to the financial statements for further information.
Management Report on Internal ControlsControl Over Financial Reporting
The management of SPS is responsible for establishing and maintaining adequate internal control over financial reporting. SPS’ internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s and SPS’ management and board of directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
SPS management assessed the effectiveness of SPS’ internal control over financial reporting as of Dec. 31, 2019.2020. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2019,2020, SPS’ internal control over financial reporting is effective at the reasonable assurance level based on those criteria.
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| /s/ BEN FOWKE | | /s/ ROBERT C. FRENZELBRIAN J. VAN ABEL |
| Ben Fowke | | Robert C. FrenzelBrian J. Van Abel |
| Chairman, Chief Executive Officer and Director | | Executive Vice President, Chief Financial Officer and Director |
Feb. 21, 202017, 2021 | | Feb. 21, 202017, 2021 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and Board of Directors of Southwestern Public Service Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Southwestern Public Service Company (the "Company") as of December 31, 20192020 and 2018,2019, the related statements of income, comprehensive income, cash flows and common stockholder's equity, for each of the three years in the period ended December 31, 2019,2020, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20192020 and 2018,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2020, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Assets and Liabilities - Impact of Rate Regulation on the Financial Statements — Refer to Notes 4 and 10 to the consolidated financial statements.
Critical Audit Matter Description
The Company is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric transmission and distribution companies in New Mexico and Texas. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission for its wholesale electric operations, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with North American Electric Reliability Corporation standards, asset transactions and mergers and natural gas transactions in interstate commerce, (collectively with state utility regulatory agencies, the “Commissions”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation affects multiple financial statement line items and disclosures, including property, plant and equipment, regulatory assets and liabilities, operating revenues and expenses, and income taxes.
The Company is subject to regulatory rate setting processes. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in assets required to deliver services to customers. Accounting for the Company’s regulated operations provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. The Commissions’ regulation of rates is premised on the full recovery of incurred costs and a reasonable rate of return on invested capital. Decisions by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. In the rate setting process, the Company’s rates result in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant, and 3) a refund due to customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the recognition of regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions for the Company, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We also evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. If the full recovery of project costs is being challenged by intervenors, we evaluated management’s assessment of the probability of a disallowance. We evaluated the external information and compared to the Company’s recorded regulatory assets and liabilities for completeness.
•We obtained management’s analysis and correspondence from counsel, as appropriate, regarding regulatory assets or liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
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| /s/ DELOITTE & TOUCHE LLP |
| Minneapolis, Minnesota |
February 21, 202017, 2021 |
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| We have served as the Company’s auditor since 2002. |
SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF INCOME
(amounts in millions)
| | | | | Year Ended Dec. 31 | | | | | | | | | | | | | | | | | |
| | | 2019 | | 2018 | | 2017 | | Year Ended Dec. 31 |
| | | | | | | | | 2020 | | 2019 | | 2018 |
| Operating revenues | | $ | 1,825.8 |
| | $ | 1,933.2 |
| | $ | 1,918.0 |
| Operating revenues | | $ | 1,870 | | | $ | 1,826 | | | $ | 1,933 | |
| | | | | | | | |
| Operating expenses | | | | | | | Operating expenses | |
| Electric fuel and purchased power | | 875.4 |
| | 1,043.5 |
| | 1,055.3 |
| Electric fuel and purchased power | | 835 | | | 875 | | | 1,043 | |
| Operating and maintenance expenses | | 285.3 |
| | 282.7 |
| | 285.4 |
| Operating and maintenance expenses | | 275 | | | 285 | | | 283 | |
| Demand side management program expenses | | 16.6 |
| | 17.7 |
| | 15.5 |
| |
| Demand side management expenses | | Demand side management expenses | | 16 | | | 17 | | | 18 | |
| Depreciation and amortization | | 229.9 |
| | 209.6 |
| | 193.9 |
| Depreciation and amortization | | 295 | | | 230 | | | 210 | |
| Taxes (other than income taxes) | | 71.9 |
| | 68.0 |
| | 67.0 |
| Taxes (other than income taxes) | | 90 | | | 72 | | | 68 | |
| Total operating expenses | | 1,479.1 |
| | 1,621.5 |
| | 1,617.1 |
| Total operating expenses | | 1,511 | | | 1,479 | | | 1,622 | |
| | | | | | | | | | | | | |
| Operating income | | 346.7 |
| | 311.7 |
| | 300.9 |
| Operating income | | 359 | | | 347 | | | 311 | |
| | | | | | | | |
| Other income (expense), net | | 2.2 |
| | (3.0 | ) | | (1.8 | ) | |
| Other (expense) income, net | | Other (expense) income, net | | (2) | | | 2 | | | (3) | |
| Allowance for funds used during construction — equity | | 26.8 |
| | 19.1 |
| | 9.3 |
| Allowance for funds used during construction — equity | | 33 | | 27 | | 19 |
| | | | | | | | |
| Interest charges and financing costs | | | | | | | Interest charges and financing costs | |
Interest charges — includes other financing costs of $3.4, $2.9 and $2.5, respectively | | 99.3 |
| | 84.5 |
| | 86.2 |
| |
| Interest charges — includes other financing costs of $4, $3 and $3, respectively | | Interest charges — includes other financing costs of $4, $3 and $3, respectively | | 119 | | | 99 | | | 84 | |
| Allowance for funds used during construction — debt | | (12.3 | ) | | (8.9 | ) | | (5.4 | ) | Allowance for funds used during construction — debt | | (14) | | | (12) | | | (9) | |
| Total interest charges and financing costs | | 87.0 |
| | 75.6 |
| | 80.8 |
| Total interest charges and financing costs | | 105 | | 87 | | 75 |
| | | | | | | | |
| Income before income taxes | | 288.7 |
| | 252.2 |
| | 227.6 |
| Income before income taxes | | 285 | | | 289 | | | 252 | |
| Income taxes | | 25.6 |
| | 38.9 |
| | 68.4 |
| |
| Income tax (benefit) expense | | Income tax (benefit) expense | | (10) | | | 26 | | | 39 | |
| Net income | | $ | 263.1 |
| | $ | 213.3 |
| | $ | 159.2 |
| Net income | | $ | 295 | | | $ | 263 | | | $ | 213 | |
See Notes to Financial Statements
SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF COMPREHENSIVE INCOME
(amounts in millions)
|
| | | | | | | | | | | |
| | Year Ended Dec. 31 |
| | 2019 | | 2018 | | 2017 |
| Net income | $ | 263.1 |
| | $ | 213.3 |
| | $ | 159.2 |
|
| | | | | | |
| Other comprehensive income | | | | | |
| | | | | | |
| Defined pension and other postretirement benefits: | | | | | |
| Net pension and retiree medical loss arising during the period, net of tax of $(0.1), $0 and $0, respectively | (0.2 | ) | | — |
| | — |
|
| Reclassification of loss to net income, net of tax of $0 | 0.2 |
| | — |
| | 0.1 |
|
| Derivative instruments: | | | | | |
| Reclassification of loss to net income, net of tax of $0 | — |
| | 0.1 |
| | — |
|
| | | | | | |
| Other comprehensive income | — |
| | 0.1 |
| | 0.1 |
|
| Comprehensive income | $ | 263.1 |
| | $ | 213.4 |
| | $ | 159.3 |
|
See Notes to Financial Statements
SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF CASH FLOWS
| |
| Year Ended Dec. 31 | | Year Ended Dec. 31 |
| | 2019 | | 2018 | | 2017 | | 2020 | | 2019 | | 2018 |
| Operating activities | | | | | | Operating activities | | | | | |
| Net income | $ | 263.1 |
| | $ | 213.3 |
| | $ | 159.2 |
| Net income | $ | 295 | | | $ | 263 | | | $ | 213 | |
| Adjustments to reconcile net income to cash provided by operating activities: | | | | | | Adjustments to reconcile net income to cash provided by operating activities: | |
| Depreciation and amortization | 232.2 |
| | 210.0 |
| | 193.9 |
| Depreciation and amortization | 298 | | | 232 | | | 210 | |
| Demand side management program amortization | — |
| | 1.7 |
| | 1.7 |
| Demand side management program amortization | 0 | | | 0 | | | 2 | |
| Deferred income taxes | 29.0 |
| | 22.1 |
| | 126.5 |
| Deferred income taxes | 22 | | | 29 | | | 22 | |
| Allowance for equity funds used during construction | (26.8 | ) | | (19.1 | ) | | (9.3 | ) | Allowance for equity funds used during construction | (33) | | | (27) | | | (19) | |
| Provision for bad debts | 5.7 |
| | 4.9 |
| | 5.1 |
| Provision for bad debts | 6 | | | 6 | | | 5 | |
| Net derivative losses | — |
| | 0.1 |
| | 0.1 |
| |
| Changes in operating assets and liabilities: | | | | | | Changes in operating assets and liabilities: | |
| Accounts receivable | (9.0 | ) | | (19.5 | ) | | (10.4 | ) | Accounts receivable | (14) | | | (9) | | | (20) | |
| Accrued unbilled revenues | (0.6 | ) | | 15.3 |
| | (10.4 | ) | Accrued unbilled revenues | 0 | | | (1) | | | 15 | |
| Inventories | (20.5 | ) | | (16.0 | ) | | (1.9 | ) | Inventories | (35) | | | (21) | | | (16) | |
| Prepayments and other | 2.8 |
| | 0.5 |
| | 4.3 |
| Prepayments and other | (14) | | | 3 | | | 1 | |
| Accounts payable | (8.5 | ) | | (6.6 | ) | | 11.8 |
| Accounts payable | 8 | | | (9) | | | (7) | |
| Net regulatory assets and liabilities | 13.8 |
| | 38.2 |
| | 38.1 |
| Net regulatory assets and liabilities | (115) | | | 14 | | | 38 | |
| Other current liabilities | 5.8 |
| | 11.6 |
| | 3.4 |
| Other current liabilities | 13 | | | 6 | | | 12 | |
| Pension and other employee benefit obligations | (17.7 | ) | | (16.0 | ) | | (21.7 | ) | Pension and other employee benefit obligations | (16) | | | (18) | | | (16) | |
| Other, net | 3.5 |
| | 5.8 |
| | (19.9 | ) | Other, net | (1) | | | 5 | | | 6 | |
| Net cash provided by operating activities | 472.8 |
| | 446.3 |
| | 470.5 |
| Net cash provided by operating activities | 414 | | | 473 | | | 446 | |
| | | | | | | |
| Investing activities | | | | | | Investing activities | |
| Utility capital/construction expenditures | (844.4 | ) | | (1,020.9 | ) | | (550.6 | ) | Utility capital/construction expenditures | (1,142) | | | (844) | | | (1,021) | |
| Investments in utility money pool arrangement | (133.0 | ) | | (285.0 | ) | | (142.0 | ) | Investments in utility money pool arrangement | (4) | | | (133) | | | (285) | |
| Receipts from utility money pool arrangement | 133.0 |
| | 350.0 |
| | 77.0 |
| Receipts from utility money pool arrangement | 4 | | | 133 | | | 350 | |
| Other | — |
| | — |
| | (0.5 | ) | |
| Net cash used in investing activities | (844.4 | ) | | (955.9 | ) | | (616.1 | ) | Net cash used in investing activities | (1,142) | | | (844) | | | (956) | |
| | | | | | | |
| Financing activities | | | | | | Financing activities | |
| (Repayments of) proceeds from short-term borrowings, net | (42.0 | ) | | 42.0 |
| | (50.0 | ) | |
| Proceeds from issuance of long-term debt | 292.2 |
| | 295.0 |
| | 442.3 |
| |
| Repayment of long-term debt, including reacquisition premiums | — |
| | — |
| | (271.6 | ) | |
| Proceeds from (repayments of) short-term borrowings, net | | Proceeds from (repayments of) short-term borrowings, net | 250 | | | (42) | | | 42 | |
| Proceeds from issuance of long-term debt, net | | Proceeds from issuance of long-term debt, net | 343 | | | 292 | | | 295 | |
| Borrowings under utility money pool arrangement | 296.0 |
| | 595.0 |
| | 335.0 |
| Borrowings under utility money pool arrangement | 561 | | | 296 | | | 595 | |
| Repayments under utility money pool arrangement | (296.0 | ) | | (595.0 | ) | | (335.0 | ) | Repayments under utility money pool arrangement | (561) | | | (296) | | | (595) | |
| Capital contributions from parent | 426.3 |
| | 336.8 |
| | 143.7 |
| Capital contributions from parent | 438 | | | 426 | | | 337 | |
| Dividends paid to parent | (332.7 | ) | | (131.0 | ) | | (108.8 | ) | Dividends paid to parent | (313) | | | (333) | | | (131) | |
| Net cash provided by financing activities | 343.8 |
| | 542.8 |
| | 155.6 |
| Net cash provided by financing activities | 718 | | | 343 | | | 543 | |
| | | | | | | |
| Net change in cash, cash equivalents and restricted cash | (27.8 | ) | | 33.2 |
| | 10.0 |
| |
| Cash, cash equivalents and restricted cash at beginning of year | 44.0 |
| | 10.8 |
| | 0.8 |
| |
| Cash, cash equivalents and restricted cash at end of year | $ | 16.2 |
| | $ | 44.0 |
| | $ | 10.8 |
| |
| Net change in cash and cash equivalents | | Net change in cash and cash equivalents | (10) | | | (28) | | | 33 | |
| Cash and cash equivalents at beginning of period | | Cash and cash equivalents at beginning of period | 16 | | | 44 | | | 11 | |
| Cash and cash equivalents at end of period | | Cash and cash equivalents at end of period | $ | 6 | | | $ | 16 | | | $ | 44 | |
| | |
| | |
| | |
| | | | | | |
| Supplemental disclosure of cash flow information: | | | | | | Supplemental disclosure of cash flow information: | |
| Cash paid for interest (net of amounts capitalized) | $ | (83.6 | ) | | $ | (71.2 | ) | | $ | (76.0 | ) | Cash paid for interest (net of amounts capitalized) | $ | (98) | | | $ | (84) | | | $ | (71) | |
| Cash received (paid) for income taxes, net | 11.9 |
| | (10.6 | ) | | 41.5 |
| Cash received (paid) for income taxes, net | 10 | | | 12 | | | (11) | |
| Supplemental disclosure of non-cash investing transactions: | | | | | | |
| Property, plant and equipment additions in accounts payable | $ | 94.5 |
| | $ | 71.5 |
| | $ | 85.1 |
| |
| Inventory transfer additions in property, plant and equipment | 23.3 |
| | 22.5 |
| | 13.7 |
| |
| | Supplemental disclosure of non-cash investing and financing transactions: | | Supplemental disclosure of non-cash investing and financing transactions: | |
| Accrued property, plant and equipment additions | | Accrued property, plant and equipment additions | $ | 99 | | | $ | 95 | | | $ | 72 | |
| Inventory transfers to property, plant and equipment | | Inventory transfers to property, plant and equipment | 31 | | | 23 | | | 23 | |
| Operating lease right-of-use assets | 548.3 |
| | — |
| | — |
| Operating lease right-of-use assets | 0 | | | 548 | | | 0 | |
| Allowance for equity funds used during construction | 26.8 |
| | 19.1 |
| | 9.3 |
| Allowance for equity funds used during construction | 33 | | | 27 | | | 19 | |
See Notes to Financial Statements
SOUTHWESTERN PUBLIC SERVICE CO.
BALANCE SHEETS
(amounts in millions, except share and per share data)
| | | | | Dec. 31 | | Dec. 31 |
| | | 2019 | | 2018 | | 2020 | | 2019 |
| Assets | | | | | Assets | | | | |
| Current assets | | | | | Current assets | |
| Cash and cash equivalents | | $ | 16.2 |
| | $ | 44.0 |
| Cash and cash equivalents | | $ | 6 | | | $ | 16 | |
| Accounts receivable, net | | 92.7 |
| | 90.7 |
| Accounts receivable, net | | 94 | | | 93 | |
| Accounts receivable from affiliates | | 4.2 |
| | 10.5 |
| Accounts receivable from affiliates | | 9 | | | 4 | |
| Investments in money pool arrangements | | — |
| | — |
| |
| Accrued unbilled revenues | | 115.1 |
| | 114.5 |
| Accrued unbilled revenues | | 114 | | | 115 | |
| Inventories | | 31.0 |
| | 33.9 |
| Inventories | | 36 | | | 31 | |
| Regulatory assets | | 20.0 |
| | 26.0 |
| Regulatory assets | | 76 | | | 20 | |
| Derivative instruments | | 15.0 |
| | 17.8 |
| Derivative instruments | | 10 | | | 15 | |
| Prepaid taxes | | 0.8 |
| | 14.2 |
| Prepaid taxes | | 18 | | | 1 | |
| Prepayments and other | | 21.4 |
| | 10.7 |
| Prepayments and other | | 20 | | | 21 | |
| Total current assets | | 316.4 |
| | 362.3 |
| Total current assets | | 383 | | | 316 | |
| | | | | | | | | |
| Property, plant and equipment, net | | 6,631.6 |
| | 5,946.4 |
| Property, plant and equipment, net | | 7,603 | | | 6,632 | |
| | | | | | |
| Other assets | | | | | Other assets | |
| Regulatory assets | | 364.0 |
| | 366.2 |
| Regulatory assets | | 357 | | | 364 | |
| Derivative instruments | | 12.6 |
| | 15.8 |
| Derivative instruments | | 9 | | | 13 | |
| Operating lease right-of-use assets | | 522.4 |
| | — |
| Operating lease right-of-use assets | | 492 | | | 522 | |
| Other | | 3.9 |
| | 5.1 |
| Other | | 15 | | | 4 | |
| Total other assets | | 902.9 |
| | 387.1 |
| Total other assets | | 873 | | | 903 | |
| Total assets | | $ | 7,850.9 |
| | $ | 6,695.8 |
| Total assets | | $ | 8,859 | | | $ | 7,851 | |
| | | | | | | | | |
| Liabilities and Equity | | | | | Liabilities and Equity | |
| Current liabilities | | | | | Current liabilities | |
| Short-term debt | | $ | — |
| | $ | 42.0 |
| Short-term debt | | $ | 250 | | | $ | 0 | |
| Accounts payable | | 168.1 |
| | 191.8 |
| Accounts payable | | 198 | | | 168 | |
| Accounts payable to affiliates | | 20.4 |
| | 19.9 |
| Accounts payable to affiliates | | 17 | | | 20 | |
| Regulatory liabilities | | 118.1 |
| | 85.8 |
| Regulatory liabilities | | 57 | | | 118 | |
| Taxes accrued | | 40.4 |
| | 41.6 |
| Taxes accrued | | 54 | | | 40 | |
| Accrued interest | | 26.2 |
| | 25.8 |
| Accrued interest | | 29 | | | 26 | |
| Dividends payable | | 46.3 |
| | 45.2 |
| |
| Dividends payable to parent | | Dividends payable to parent | | 54 | | | 46 | |
| Derivative instruments | | 3.7 |
| | 3.6 |
| Derivative instruments | | 4 | | | 4 | |
| Operating lease liabilities | | 26.9 |
| | — |
| Operating lease liabilities | | 28 | | | 27 | |
| Other | | 30.7 |
| | 28.3 |
| Other | | 25 | | | 31 | |
| Total current liabilities | | 480.8 |
| | 484.0 |
| Total current liabilities | | 716 | | | 480 | |
| | | | | | | | | |
| Deferred credits and other liabilities | | | | | Deferred credits and other liabilities | |
| Deferred income taxes | | 671.8 |
| | 619.1 |
| Deferred income taxes | | 725 | | | 672 | |
| Regulatory liabilities | | 732.3 |
| | 780.9 |
| Regulatory liabilities | | 718 | | | 732 | |
| Asset retirement obligations | | 77.3 |
| | 32.4 |
| Asset retirement obligations | | 112 | | | 77 | |
| Derivative instruments | | 12.8 |
| | 16.4 |
| Derivative instruments | | 9 | | | 13 | |
| Pension and employee benefit obligations | | 67.0 |
| | 92.4 |
| Pension and employee benefit obligations | | 42 | | | 67 | |
| Operating lease liabilities | | 495.3 |
| | — |
| Operating lease liabilities | | 463 | | | 495 | |
| Other | | 9.4 |
| | 7.9 |
| Other | | 12 | | | 10 | |
| Total deferred credits and other liabilities | | 2,065.9 |
| | 1,549.1 |
| Total deferred credits and other liabilities | | 2,081 | | | 2,066 | |
| | | | | | | | | |
| Commitments and contingencies | |
|
| |
|
| Commitments and contingencies | | 0 | | 0 |
| Capitalization | | | | | Capitalization | |
| Long-term debt | | 2,419.7 |
| | 2,126.1 |
| Long-term debt | | 2,764 | | | 2,420 | |
| Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2019 and 2018, respectively | | — |
| | — |
| |
| Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2020 and Dec. 31, 2019, respectively | | Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2020 and Dec. 31, 2019, respectively | | 0 | | | 0 | |
| Additional paid in capital | | 2,350.9 |
| | 1,932.3 |
| Additional paid in capital | | 2,790 | | | 2,351 | |
| Retained earnings | | 535.0 |
| | 605.7 |
| Retained earnings | | 509 | | | 535 | |
| Accumulated other comprehensive loss | | (1.4 | ) | | (1.4 | ) | Accumulated other comprehensive loss | | (1) | | | (1) | |
| Total common stockholder’s equity | | 2,884.5 |
| | 2,536.6 |
| |
| Total common stockholder's equity | | Total common stockholder's equity | | 3,298 | | | 2,885 | |
| Total liabilities and equity | | $ | 7,850.9 |
| | $ | 6,695.8 |
| Total liabilities and equity | | $ | 8,859 | | | $ | 7,851 | |
See Notes to Financial Statements
SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
(amounts in millions, except share data)
| | | | | | | | | | | | | | | Common Stock Issued | | Accumulated Other Comprehensive Income (Loss) | | Total Common Stockholder’s Equity |
| | Common Stock Issued | | | | Accumulated Other Comprehensive Income (Loss) | | Total Common Stockholder’s Equity | | Shares | | Par Value | | Additional Paid In Capital | | Retained Earnings | |
| | Shares | | Par Value | | Additional Paid In Capital | | Retained Earnings | | |
| Balance at Dec. 31, 2016 | 100 |
| | $ | — |
| | $ | 1,446.2 |
| | $ | 486.7 |
| | $ | (1.3 | ) | | $ | 1,931.6 |
| |
| | | | | | | | | | | | | |
| Net income | | | | | | | 159.2 |
| | | | 159.2 |
| |
| Other comprehensive loss | | | | | | | | | 0.1 |
| | 0.1 |
| |
| Common dividends declared to parent | | | | | | | (104.6 | ) | | | | (104.6 | ) | |
| Contribution of capital by parent | | | | | 144.0 |
| | | | | | 144.0 |
| |
| Adoption of ASU No. 2018-02 | | | | | | | 0.3 |
| | (0.3 | ) | | — |
| |
| Balance at Dec. 31, 2017 | 100 |
| | $ | — |
| | $ | 1,590.2 |
| | $ | 541.6 |
| | $ | (1.5 | ) | | $ | 2,130.3 |
| Balance at Dec. 31, 2017 | 100 | | | $ | 0 | | | $ | 1,590 | | | $ | 541 | | | $ | (1) | | | $ | 2,130 | |
| | | | | | | | | | | | | |
| Net income | | | | | | | 213.3 |
| | | | 213.3 |
| Net income | | 213 | | | 213 | |
| Other comprehensive loss | | | | | | | | | 0.1 |
| | 0.1 |
| |
| | Common dividends declared to parent | | | | | | | (149.2 | ) | | | | (149.2 | ) | Common dividends declared to parent | | (148) | | | (148) | |
| Contribution of capital by parent | | | | | 342.1 |
| | | | | | 342.1 |
| Contribution of capital by parent | | 342 | | | 342 | |
| | Balance at Dec. 31, 2018 | 100 |
| | $ | — |
| | $ | 1,932.3 |
| | $ | 605.7 |
| | $ | (1.4 | ) | | $ | 2,536.6 |
| Balance at Dec. 31, 2018 | 100 | | | $ | 0 | | | $ | 1,932 | | | $ | 606 | | | $ | (1) | | | $ | 2,537 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| Net income | | | | | | | 263.1 |
| | | | 263.1 |
| Net income | | 263 | | | 263 | |
| Other comprehensive income | | | | | | | | | — |
| | — |
| |
| | Common dividends declared to parent | | | | | | | (333.8 | ) | | | | (333.8 | ) | Common dividends declared to parent | | (334) | | | (334) | |
| Contribution of capital by parent | | | | | 418.6 |
| | | | | | 418.6 |
| Contribution of capital by parent | | 419 | | | 419 | |
| Balance at Dec. 31, 2019 | 100 |
| | $ | — |
| | $ | 2,350.9 |
| | $ | 535.0 |
| | $ | (1.4 | ) | | $ | 2,884.5 |
| Balance at Dec. 31, 2019 | 100 | | | $ | 0 | | | $ | 2,351 | | | $ | 535 | | | $ | (1) | | | $ | 2,885 | |
| | Net income | | Net income | | 295 | | | 295 | |
| | Common dividends declared to parent | | Common dividends declared to parent | | (321) | | | (321) | |
| Contribution of capital by parent | | Contribution of capital by parent | | 439 | | | 439 | |
| Balance at Dec. 31, 2020 | | Balance at Dec. 31, 2020 | 100 | | | $ | 0 | | | $ | 2,790 | | | $ | 509 | | | $ | (1) | | | $ | 3,298 | |
See Notes to Financial Statements
SOUTHWESTERN PUBLIC SERVICE COMPANY
Notes to Financial Statements
|
| |
| 1. Summary of Significant Accounting Policies |
General — SPS is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity.
SPS’ financial statements are presented in accordance with GAAP. All of SPS’ underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions. Certain amounts in the 2018 and 2017 financial statements or notes have been reclassified to conform to the 2019 presentation for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.
SPS has evaluated events occurring after Dec. 31, 20192020 up to the date of issuance of these financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.
Use of Estimates — SPS uses estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used on items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results.
Regulatory Accounting — SPS accounts for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:
•Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; andrates.
•Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates or because the amounts were collected in rates prior to the costs being incurred.
Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.
If changes in the regulatory environment occur, SPS may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on SPS’ results of operations, financial condition and cash flows.
See Note 4 for further information.
Income Taxes — SPS accounts for income taxes using the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. SPS defers income taxes for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities. SPS uses rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.
The effects of SPS’ tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, which willwould be refundable to utility customers over the remaining life of the related assets. ASPS anticipates that a tax rate increase would result in the establishment of a similar regulatory asset.asset, subject to regulatory approval.
Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of regulatory assets and liabilities related to income taxes. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized.
SPS follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. SPS recognizes a tax position in its financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax expense.
SPS reports interest and penalties related to income taxes within the other (expense) income andor interest charges in the statements of income.
Xcel Energy Inc. and its subsidiaries, including SPS, filesfile consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.
See Note 7 for further information.
Property, Plant and Equipment and Depreciation in Regulated Operations — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.
Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.
SPS records depreciation expense using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Plant removal costs are recovered in rates as authorized by the appropriate regulatory entities. The amount of removal costs are based on current factors used in existing depreciation rates. Depreciation expense, expressed as a percentage of average depreciable property, was 3.1% in 2020, 2.9% in 2019 and 2.9% in 2018 and 2.8% in 2017.2018.
See Note 3 for further information.
AROs — SPS accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. SPS also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.
See Note 10 for further information.
Benefit Plans and Other Postretirement Benefits — SPS maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates.
Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.
See Note 9 for further information.
Environmental Costs — Environmental costs are recorded when it is probable SPS is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant.
Estimated remediation costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating PRPspotentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for SPS’ expected share of the cost.
Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.
See Note 10 for further information.
Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. SPS recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs on a systematic basissystematically throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is recognized.
SPS does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. SPS presents its revenues net of any excise or sales taxes or fees.
SPS participates in SPP. SPS recognizes physical sales to both nativecustomers (native load and other end use customerswholesale) on a gross basis in electric revenues and cost of sales. Revenues and charges for short-term physical wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other revenues and charges related to participating and transacting in RTOssettled/facilitated through an RTO are recorded on a net basis in cost of sales.
See Note 6 for further information.
Cash and Cash Equivalents — SPS considers investments in instruments with a remaining maturity of three months or less at the time of purchase to be cash equivalents.
Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. SPS establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.
As of Dec. 31, 20192020 and 2018,2019, the allowance for bad debts was $5.3$8 million and $5.6$5 million, respectively.
Inventory — Inventory is recorded at average cost and consisted of the following: |
| | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2019 | | Dec. 31, 2018 |
| Inventories | | | | |
| Materials and supplies | | $ | 24.7 |
| | $ | 25.7 |
|
| Fuel | | 6.3 |
| | 8.2 |
|
| Total inventories | | $ | 31.0 |
| | $ | 33.9 |
|
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2020 | | Dec. 31, 2019 |
| Inventories | | | | |
| Materials and supplies | | $ | 27 | | | $ | 25 | |
| Fuel | | 9 | | | 6 | |
| Total inventories | | $ | 36 | | | $ | 31 | |
Fair Value Measurements — SPS presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its financial statements. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, SPS may use quoted prices for similar contracts or internally prepared valuation models to determine fair value. For the pension and postretirement plan assets published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security.
See Notes 8 and 9 for further information.
Derivative Instruments — SPS uses derivative instruments in connection with its utility commodity price and interest rate activities, including forward contracts, futures, swaps and options. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on expected recovery of derivative instrument settlements through fuel and purchased energy cost recovery mechanisms. Interest rate hedging transactions are recorded as a component of interest expense.
Normal Purchases and Normal Sales — SPS enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale.
See Note 8 for further information.
Other Utility Items
AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in SPS’ rate base for establishing utility rates.
Alternative Revenue — Certain rate rider mechanisms (including DSM programs) qualify as alternative revenue programs. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, including expected collection within 24 months, revenue is recognized equal to the revenue requirement, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers.
See Note 6 for further information.
Conservation Programs — SPS has implemented programs in its jurisdictions to assist customers in conserving energy and reducing peak demand on the electric system. These programs include commercial motor, air conditioner and lighting upgrades, as well as residential rebates for participation in air conditioner interruption and home weatherization.
The costs incurred for some DSM programs are deferred as permitted by the applicable regulatory jurisdiction. For those programs, costs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. Revenues recognized for incentive programs designed for recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the annual period in which they are earned. SPS recovers approved conservation program costs in base rate revenue or through a rider.
Emission Allowances — Emission allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these allowances are included in electric revenues.
RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. SPS reduces recoverable fuel costs for the cost of RECs and records that cost as a regulatory asset when the amount is recoverable in future rates.
Sales of RECs are recorded in electric revenues on a gross basis. Cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.
Segment Information — SPS has only one reportable segment. SPS is a wholly owned subsidiary of Xcel Energy Inc. and operates in the regulated electric utility industry providing wholesale and retail electric service in the states of Texas and New Mexico.
|
| |
| 2. Accounting Pronouncements |
Recently IssuedAdopted
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
SPS implemented the guidance using a modified-retrospective approach, with a cumulative-effect adjustmentrecognizing an immaterial cumulative effect charge (after tax) to retained earnings as ofon Jan. 1, 2020. SPS expects the impact of adoption of the new standard to include first-time recognition of expected credit losses (i.e., bad debt expense) on unbilled revenues, with the initial allowance established atThe Jan. 1, 2020 charged to retained earnings. Recognition of this allowance and other impacts of adoption are expected to be immaterial to the financial statements.
Recently Adopted
Leases — In 2016, the FASB issued Leases, Topic 842(ASC Topic 842), which provides new accounting and disclosure guidance for leasing activities, most significantly requiring that operating leases be recognized on the balance sheet. SPS adopted the guidance 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, SPS 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.
SPS 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 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). Other than first-time recognition of operating leases on its balance sheet, the implementation of ASC Topic 842326 did not have a significant impact on SPS’ financial statements. Adoption resulted in recognition of approximately $0.5 billion of operating lease ROU assets and current/noncurrent operating lease liabilities.
See Note 10 for leasing disclosures.
|
| |
| 3. Property, Plant and Equipment |
Major classes of property, plant and equipment
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2020 | | Dec. 31, 2019 |
| Property, plant and equipment, net | | | | |
| Electric plant | | $ | 9,229 | | | $ | 8,453 | |
Plant to be retired (a) | | 316 | | | 0 | |
| CWIP | | 146 | | | 486 | |
| Total property, plant and equipment | | 9,691 | | | 8,939 | |
| Less accumulated depreciation | | (2,088) | | | (2,307) | |
| Property, plant and equipment, net | | $ | 7,603 | | | $ | 6,632 | |
|
| | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2019 | | Dec. 31, 2018 |
| Property, plant and equipment | | | | |
| Electric plant | | $ | 8,453.0 |
| | $ | 7,227.7 |
|
| CWIP | | 485.4 |
| | 847.3 |
|
| Total property, plant and equipment | | 8,938.4 |
| | 8,075.0 |
|
| Less accumulated depreciation | | (2,306.8 | ) | | (2,128.6 | ) |
| Property, plant and equipment, net | | $ | 6,631.6 |
| | $ | 5,946.4 |
|
|
| |
| 4. Regulatory Assets and Liabilities |
Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric rates. SPS would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP.
Components of regulatory assets:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | See Note(s) | | Remaining Amortization Period | | Dec. 31, 2020 | | Dec. 31, 2019 |
| Regulatory Assets | | | | | | Current | | Noncurrent | | Current | | Noncurrent |
| Pension and retiree medical obligations | 9 | | Various | | $ | 12 | | | $ | 178 | | | $ | 11 | | | $ | 204 | |
| Excess deferred taxes — TCJA | | 7 | | Various | | 3 | | | 51 | | | 2 | | | 52 | |
| Recoverable deferred taxes on AFUDC | | | | Plant lives | | 0 | | | 42 | | | 0 | | | 34 | |
Net AROs (a) | | 1, 10 | | Various | | 0 | | | 33 | | | 0 | | | 27 | |
| Losses on reacquired debt | | | | Term of related debt | | 1 | | | 20 | | | 1 | | | 21 | |
| Texas revenue surcharge | | | | One to two years | | 54 | | | 17 | | | 2 | | | 0 | |
Conservation programs (b) | | 1 | | One to two years | | 1 | | | 2 | | | 1 | | | 1 | |
| Other | | | | Various | | 5 | | | 14 | | | 3 | | | 25 | |
| Total regulatory assets | | | | | | $ | 76 | | | $ | 357 | | | $ | 20 | | | $ | 364 | |
|
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | See
Note(s) | | Remaining
Amortization Period | | Dec. 31, 2019 | | Dec. 31, 2018 |
| Regulatory Assets | | | | | | Current | | Noncurrent | | Current | | Noncurrent |
| Pension and retiree medical obligations | 9 | | Various | | $ | 11.1 |
| | $ | 203.5 |
| | $ | 12.6 |
| | $ | 222.1 |
|
| Excess deferred taxes — TCJA | | 7 | | Various | | 1.7 |
| | 52.0 |
| | — |
| | 55.9 |
|
Recoverable deferred taxes on AFUDC recorded in plant | | | | Plant lives | | — |
| | 34.1 |
| | — |
| | 27.9 |
|
Net AROs (a) | | 1, 10 | | Plant lives | | — |
| | 26.9 |
| | — |
| | 25.7 |
|
| Losses on reacquired debt | | | | Term of related debt | | 0.8 |
| | 21.0 |
| | 0.8 |
| | 21.9 |
|
Conservation programs (b) | | 1 | | One to two years | | 0.6 |
| | 1.1 |
| | 0.7 |
| | 0.6 |
|
| Other | | | | Various | | 5.8 |
| | 25.4 |
| | 11.9 |
| | 12.1 |
|
| Total regulatory assets | | | | | | $ | 20.0 |
| | $ | 364.0 |
| | $ | 26.0 |
| | $ | 366.2 |
|
| |
(a)(b)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. | Includes amounts recorded for future recovery of AROs. |
| |
(b)
| Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. |
Components of regulatory liabilities:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | See Note(s) | | Remaining Amortization Period | | Dec. 31, 2020 | | Dec. 31, 2019 |
| Regulatory Liabilities | | | | | | Current | | Noncurrent | | Current | | Noncurrent |
Deferred income tax adjustments and TCJA refunds (a) | | 7 | | | Various | | $ | 6 | | | $ | 513 | | | $ | 7 | | | $ | 535 | |
| Plant removal costs | | 1, 10 | | Various | | 0 | | | 177 | | | 0 | | | 175 | |
| Revenue subject to refund | | | | One to two years | | 4 | | | 4 | | | 14 | | | 1 | |
| Gain from asset sales | | | | Various | | 0 | | | 2 | | | 0 | | | 2 | |
| Deferred electric energy costs | | | | Less than one year | | 35 | | | 0 | | | 82 | | | 0 | |
Contract valuation adjustments (b) | | 1, 8 | | Less than one year | | 7 | | | 0 | | | 12 | | | 0 | |
| Other | | | | Various | | 5 | | | 22 | | | 3 | | | 19 | |
Total regulatory liabilities (c) | | | | | | $ | 57 | | | $ | 718 | | | $ | 118 | | | $ | 732 | |
|
| | | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | See
Note(s) | | Remaining
Amortization Period | | Dec. 31, 2019 | | Dec. 31, 2018 |
| Regulatory Liabilities | | | | | | Current | | Noncurrent | | Current | | Noncurrent |
Deferred income tax adjustments and TCJA refunds (a) | | 7 |
| | Various | | $ | 6.9 |
| | $ | 534.9 |
| | $ | 2.2 |
| | $ | 569.8 |
|
| Plant removal costs | | 1, 10 |
| | Plant lives | | — |
| | 174.5 |
| | — |
| | 187.7 |
|
| Revenue subject to refund | | | | One to two years | | 14.6 |
| | 1.1 |
| | 11.3 |
| | 8.1 |
|
| Gain from asset sales | | | | Various | | — |
| | 2.4 |
| | — |
| | 2.4 |
|
| Deferred electric energy costs | | | | Less than one year | | 81.6 |
| | — |
| | 56.5 |
| | — |
|
Contract valuation adjustments (b) | | 1, 8 |
| | Less than one year | | 11.7 |
| | — |
| | 14.7 |
| | — |
|
| Other | | | | Various | | 3.3 |
| | 19.4 |
| | 1.1 |
| | 12.9 |
|
Total regulatory liabilities (c) | | | | | | $ | 118.1 |
| | $ | 732.3 |
| | $ | 85.8 |
| | $ | 780.9 |
|
| |
(a)(b)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements. (c)Revenue subject to refund of $4 million for 2019 was included in other current liabilities and none for 2020. | Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA. |
| |
(b)
| Includes the fair value of certain long-term PPAs used to meet energy capacity requirements. |
| |
(c)
| Revenue subject to refund of $3.9 million for 2019 and none for 2018 is included in other current liabilities. |
At Dec. 31, 20192020 and 2018,2019, SPS’ regulatory assets not earning a return primarily included the unfunded portion of pension and retiree medical obligations and net AROs. In addition, SPS’ regulatory assets included $56.5$114 million and $50.5$57 million at Dec. 31, 20192020 and 2018,2019, respectively, of past expenditures not earning a return. Amounts primarilyare related to formula rates, losses on reacquired debt and certain rate case expenditures.
|
| |
| 5. Borrowings and Other Financing Instruments |
Short-Term Borrowings
SPS meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool.
Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc.
Money pool borrowings for SPS were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars, Except Interest Rates) | | Three Months Ended Dec. 31, 2020 | | Year Ended Dec. 31 |
| | 2020 | | 2019 | | 2018 |
| Borrowing limit | | $ | 100 | | | $ | 100 | | | $ | 100 | | | $ | 100 | |
| Amount outstanding at period end | | 0 | | | 0 | | | 0 | | | 0 | |
| Average amount outstanding | | 81 | | | 43 | | | 8 | | | 29 | |
| Maximum amount outstanding | | 100 | | | 100 | | | 100 | | | 100 | |
| Weighted average interest rate, computed on a daily basis | | 0.08 | % | | 0.54 | % | | 2.42 | % | | 1.96 | % |
| Weighted average interest rate at end of period | | N/A | | N/A | | N/A | | N/A |
|
| | | | | | | | | | | | | | | | |
| (Millions of Dollars, Except Interest Rates) | | Three Months Ended Dec. 31, 2019 | | Year Ended Dec. 31 |
| | | 2019 | | 2018 | | 2017 |
| Borrowing limit | | $ | 100 |
| | $ | 100 |
| | $ | 100 |
| | $ | 100 |
|
| Amount outstanding at period end | | — |
| | — |
| | — |
| | — |
|
| Average amount outstanding | | 1 |
| | 8 |
| | 29 |
| | 13 |
|
| Maximum amount outstanding | | 12 |
| | 100 |
| | 100 |
| | 100 |
|
| Weighted average interest rate, computed on a daily basis | | 1.63 | % | | 2.42 | % | | 1.96 | % | | 1.12 | % |
| Weighted average interest rate at end of period | | N/A |
| | N/A |
| | N/A |
| | N/A |
|
Commercial Paper — Commercial paper outstanding for SPS was as follows:
|
| | | | | | | | | | | | | | | | |
| (Millions of Dollars, Except Interest Rates) | | Three Months Ended Dec. 31, 2019 | | Year Ended Dec. 31 |
| | | 2019 | | 2018 | | 2017 |
| Borrowing limit | | $ | 500 |
| | $ | 500 |
| | $ | 400 |
| | $ | 400 |
|
| Amount outstanding at period end | | — |
| | — |
| | 42 |
| | — |
|
| Average amount outstanding | | — |
| | 72 |
| | 30 |
| | 69 |
|
| Maximum amount outstanding | | — |
| | 316 |
| | 144 |
| | 176 |
|
| Weighted average interest rate, computed on a daily basis | | N/A |
| | 2.68 | % | | 2.27 | % | | 1.13 | % |
| Weighted average interest rate at end of period | | N/A |
| | N/A |
| | 2.80 |
| | NA |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars, Except Interest Rates) | | Three Months Ended Dec. 31, 2020 | | Year Ended Dec. 31 |
| | 2020 | | 2019 | | 2018 |
| Borrowing limit | | $ | 500 | | | $ | 500 | | | $ | 500 | | | $ | 400 | |
| Amount outstanding at period end | | 250 | | | 250 | | | 0 | | | 42 | |
| Average amount outstanding | | 58 | | | 44 | | | 72 | | | 30 | |
| Maximum amount outstanding | | 250 | | | 250 | | | 316 | | | 144 | |
| Weighted average interest rate, computed on a daily basis | | 0.21 | % | | 1.11 | % | | 2.68 | % | | 2.27 | % |
| Weighted average interest rate at end of period | | 0.29 | | | 0.29 | | | N/A | | 2.80 | |
Letters of Credit — SPS may use letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. At both Dec. 31, 20192020 and 2018,2019, there were $2 million of letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.
Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, SPS must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
Amended Credit Agreement — In June 2019, SPS entered into an amended five-year credit agreement with a syndicate of banks. The amended credit agreements haveagreement has substantially the same terms and conditions as the prior credit agreementsagreement with the exception of the following:
•Maturity extended fromis June 2021 to June 2024; and2024.
•Borrowing limit increased from $400 million tois $500 million.
The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
Features of SPS’ credit facility:
| | | | | | | | | | | | | | | | | | | | |
Debt-to-Total Capitalization Ratio (a) | | Amount Facility May Be Increased (millions) | | Additional Periods for Which a One-Year Extension May Be Requested (b) |
| 2020 | | 2019 | | | | |
| 48% | | 46% | | $50 | | 2 |
|
| | | | | | |
Debt-to-Total Capitalization Ratio(a) | | Amount Facility May Be Increased (millions) | | Additional Periods for Which a One-Year Extension May Be Requested (b) |
| 2019 | | 2018 | | | | |
| 46% | | 46% | | $50 | | 2 |
| |
(a)(b) All extension requests are subject to majority bank group approval. | The SPS credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%. |
| |
(b)
| All extension requests are subject to majority bank group approval. |
The credit facility has a cross-default provision that SPS willwould be in default on its borrowings under the facility if SPS or any of its future significant subsidiaries whose total assets exceed 15% of SPS’ total assets default on indebtedness in an aggregate principal amount exceeding $75 million.
If SPS does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2019,2020, SPS was in compliance with all financial covenants.
SPS had the following committed credit facilitiesfacility available as of Dec. 31, 2019.2020.
| | | | | | | | | | | | | | |
Credit Facility (a) | | Drawn (b) | | Available |
| $500 | | $252 | | $248 |
|
| | | | |
Credit Facility (a) | | Drawn (b) | | Available |
| $500 | | $2 | | $498 |
| |
(a)This credit facility matures in June 2024. (b)Includes letters of credit and outstanding commercial paper. | This credit facility matures in June 2024. |
| |
(b)
| Includes letters of credit and outstanding commercial paper. |
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. SPS had 0 direct advances on the facility outstanding at Dec. 31, 20192020 and 2018.2019.
Long-Term Borrowings and Other Financing Instruments
Generally, all property of SPS is subject to the lien of its first mortgage indenture. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance.
Long-term debt obligations for SPS as of Dec. 31 (millions of dollars):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Financing Instrument | | Interest Rate | | Maturity Date | | 2020 | | 2019 |
| First mortgage bonds | | 3.30 | % | | June 15, 2024 | | $ | 150 | | | $ | 150 | |
| First mortgage bonds | | 3.30 | | | June 15, 2024 | | 200 | | | 200 | |
| Unsecured senior notes | | 6.00 | | | Oct. 1, 2033 | | 100 | | | 100 | |
| Unsecured senior notes | | 6.00 | | | Oct. 1, 2036 | | 250 | | | 250 | |
| First mortgage bonds | | 4.50 | | | Aug. 15, 2041 | | 200 | | | 200 | |
| First mortgage bonds | | 4.50 | | | Aug. 15, 2041 | | 100 | | | 100 | |
| First mortgage bonds | | 4.50 | | | Aug. 15, 2041 | | 100 | | | 100 | |
| First mortgage bonds | | 3.40 | | | Aug. 15, 2046 | | 300 | | | 300 | |
| First mortgage bonds | | 3.70 | | | Aug. 15, 2047 | | 450 | | | 450 | |
| First mortgage bonds | | 4.40 | | | Nov. 15, 2048 | | 300 | | | 300 | |
First mortgage bonds (b) | | 3.75 | | | June 15, 2049 | | 300 | | | 300 | |
First mortgage bonds (a) | | 3.15 | | | May 1, 2050 | | 350 | | | 0 | |
| Unamortized discount | | | | | | (10) | | | (7) | |
| Unamortized debt issuance cost | | | | | | (26) | | | (23) | |
| Total long-term debt | | | | | | $ | 2,764 | | | $ | 2,420 | |
|
| | | | | | | | | | | | | |
| Financing Instrument | | Interest Rate | | Maturity Date | | 2019 | | 2018 |
| First mortgage bonds | | 3.30 | % | | June 15, 2024 | | $ | 150 |
| | $ | 150 |
|
| First mortgage bonds | | 3.30 |
| | June 15, 2024 | | 200 |
| | 200 |
|
| Unsecured senior notes | | 6.00 |
| | Oct. 1, 2033 | | 100 |
| | 100 |
|
| Unsecured senior notes | | 6.00 |
| | Oct. 1, 2036 | | 250 |
| | 250 |
|
| First mortgage bonds | | 4.50 |
| | Aug. 15, 2041 | | 200 |
| | 200 |
|
| First mortgage bonds | | 4.50 |
| | Aug. 15, 2041 | | 100 |
| | 100 |
|
| First mortgage bonds | | 4.50 |
| | Aug. 15, 2041 | | 100 |
| | 100 |
|
| First mortgage bonds | | 3.40 |
| | Aug. 15, 2046 | | 300 |
| | 300 |
|
| First mortgage bonds | | 3.70 |
| | Aug. 15, 2047 | | 450 |
| | 450 |
|
First mortgage bonds (b) | | 4.40 |
| | Nov. 15, 2048 | | 300 |
| | 300 |
|
First mortgage bonds (a) | | 3.75 |
| | June 15, 2049 | | 300 |
| | — |
|
| Unamortized discount | | | | | | (7 | ) | | (4 | ) |
| Unamortized debt issuance cost | | | | | | (23 | ) | | (20 | ) |
| Total long-term debt | | | | | | $ | 2,420 |
| | $ | 2,126 |
|
Maturities of long-term debt:
| | | (Millions of Dollars) | | | (Millions of Dollars) | |
| 2020 | | $ | — |
| |
| 2021 | | — |
| 2021 | | $ | 0 | |
| 2022 | | — |
| 2022 | | 0 | |
| 2023 | | — |
| 2023 | | 0 | |
| 2024 | | 350 |
| 2024 | | 350 | |
| 2025 | | 2025 | | 0 | |
Deferred Financing Costs — Deferred financing costs of approximately $23$26 million and $20$23 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 20192020 and 2018,2019, respectively. SPS is amortizing these financing costs over the remaining maturity periods of the related debt.
Capital Stock — SPS has the following preferred stock:
| | | | | | | | | | | | | | |
| Preferred Stock Authorized (Shares) | | Par Value of Preferred Stock | | Preferred Stock Outstanding (Shares) 2020 and 2019 |
| 10,000,000 | | | 1.00 | | | 0 | |
|
| | | | | | | |
| Preferred Stock Authorized (Shares) | | Par Value of Preferred Stock | | Preferred Stock Outstanding (Shares) 2019 and 2018 |
| 10,000,000 |
| | 1.00 |
| | — |
|
Dividend Restrictions — SPS dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings. SPS is required to be current on particular interest payments before dividends can be paid.
SPS’ state regulatory commissions additionally impose dividend limitations, which are more restrictive than those imposed by the FERC.
Requirements and actuals as of Dec. 31, 2019:2020:
|
| | | | | | | |
| Equity to Total Capitalization Ratio - Required Range | | Equity to Total Capitalization Ratio - Actual (a) |
| Low | | High | | 2019 |
| 45.0 | % | | 55.0 | % | | 54.4 | % |
| |
(a)
| Excludes short-term debt. |
|
| | | | | | | | |
| Unrestricted Retained Earnings | | Total Capitalization | | Limit on Total Capitalization (a) |
| $ | 535.0 | million | | $ | 5.3 | billion | | N/A |
| | | | | | | | | | | | | | |
Equity to Total Capitalization Ratio
Required Range | | Equity to Total Capitalization Ratio Actual (a) |
| Low | | High | | 2020 |
| 45.0 | % | | 55.0 | % | | 54.4 | % |
(a)Excludes short-term debt.
| | | | | | | | | | | | | | |
| Unrestricted Retained Earnings | | Total Capitalization | | Limit on Total Capitalization (a) |
| $ | 510 | million | | $ | 6 | billion | | N/A |
(a) SPS may not pay a dividend that would cause it to lose its investment grade bond rating.
Revenue is classified by the type of goods/services rendered and market/customer type. SPS’ operating revenues consisted of the following:
|
| | | | |
| (Millions of Dollars) | | Year Ended Dec. 31, 2019 |
| Major product lines | | |
| Revenue from contracts with customers: | | |
| Residential | | $ | 351.9 |
|
| C&I | | 800.3 |
|
| Other | | 41.1 |
|
| Total retail | | 1,193.3 |
|
| Wholesale | | 361.0 |
|
| Transmission | | 239.6 |
|
| Other | | 3.3 |
|
| Total revenue from contracts with customers | | 1,797.2 |
|
| Alternative revenue and other | | 28.6 |
|
| Total revenues | | $ | 1,825.8 |
|
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended Dec. 31 |
| (Millions of Dollars) | | 2020 | | 2019 | | 2018 |
| Major revenue types | | | | | | |
| Revenue from contracts with customers: | | | | | | |
| Residential | | $ | 359 | | | $ | 352 | | | $ | 364 | |
| C&I | | 739 | | | 800 | | | 828 | |
| Other | | 39 | | | 41 | | | 45 | |
| Total retail | | 1,137 | | | 1,193 | | | 1,237 | |
| Wholesale | | 345 | | | 361 | | | 426 | |
| Transmission | | 279 | | | 240 | | | 231 | |
| Other | | 4 | | | 3 | | | 13 | |
| Total revenue from contracts with customers | | 1,765 | | | 1,797 | | | 1,907 | |
| Alternative revenue and other | | 105 | | | 29 | | | 26 | |
| Total revenues | | $ | 1,870 | | | $ | 1,826 | | | $ | 1,933 | |
|
| | | | |
| (Millions of Dollars) | | Year Ended Dec. 31, 2018 |
| Major product lines | | |
| Revenue from contracts with customers: | | |
| Residential | | $ | 363.7 |
|
| C&I | | 828.3 |
|
| Other | | 44.7 |
|
| Total retail | | 1,236.7 |
|
| Wholesale | | 426.0 |
|
| Transmission | | 231.1 |
|
| Other | | 12.8 |
|
| Total revenue from contracts with customers | | 1,906.6 |
|
| Alternative revenue and other | | 26.6 |
|
| Total revenues | | $ | 1,933.2 |
|
Federal Tax ReformLoss Carryback Claims — In 2017, the TCJA was signed into law. The key provisions impacting2020, Xcel Energy (which includes SPS), generally beginning in 2018, included:
Corporate federalidentified certain expenses related to tax rate reduction from 35%years 2009 - 2011 that qualify for an extended carryback claim. SPS is not expected to 21%;
Normalization of resulting plant-related excess deferred taxes;
Elimination of the corporate alternative minimum tax;
Continued interest expense deductibility and discontinued bonus depreciation for regulated public utilities;
Limitations on certain executive compensation deductions;
Limitations on certain deductions for NOLs arising after Dec. 31, 2017 (limited to 80% of taxable income);
Repeal of the section 199 manufacturing deduction; and
Reduced deductions for meals and entertainment as well as state and local lobbying.
Xcel Energy estimated the effects of the TCJA, which have been reflected in the consolidated financial statements.
Reductions in deferred tax assets and liabilities due to a decrease in corporate federal tax rates typically result in a net tax benefit. However, the impacts are primarily recognized as regulatory liabilities refundable to utility customers as a result of IRS requirements and past regulatory treatment.
Estimated impacts of the new tax law for SPS in December 2017 included:
$426 million ($559 million grossed-up for tax) of reclassifications of plant-related excess deferred taxes to regulatory liabilities upon valuation at the new 21% federal rate. The regulatory liabilities will be amortized consistent with IRS normalization requirements, resulting in customer refunds over the average remaining life of the related property;
$45 million and $28 million of reclassifications (grossed-up for tax) of excess deferred taxes for non-plant related deferred tax assets and liabilities, respectively, to regulatory assets and liabilities; and
$8 million of total estimatedaccrue any income tax benefitexpense related to the federal tax reform implementation and a $2 million reduction to net income related to the allocation of Xcel Energy Services Inc.’s tax rate change on its deferred taxes.
Xcel Energy accounted for the state tax impacts of federal tax reform based on enacted state tax laws. Any future state tax law changes related to the TCJA will be accounted for in the periods state laws are enacted.this adjustment.
Federal Audit — SPS is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. StatuteStatue of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows:
|
| | | | | | | |
| Tax Year(s) | | Expiration |
2009 - 2013 | | June 2020 |
| 2014 - 2016 | | September 2020July 2021 |
Additionally, the statute of limitations related to the federal tax loss carryback claim referenced above has been extended. 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.
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 Dec. 31, 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 0 material adjustments were required.
In 2018, the IRS began an audit of tax years 2014 - 2016. As of Dec. 31, 2019 0 adjustments have been proposed.In July 2020, Xcel Energy and the IRS reached an agreement and the related benefit was recognized.
State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2019,2020, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009.2012. There are currently no0 state income tax audits in progress.
Unrecognized Tax 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) | | Dec. 31, 2019 | | Dec. 31, 2018 | (Millions of Dollars) | | Dec. 31, 2020 | | Dec. 31, 2019 |
| Unrecognized tax benefit — Permanent tax positions | | $ | 3.7 |
| | $ | 3.0 |
| Unrecognized tax benefit — Permanent tax positions | | $ | 3 | | | $ | 3 | |
| Unrecognized tax benefit — Temporary tax positions | | 1.5 |
| | 1.5 |
| Unrecognized tax benefit — Temporary tax positions | | 4 | | | 2 | |
| Total unrecognized tax benefit | | $ | 5.2 |
| | $ | 4.5 |
| Total unrecognized tax benefit | | $ | 7 | | | $ | 5 | |
Changes in unrecognized tax benefits:
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 |
| Balance at Jan. 1 | | $ | 4.5 |
| | $ | 4.3 |
| | $ | 28.7 |
|
| Additions based on tax positions related to the current year | | 0.7 |
| | 0.6 |
| | 0.9 |
|
| Reductions based on tax positions related to the current year | | (0.1 | ) | | (0.1 | ) | | (0.6 | ) |
| Additions for tax positions of prior years | | 0.2 |
| | 0.1 |
| | 1.3 |
|
| Reductions for tax positions of prior years | | (0.1 | ) | | (0.3 | ) | | (19.9 | ) |
| Settlements with taxing authorities | | — |
| | (0.1 | ) | | (6.1 | ) |
| Balance at Dec. 31 | | $ | 5.2 |
| | $ | 4.5 |
| | $ | 4.3 |
|
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2020 | | 2019 | | 2018 |
| Balance at Jan. 1 | | $ | 5 | | | $ | 5 | | | $ | 4 | |
| Additions based on tax positions related to the current year | | 1 | | | 0 | | | 1 | |
| Additions for tax positions of prior years | | 5 | | | 0 | | | 0 | |
| Reductions for tax positions of prior years | | (4) | | | 0 | | | 0 | |
| Balance at Dec. 31 | | $ | 7 | | | $ | 5 | | | $ | 5 | |
Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards: |
| | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2019 | | Dec. 31, 2018 |
| NOL and tax credit carryforwards | | $ | (4.4 | ) | | $ | (3.8 | ) |
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2020 | | Dec. 31, 2019 |
| NOL and tax credit carryforwards | | $ | (6) | | | $ | (4) | |
Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $1.4$2 million and $0.8$1 million at Dec. 31, 20192020 and Dec. 31, 2018,2019, respectively.
As the IRS Appeals and federal audit progresses and state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $3.7$5 million in the next 12 months.
Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.
Interest payable related to unrecognized tax benefits:
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 |
| Receivable (payable) for interest related to unrecognized tax benefits at Jan. 1 | | $ | 0.7 |
| | $ | 0.5 |
| | $ | (0.9 | ) |
| Interest income related to unrecognized tax benefits | | — |
| | 0.2 |
| | 1.4 |
|
| Receivable for interest related to unrecognized tax benefits at Dec. 31 | | $ | 0.7 |
| | $ | 0.7 |
| | $ | 0.5 |
|
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2020 | | 2019 | | 2018 |
| Receivable for interest related to unrecognized tax benefits at Jan. 1 | | $ | 1 | | | $ | 1 | | | $ | 1 | |
| Interest expense related to unrecognized tax benefits | | (2) | | | 0 | | | 0 | |
| (Payable) receivable for interest related to unrecognized tax benefits at Dec. 31 | | $ | (1) | | | $ | 1 | | | $ | 1 | |
NoNaN amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2020, 2019 2018, or 2017.2018.
Other Income Tax Matters — NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:
|
| | | | | | | | |
| (Millions of Dollars) | | 2019 | | 2018 |
| Federal tax credit carryforwards | | $ | 29.5 |
| | $ | 5.7 |
|
| State NOL carryforwards | | 1.2 |
| | 2.9 |
|
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2020 | | 2019 |
| Federal tax credit carryforwards | | $ | 83 | | | $ | 30 | |
| State NOL carryforwards | | 1 | | | 1 | |
Federal carryforward periods expire between 20242031 and 20392040 and state carryforward periods expire between 2025 and 2036.starting 2025.
Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.
Effective income tax rate for years ended Dec. 31: | | | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 | | 2018 |
| Federal statutory rate | | 21.0 | % | | 21.0 | % | | 21.0 | % |
| State income tax on pretax income, net of federal tax effect | | 2.3 | | | 2.2 | | | 2.3 | |
| Increases (decreases) in tax from: | | | | | | |
| Wind PTCs | | (18.3) | | | (7.9) | | | 0 | |
Plant regulatory differences (a) | | (6.4) | | | (5.0) | | | (4.8) | |
| Amortization of excess nonplant deferred taxes | | (0.8) | | | (0.9) | | | (1.2) | |
| Other tax credits, net NOL & tax credit allowances | | (0.7) | | | (0.6) | | | (0.7) | |
| Adjustments attributable to tax returns | | (0.6) | | | (0.1) | | | (1.5) | |
| Change in unrecognized tax benefits | | 0.3 | | | 0.2 | | | 0.1 | |
| Other, net | | (0.3) | | | 0.1 | | | 0.3 | |
| Effective income tax rate | | (3.5) | % | | 9.0 | % | | 15.5 | % |
|
| | | | | | | | |
| | 2019 | | 2018 (a) | | 2017 (a) |
| Federal statutory rate | 21.0 | % | | 21.0 | % | | 35.0 | % |
| State income tax on pretax income, net of federal tax effect | 2.2 | % | | 2.3 | % | | 2.0 | % |
| Increases (decreases) in tax from: |
|
| |
|
| |
|
|
| Wind PTCs | (7.9 | ) | | — |
| | — |
|
Plant regulatory differences (b) | (5.0 | ) | | (4.8 | ) | | (0.9 | ) |
| Amortization of excess nonplant deferred taxes | (0.9 | ) | | (1.2 | ) | | — |
|
| Other tax credits, net of NOL & tax credit allowances | (0.6 | ) | | (0.7 | ) | | (0.6 | ) |
| Adjustments attributable to tax returns | (0.1 | ) | | (1.5 | ) | | (0.4 | ) |
| Change in unrecognized tax benefits | 0.2 |
| | 0.1 |
| | (1.0 | ) |
| Tax reform | — |
| | — |
| | (3.5 | ) |
| Other, net | — |
| | 0.2 |
| | (0.5 | ) |
| Effective income tax rate | 8.9 | % | | 15.4 | % | | 30.1 | % |
| |
(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.
| Prior periods have been reclassified to conform to current year presentation. |
| |
(b)
| 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. |
Components of income tax expense for years ended Dec. 31:
| | | (Millions of Dollars) | | 2019 | | 2018 | | 2017 | (Millions of Dollars) | | 2020 | | 2019 | | 2018 |
Current federal tax (benefit) expense
| | $ | (3.9 | ) | | $ | 12.3 |
| | $ | (20.9 | ) | Current federal tax (benefit) expense | | $ | (31) | | | $ | (4) | | | $ | 12 | |
| Current state tax expense (benefit) | | 0.6 |
| | 2.3 |
| | (12.8 | ) | |
| Current change in unrecognized tax expense (benefit) | | — |
| | 2.3 |
| | (24.3 | ) | |
| Current state tax (benefit) expense | | Current state tax (benefit) expense | | (1) | | | 1 | | | 3 | |
| Current change in unrecognized tax expense | | Current change in unrecognized tax expense | | 0 | | | 0 | | | 2 | |
| Deferred federal tax expense | | 22.3 |
| | 20.5 |
| | 89.9 |
| Deferred federal tax expense | | 13 | | | 22 | | | 20 | |
| Deferred state tax expense | | 6.0 |
| | 3.6 |
| | 14.5 |
| Deferred state tax expense | | 8 | | | 6 | | | 4 | |
| Deferred change in unrecognized tax expense (benefit) | | 0.7 |
| | (2.0 | ) | | 22.1 |
| Deferred change in unrecognized tax expense (benefit) | | 1 | | | 1 | | | (2) | |
| Deferred ITCs | | (0.1 | ) | | (0.1 | ) | | (0.1 | ) | |
| Total income tax expense | | $ | 25.6 |
| | $ | 38.9 |
| | $ | 68.4 |
| |
| Total income tax (benefit) expense | | Total income tax (benefit) expense | | $ | (10) | | | $ | 26 | | | $ | 39 | |
Components of deferred income tax expense as of Dec. 31:
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2020 | | 2019 | | 2018 |
| Deferred tax expense excluding items below | | $ | 53 | | | $ | 53 | | | $ | 44 | |
| Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities | | (31) | | | (24) | | | (22) | |
| Deferred tax expense | | $ | 22 | | | $ | 29 | | | $ | 22 | |
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 |
| Deferred tax expense (benefit) excluding items below | | $ | 52.7 |
| | $ | 44.2 |
| | $ | (414.2 | ) |
| Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities | | (23.8 | ) | | (22.0 | ) | | 540.7 |
|
| Tax benefit (expense) allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other | | 0.1 |
| | (0.1 | ) | | — |
|
| Deferred tax expense | | $ | 29.0 |
| | $ | 22.1 |
| | $ | 126.5 |
|
Components of the net deferred tax liability as of Dec. 31:
| | | (Millions of Dollars) | | 2019 | | 2018 (a) | (Millions of Dollars) | | 2020 | | 2019 (a) |
| Deferred tax liabilities: | | | | | Deferred tax liabilities: | | | | |
| Differences between book and tax bases of property | | $ | 758.7 |
| | $ | 680.6 |
| Differences between book and tax bases of property | | $ | 838 | | | $ | 759 | |
| Operating lease assets | | 115.8 |
| | — |
| Operating lease assets | | 109 | | | 116 | |
| Regulatory assets | | 49.7 |
| | 49.2 |
| Regulatory assets | | 59 | | | 50 | |
| Pension expense | | 33.1 |
| | 32.3 |
| Pension expense | | 33 | | | 33 | |
| Other | | Other | | 2 | | | 0 | |
| Total deferred tax liabilities | | $ | 957.3 |
| | $ | 762.1 |
| Total deferred tax liabilities | | $ | 1,041 | | | $ | 958 | |
| | | | | | | | | |
| Deferred tax assets: | |
|
| |
|
| Deferred tax assets: | |
| Operating lease liabilities | | Operating lease liabilities | | $ | 109 | | | $ | 116 | |
| Regulatory liabilities | | $ | 111.2 |
| | $ | 116.8 |
| Regulatory liabilities | | 104 | | | 111 | |
| Operating lease liabilities | | 115.8 |
| | — |
| |
| Tax credit carryforward | | 29.5 |
| | 5.7 |
| Tax credit carryforward | | 83 | | | 30 | |
| Deferred fuel costs | | 18.3 |
| | 12.7 |
| Deferred fuel costs | | 9 | | | 18 | |
| Other employee benefits | | 5.8 |
| | 5.6 |
| Other employee benefits | | 7 | | | 6 | |
| NOL carryforward | | 0.1 |
| | 0.2 |
| |
| Other | | 4.8 |
| | 2.0 |
| Other | | 4 | | | 5 | |
| Total deferred tax assets | | 285.5 |
| | 143.0 |
| Total deferred tax assets | | 316 | | | 286 | |
| Net deferred tax liability | | $ | 671.8 |
| | $ | 619.1 |
| Net deferred tax liability | | $ | 725 | | | $ | 672 | |
(a) Prior periods have been reclassified to conform to current year presentation.
|
| |
| 8. Fair Value of Financial Assets and Liabilities |
Fair Value Measurements
The accountingAccounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires disclosures 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; andinputs.
•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:
Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAVs.net asset value.
Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.
Electric commodity derivatives held by SPS include transmission congestion instruments, generally referred to as FTRs, purchased from SPP. FTRs purchased from an 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 important 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 expected to be recovered through fuel and purchased energy cost recovery mechanisms, and therefore changes in the fair value of the yet to be settled portions of 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 SPS, the numerous unobservable quantitative inputs pertinent to the value of FTRs are immaterial to the financial statements of SPS.
Derivative Instruments Fair Value Measurements
SPS enters into derivative instruments, including forward contracts, for trading purposes and to manage risk in connection with changes in interest rates and electric utility commodity prices.
Interest Rate Derivatives — SPS may enter into various instruments that effectively fix the interest payments on certain floating rate debt obligations or 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. As of Dec. 31, 2019,2020, accumulated other comprehensive lossesloss related to interest rate derivatives included $0.1 millionimmaterial net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.
Wholesale and Commodity Trading Risk — SPS conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments, including derivatives. SPS 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 the activities governed by this policy.
Commodity Derivatives — SPS enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric utility operations. This could include the purchase or sale of energy or energy-related products and FTRs.
| | | | | | | | | | | | | | |
(Amounts in Millions) (a) | | Dec. 31, 2020 | | Dec. 31, 2019 |
| MWh of electricity | | 5 | | | 6 | |
Gross notional amounts(a)Amounts are not reflective of commodity FTRs at Dec. 31, 2019 and 2018: |
| | | | | | |
(Amounts in Millions) (a) | | Dec. 31, 2019 | | Dec. 31, 2018 |
| MWh of electricity | | 6.4 |
| | 5.5 |
|
| |
(a)net positions in the underlying commodities.
| Amounts are not reflective of net positions in the underlying commodities. |
Consideration of Credit Risk and Concentrations — SPS 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 balance sheets.
SPS’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. At Dec. 31, 2019, 32020, 2 of the 109 most significant counterparties for these activities, comprising $12.2$12 million or 35%36% of this credit exposure, had investment grade ratings from Standard & Poor’s,S&P, Moody’s or Fitch Ratings. NaN of the 109 most significant counterparties, comprising $22.1$22 million or 65%64% of this credit exposure, were not rated by external rating agencies, but based on SPS’ internal analysis, had credit quality consistent with investment grade. NaN of these significant counterparties, comprising $0.1 millionan immaterial amount or less than 1% of this credit exposure, had credit quality less than investment grade, based on internal analysis. NaN of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.
Qualifying Cash Flow HedgesImpact of Derivative Activities on Income and Accumulated Other Comprehensive Loss — Financial impact of qualifying interest rate cash flow hedges on SPS’ accumulated other comprehensive loss, included in the statements of common stockholder’s equity and in the statements of comprehensive income:
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 |
| Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 | | $ | (0.7 | ) | | $ | (0.8 | ) | | $ | (0.7 | ) |
| After-tax net realized losses on derivative transactions reclassified into earnings | | — |
| | 0.1 |
| | — |
|
Adoption of ASU. 2018-02 (a) | | — |
| | — |
| | (0.1 | ) |
| Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 | | $ | (0.7 | ) | | $ | (0.7 | ) | | $ | (0.8 | ) |
| |
(a)
| In 2017, SPS implemented ASU No. 2018-02 related to TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. |
Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were immaterial, $0.1 million and $0.1 million for the years ended Dec. 31, 2019, 2018 and 2017, respectively.
Changes in the fair value of FTRs resulting in a pre-tax net loss of $7 million in Dec. 31, 2020 and $7 million in pre-tax net gains of $6.5 million, $7.0 million and $0.5 million recognized for theboth years ended Dec. 31, 2019 2018 and 2017,2018, respectively, were reclassified as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on expected recovery of FTR settlements through fuel and purchased energy cost recovery mechanisms.
FTR settlement gains of $6.0 million, $4.4 million and $0.8 millionlosses were recognizedimmaterial for the year ended Dec. 31, 2020. For the years ended Dec. 31, 2019 and 2018, $6 million and 2017,$4 million, respectively, of settlement gains were recognized and were 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.
SPS had 0 derivative instruments designated as fair value hedges during the years ended Dec. 31, 2020, 2019 2018 and 2017.
Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Dec. 31, 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: | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric commodity | | $ | 0 | | | $ | 0 | | | $ | 7 | | | $ | 7 | | | $ | 0 | | | $ | 7 | | | $ | 0 | | | $ | 0 | | | $ | 12 | | | $ | 12 | | | $ | 0 | | | $ | 12 | |
| Total current derivative assets | | $ | 0 | | | $ | 0 | | | $ | 7 | | | $ | 7 | | | $ | 0 | | | 7 | | | $ | 0 | | | $ | 0 | | | $ | 12 | | | $ | 12 | | | $ | 0 | | | 12 | |
PPAs (b) | | | | | | | | | | | | 3 | | | | | | | | | | | | | 3 | |
| Current derivative instruments | | | | | | | | | | | | $ | 10 | | | | | | | | | | | | | $ | 15 | |
| Noncurrent derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
PPAs (b) | | | | | | | | | | | | $ | 9 | | | | | | | | | | | | | $ | 13 | |
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 9 | | | | | | | | | | | | | $ | 13 | |
| Current derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
PPAs (b) | | | | | | | | | | | | $ | 4 | | | | | | | | | | | | | $ | 4 | |
| Current derivative instruments | | | | | | | | | | | | $ | 4 | | | | | | | | | | | | | $ | 4 | |
| Noncurrent derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
PPAs (b) | | | | | | | | | | | | $ | 9 | | | | | | | | | | | | | $ | 13 | |
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 9 | | | | | | | | | | | | | $ | 13 | |
(a)SPS nets derivative instruments and related collateral on its balance sheets when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2020 and 2019. At Dec. 31, 2020 and 2019, derivative assets and 2018:liabilities include 0 obligations to return cash collateral, respectively. At Dec. 31, 2020 and 2019, derivative assets and liabilities include no rights to reclaim cash collateral, respectively. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2019 | | Dec. 31, 2018 |
| | | Fair Value | | | | | | | | Fair Value | | | | | | |
| (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Fair Value Total | |
Netting (a) | | Total | | Level 1 | | Level 2 | | Level 3 | | Fair Value Total | |
Netting (a) | | Total |
| Current derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric commodity | | $ | — |
| | $ | — |
| | $ | 11.8 |
| | $ | 11.8 |
| | $ | — |
| | $ | 11.8 |
| | $ | — |
| | $ | — |
| | $ | 14.9 |
| | $ | 14.9 |
| | $ | (0.2 | ) | | $ | 14.7 |
|
| Total current derivative assets | | $ | — |
| | $ | — |
| | $ | 11.8 |
| | $ | 11.8 |
| | $ | — |
| | 11.8 |
| | $ | — |
| | $ | — |
| | $ | 14.9 |
| | $ | 14.9 |
| | $ | (0.2 | ) | | 14.7 |
|
PPAs (b) | | | | | | | | | | | | 3.2 |
| | | | | | | | | | | | 3.1 |
|
| Current derivative instruments | | | | | | | | | | | | $ | 15.0 |
| | | | | | | | | | | | $ | 17.8 |
|
| Noncurrent derivative assets | | | | | | | | | | | | | | | | | | | | | | | | |
PPAs (b) | | | | | | | | | | | | 12.6 |
| | | | | | | | | | | | 15.8 |
|
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 12.6 |
| | | | | | | | | | | | $ | 15.8 |
|
| Current derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
| Other derivative instruments: | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric commodity | | $ | — |
| | $ | — |
| | $ | 0.1 |
| | $ | 0.1 |
| | $ | — |
| | $ | 0.1 |
| | $ | — |
| | $ | — |
| | $ | 0.2 |
| | $ | 0.2 |
| | $ | (0.2 | ) | | $ | — |
|
| Total current derivative liabilities | | $ | — |
| | $ | — |
| | $ | 0.1 |
| | $ | 0.1 |
| | $ | — |
| | 0.1 |
| | $ | — |
| | $ | — |
| | $ | 0.2 |
| | $ | 0.2 |
| | $ | (0.2 | ) | | — |
|
PPAs (b) | | | | | | | | | | | | 3.6 |
| | | | | | | | | | | | 3.6 |
|
| Current derivative instruments | | | | | | | | | | | | $ | 3.7 |
| | | | | | | | | | | | $ | 3.6 |
|
| Noncurrent derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
PPAs (b) | | | | | | | | | | | | 12.8 |
| | | | | | | | | | | | 16.4 |
|
| Noncurrent derivative instruments | | | | | | | | | | | | $ | 12.8 |
| | | | | | | | | | | | $ | 16.4 |
|
| |
(a)(b)During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
| SPS nets derivative instruments and related collateral in its 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 Dec. 31, 2019 and 2018. At both Dec. 31, 2019 and 2018, derivative assets and liabilities include 0 obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. |
| |
(b)
| During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. |
Changes in Level 3 commodity derivatives for the years ended Dec. 31, 2020, 2019 2018 and 2017:2018:
|
| | | | | | | | | | | | |
| | | Year Ended Dec. 31 |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 |
| Balance at Jan. 1 | | $ | 14.7 |
| | $ | 12.7 |
| | $ | 2.0 |
|
| Purchases | | 26.7 |
| | 32.3 |
| | 41.2 |
|
| Settlements | | (34.2 | ) | | (41.6 | ) | | (55.8 | ) |
| Net transactions recorded during the period: | |
|
| | | | |
| Net gains recognized as regulatory assets | | 4.5 |
| | 11.3 |
| | 25.3 |
|
| Balance at Dec. 31 | | $ | 11.7 |
| | $ | 14.7 |
| | $ | 12.7 |
|
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended Dec. 31 |
| (Millions of Dollars) | | 2020 | | 2019 | | 2018 |
| Balance at Jan. 1 | | $ | 12 | | | $ | 14 | | | $ | 13 | |
| Purchases | | 23 | | | 27 | | | 32 | |
| Settlements | | (23) | | | (34) | | | (42) | |
| Net transactions recorded during the period: | | | | | | |
| Net (losses) gains recognized as regulatory assets | | (5) | | | 5 | | | 11 | |
| Balance at Dec. 31 | | $ | 7 | | | $ | 12 | | | $ | 14 | |
SPS recognizes transfers between levels as of the beginning of each period. There were 0 transfers of amounts between levels for derivative instruments for 2017 – 2019.Dec. 31, 2020, 2019 and 2018.
Fair Value of Long-Term Debt
As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:
| | | | | 2019 | | 2018 | | 2020 | | 2019 |
| (Millions of Dollars) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | (Millions of Dollars) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| Long-term debt, including current portion | | $ | 2,419.7 |
| | $ | 2,706.1 |
| | $ | 2,126.1 |
| | $ | 2,139.8 |
| |
| Long-term debt | | Long-term debt | | $ | 2,764 | | | $ | 3,381 | | | $ | 2,420 | | | $ | 2,706 | |
Fair value of SPS’ 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 Dec. 31, 20192020 and 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 |
Pension and Postretirement Health Care Benefits
Xcel Energy, which includes SPS, has several noncontributory, qualified, defined benefit pension plans that cover almost all employees. Generally, benefits areAll newly hired or rehired employees participate under the Cash Balance formula, which is based on pay credits using a combinationpercentage of years of serviceannual eligible pay and annual interest credits. The average pay.annual interest crediting rates for these plans was 2.37, 3.12 and 3.75 percent in 2020, 2019, and 2018, respectively. Some employees may participate under legacy formulas such as the traditional final average pay or pension equity. Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs subject to the limitations of applicable employee benefit and tax laws.
In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The SERP is maintained for certain executives that were participantswho participated in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions funded by Xcel Energy’s consolidated operating cash flows. Obligations of the SERP and nonqualified plan as of Dec. 31, 2020 and 2019 and 2018 were $39$43 million and $33$39 million, respectively, of which $2 million was attributable to SPS in both years. In 20192020 and 2018,2019, Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $6 million and $4 million, in 2019 and 2018,respectively, of which immaterial amounts were attributable to SPS.
Xcel Energy, which includes SPS, bases the investment-return assumption on expected long-term performance for each of the asset classes in its pension and postretirement health care portfolios. For pension assets, Xcel Energy considers the historical returns achieved by its asset portfolio over the past 20 years or longer period, as well as long-term projected return levels. Xcel Energy and SPS continually review pension assumptions.
Pension cost determination assumes a forecasted mix of investment types over the long-term.
•Investment returns in 2020 were above the assumed level of 6.78%.
•Investment returns in 2019 were above the assumed level of 6.78%;.
•Investment returns in 2018 were below the assumed level of 6.78%;.
Investment returns in 2017 were above the assumed level of 6.78%; and
•In 2020, Xcel Energy’s2021, SPS’s expected investment-return assumption is 6.78%6.39%.
Pension plan and postretirement benefit assets are invested in a portfolio according to Xcel Energy’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by the assets in any year.
State agencies also have issued guidelines to the funding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for Texas and New Mexico amounts collected in rates. These assets are invested in a manner consistent with the investment strategy for the pension plan.
Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios.
Plan Assets
For each of the fair value hierarchy levels, SPS’ pension plan assets measured at fair value:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Dec. 31, 2020 (a) | | Dec. 31, 2019 (a) |
| (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total |
| Cash equivalents | | $ | 31 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 31 | | | $ | 19 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 19 | |
| Commingled funds | | 211 | | | 0 | | | 0 | | | 160 | | | 371 | | | 203 | | | 0 | | | 0 | | | 145 | | | 348 | |
| Debt securities | | 0 | | | 110 | | | 1 | | | 0 | | | 111 | | | 0 | | | 98 | | | 1 | | | 0 | | | 99 | |
| Equity securities | | 11 | | | 0 | | | 0 | | | 0 | | | 11 | | | 12 | | | 0 | | | 0 | | | 0 | | | 12 | |
| Other | | 2 | | | 1 | | | 0 | | | 0 | | | 3 | | | (17) | | | 0 | | | 0 | | | (3) | | | (20) | |
| Total | | $ | 255 | | | $ | 111 | | | $ | 1 | | | $ | 160 | | | $ | 527 | | | $ | 217 | | | $ | 98 | | | $ | 1 | | | $ | 142 | | | $ | 458 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2019 (a) | | Dec. 31, 2018 (a) |
| (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total |
| Cash equivalents | | $ | 18.9 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 18.9 |
| | $ | 21.6 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 21.6 |
|
| Commingled funds | | 202.5 |
| | — |
| | — |
| | 144.8 |
| | 347.3 |
| | 128.6 |
| | — |
| | — |
| | 132.5 |
| | 261.1 |
|
| Debt securities | | — |
| | 98.2 |
| | 0.6 |
| | — |
| | 98.8 |
| | — |
| | 98.1 |
| | — |
| | — |
| | 98.1 |
|
| Equity securities | | 12.1 |
| | — |
| | — |
| | — |
| | 12.1 |
| | 14.4 |
| | — |
| | — |
| | — |
| | 14.4 |
|
| Other | | (16.8 | ) | | 0.7 |
| | — |
| | (2.8 | ) | | (18.9 | ) | | 0.2 |
| | 0.8 |
| | — |
| | (4.0 | ) | | (3.0 | ) |
| Total | | $ | 216.7 |
| | $ | 98.9 |
| | $ | 0.6 |
| | $ | 142.0 |
| | $ | 458.2 |
| | $ | 164.8 |
| | $ | 98.9 |
| | $ | — |
| | $ | 128.5 |
| | $ | 392.2 |
|
| |
(a)
| See Note 8 for further information on fair value measurement inputs and methods. |
For each of the fair value hierarchy levels, SPS’ proportionate allocation of the total postretirement benefit plan assets that were measured at fair value:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Dec. 31, 2020 (a) | | Dec. 31, 2019 (a) |
| (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total |
| Cash equivalents | | $ | 3 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 3 | | | $ | 2 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 2 | |
| Insurance contracts | | 0 | | | 5 | | | 0 | | | 0 | | | 5 | | | 0 | | | 5 | | | 0 | | | 0 | | | 5 | |
| Commingled funds | | 7 | | | 0 | | | 0 | | | 7 | | | 14 | | | 7 | | | 0 | | | 0 | | | 8 | | | 15 | |
| Debt securities | | 0 | | | 22 | | | 0 | | | 0 | | | 22 | | | 0 | | | 22 | | | 0 | | | 0 | | | 22 | |
| | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 10 | | | $ | 27 | | | $ | 0 | | | $ | 7 | | | $ | 44 | | | $ | 9 | | | $ | 27 | | | $ | 0 | | | $ | 8 | | | $ | 44 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Dec. 31, 2019 (a) | | Dec. 31, 2018 (a) |
| (Millions of Dollars) | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total | | Level 1 | | Level 2 | | Level 3 | | Measured at NAV | | Total |
| Cash equivalents | | $ | 2.2 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2.2 |
| | $ | 1.8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1.8 |
|
| Insurance contracts | | — |
| | 4.9 |
| | — |
| | — |
| | 4.9 |
| | — |
| | 4.3 |
| | — |
| | — |
| | 4.3 |
|
| Commingled funds: | | 6.7 |
| | — |
| | — |
| | 7.4 |
| | 14.1 |
| | 12.8 |
| | — |
| | — |
| | 3.8 |
| | 16.6 |
|
| Debt securities: | | — |
| | 22.1 |
| | 0.1 |
| | — |
| | 22.2 |
| | — |
| | 17.2 |
| | — |
| | — |
| | 17.2 |
|
| Equity securities: | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other | | — |
| | 0.2 |
| | — |
| | — |
| | 0.2 |
| | — |
| | 0.1 |
| | — |
| | — |
| | 0.1 |
|
| Total | | $ | 8.9 |
| | $ | 27.2 |
| | $ | 0.1 |
| | $ | 7.4 |
| | $ | 43.6 |
| | $ | 14.6 |
| | $ | 21.6 |
| | $ | — |
| | $ | 3.8 |
| | $ | 40.0 |
|
| |
(a)
| See Note 8 for further information on fair value measurement inputs and methods. |
No assets were transferred in or out of Level 3 for 2020. Immaterial assets were transferred in or out of Level 3 for 2019. No assets were transferred in or out
Funded Status — Benefit obligations for both pension and postretirement plans increased from Dec. 31, 2019 to Dec. 31, 2020, due primarily to decreases in discount rates used in actuarial valuations. Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for Xcel EnergySPS are presentedas follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| (Millions of Dollars) | | 2020 | | 2019 | | 2020 | | 2019 |
| Change in Benefit Obligation: | | | | | | | | |
| Obligation at Jan. 1 | | $ | 519 | | | $ | 478 | | | $ | 44 | | | $ | 42 | |
| Service cost | | 10 | | | 9 | | | 1 | | | 1 | |
| Interest cost | | 18 | | | 20 | | | 1 | | | 2 | |
| Plan amendments | | 0 | | | 0 | | | 0 | | | 0 | |
| Actuarial loss (gain) | | 45 | | | 44 | | | (5) | | | 0 | |
| Plan participants’ contributions | | 0 | | | 0 | | | 1 | | | 1 | |
Benefit payments (a) | | (30) | | | (32) | | | (4) | | | (2) | |
| Obligation at Dec. 31 | | $ | 562 | | | $ | 519 | | | $ | 38 | | | $ | 44 | |
| Change in Fair Value of Plan Assets: | | | | | | | | |
| Fair value of plan assets at Jan. 1 | | $ | 458 | | | $ | 392 | | | $ | 44 | | | $ | 40 | |
| Actual return on plan assets | | 84 | | | 80 | | | 3 | | | 5 | |
| Employer contributions | | 15 | | | 18 | | | 0 | | | 0 | |
| Plan participants’ contributions | | 0 | | | 0 | | | 1 | | | 1 | |
| Benefit payments | | (30) | | | (32) | | | (4) | | | (2) | |
| Fair value of plan assets at Dec. 31 | | $ | 527 | | | $ | 458 | | | $ | 44 | | | $ | 44 | |
| Funded status of plans at Dec. 31 | | $ | (35) | | | $ | (61) | | | $ | 6 | | | $ | 0 | |
| Amounts recognized in the Balance Sheet at Dec. 31: | | | | | | | | |
| Noncurrent assets | | 0 | | | 0 | | | 6 | | | 0 | |
| Noncurrent liabilities | | (35) | | | (61) | | | 0 | | | 0 | |
| Net amounts recognized | | $ | (35) | | | $ | (61) | | | $ | 6 | | | $ | 0 | |
(a)Includes approximately $7 million in 2019, of lump-sum benefit payments used in the following table:determination of a settlement charge.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| Significant Assumptions Used to Measure Benefit Obligations: | | 2020 | | 2019 | | 2020 | | 2019 |
| Discount rate for year-end valuation | | 2.71 | % | | 3.49 | % | | 2.65 | % | | 3.47 | % |
| Expected average long-term increase in compensation level | | 3.75 | % | | 3.75 | % | | N/A | | N/A |
| Mortality table | | Pri-2012 | | Pri-2012 | | Pri-2012 | | Pri-2012 |
| Health care costs trend rate — initial: Pre-65 | | N/A | | N/A | | 5.50 | % | | 6.00 | % |
| Health care costs trend rate — initial: Post-65 | | N/A | | N/A | | 5.00 | % | | 5.10 | % |
| Ultimate trend assumption — initial: Pre-65 | | N/A | | N/A | | 4.50 | % | | 4.50 | % |
| Ultimate trend assumption — initial: Post-65 | | N/A | | N/A | | 4.50 | % | | 4.50 | % |
| Years until ultimate trend is reached | | N/A | | N/A | | 5 | | 3 |
|
| | | | | | | | | | | | | | | | |
| | | Pension Benefits | | Postretirement Benefits |
| (Millions of Dollars) | | 2019 | | 2018 | | 2019 | | 2018 |
| Change in Benefit Obligation: | | | | | | | | |
| Obligation at Jan. 1 | | $ | 477.8 |
| | $ | 515.9 |
| | $ | 41.8 |
| | $ | 47.0 |
|
| Service cost | | 8.8 |
| | 9.7 |
| | 0.9 |
| | 1.1 |
|
| Interest cost | | 20.1 |
| | 18.4 |
| | 1.7 |
| | 1.6 |
|
| Plan amendments | | — |
| | — |
| | — |
| | — |
|
| Actuarial loss (gain) | | 44.2 |
| | (34.8 | ) | | 0.4 |
| | (5.1 | ) |
| Plan participants’ contributions | | — |
| | — |
| | 0.6 |
| | 0.6 |
|
Benefit payments (a) | | (32.1 | ) | | (31.4 | ) | | (2.2 | ) | | (3.4 | ) |
| Obligation at Dec. 31 | | $ | 518.8 |
| | $ | 477.8 |
| | $ | 43.2 |
| | $ | 41.8 |
|
| Change in Fair Value of Plan Assets: | | | | | | | | |
| Fair value of plan assets at Jan. 1 | | $ | 392.2 |
| | $ | 433.2 |
| | $ | 40.0 |
| | $ | 44.1 |
|
| Actual return on plan assets | | 80.2 |
| | (17.6 | ) | | 5.1 |
| | (1.3 | ) |
| Employer contributions | | 17.9 |
| | 8.0 |
| | 0.1 |
| | — |
|
| Plan participants’ contributions | | — |
| | — |
| | 0.6 |
| | 0.6 |
|
| Benefit payments | | (32.1 | ) | | (31.4 | ) | | (2.2 | ) | | (3.4 | ) |
| Fair value of plan assets at Dec. 31 | | $ | 458.2 |
| | $ | 392.2 |
| | $ | 43.6 |
| | $ | 40.0 |
|
| Funded status of plans at Dec. 31 | | $ | (60.6 | ) | | $ | (85.6 | ) | | $ | 0.4 |
| | $ | (1.8 | ) |
| Amounts recognized in the Balance Sheet at Dec. 31: | | | | | | | | |
| Noncurrent assets | | — |
| | — |
| | 0.4 |
| | — |
|
| Noncurrent liabilities | | (60.6 | ) | | (85.6 | ) | | — |
| | (1.8 | ) |
| Net amounts recognized | | $ | (60.6 | ) | | $ | (85.6 | ) | | $ | 0.4 |
| | $ | (1.8 | ) |
| Significant Assumptions Used to Measure Benefit Obligations: | | | | | | | | |
| Discount rate for year-end valuation | | 3.49 | % | | 4.31 | % | | 3.47 | % | | 4.32 | % |
| Expected average long-term increase in compensation level | | 3.75 |
| | 3.75 |
| | N/A |
| | N/A |
|
| Mortality table | | Pri-2012 |
| | RP-2014 |
| | Pri-2012 |
| | RP-2014 |
|
Health care costs trend rate — initial: Pre-65 | | N/A |
| | N/A |
| | 6.00 | % | | 6.50 | % |
Health care costs trend rate — initial: Post-65 | | N/A |
| | N/A |
| | 5.10 | % | | 5.30 | % |
Ultimate trend assumption — initial: Pre-65 | | N/A |
| | N/A |
| | 4.50 | % | | 4.50 | % |
Ultimate trend assumption — initial: Post-65 | | N/A |
| | N/A |
| | 4.50 | % | | 4.50 | % |
| Years until ultimate trend is reached | | N/A |
| | N/A |
| | 3 |
| | 4 |
|
| |
(a)
| Includes approximately $6.8 million in 2019 and $6.9 million in 2018, of lump-sum benefit payments used in the determination of a settlement charge. |
Accumulated benefit obligation for the pension plan was $481.1$519 million and $445.8$481 million as of Dec. 31, 20192020 and 2018,2019, respectively.
Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit), other than the service cost component, is included in other income in the statementstatements of income.
Components of net periodic benefit cost (credit) and the amounts recognized in other comprehensive income and regulatory assets and liabilities are liabilities:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| (Millions of Dollars) | | 2020 | | 2019 | | 2018 | | 2020 | | 2019 | | 2018 |
| Service cost | | $ | 10 | | | $ | 9 | | | $ | 10 | | | $ | 1 | | | $ | 1 | | | $ | 1 | |
| Interest cost | | 18 | | | 20 | | | 18 | | | 1 | | | 2 | | | 2 | |
| Expected return on plan assets | | (29) | | | (28) | | | (28) | | | (2) | | | (2) | | | (3) | |
| Amortization of prior service credit | | 0 | | | 0 | | | 0 | | | 0 | | | (1) | | | 0 | |
| Amortization of net loss | | 12 | | | 11 | | | 14 | | | 0 | | | 0 | | | 0 | |
Settlement charge (a) | | 0 | | | 2 | | | 3 | | | 0 | | | 0 | | | 0 | |
| Net periodic pension cost | | 11 | | | 14 | | | 17 | | | 0 | | | 0 | | | 0 | |
| Effects of regulation | | 2 | | | 1 | | | (2) | | | 0 | | | 0 | | | 0 | |
| Net benefit cost recognized for financial reporting | | $ | 13 | | | $ | 15 | | | $ | 15 | | | $ | 0 | | | $ | 0 | | | $ | 0 | |
| Significant Assumptions Used to Measure Costs: | | | | | | | | | | | | |
| Discount rate | | 3.49 | % | | 4.31 | % | | 3.63 | % | | 3.47 | % | | 4.32 | % | | 3.62 | % |
| Expected average long-term increase in compensation level | | 3.75 | | | 3.75 | | | 3.75 | | | 0 | | | 0 | | | 0 | |
| Expected average long-term rate of return on assets | | 6.78 | | | 6.78 | | | 6.78 | | | 4.50 | | | 5.30 | | | 5.80 | |
(a)A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2019 and 2018, as follows:a result of lump-sum distributions during each plan year, SPS recorded a total pension settlement charge of $2 million and $3 million, respectively. A total of $1 million of that amount was recorded in the income statement in 2019 and 2018, respectively. There were no settlement charges recorded to the qualified pension plans in 2020.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| (Millions of Dollars) | | 2020 | | 2019 | | 2020 | | 2019 |
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | | | | | | | | |
| Net loss | | $ | 186 | | | $ | 210 | | | $ | (18) | | | $ | (12) | |
| Prior service credit | | (1) | | | (1) | | | (1) | | | (1) | |
| Total | | $ | 185 | | | $ | 209 | | | $ | (19) | | | $ | (13) | |
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: | | | | | | | | |
| Current regulatory assets | | $ | 11 | | | $ | 11 | | | $ | 0 | | | $ | 0 | |
| Noncurrent regulatory assets | | 174 | | | 198 | | | 0 | | | 0 | |
| Current regulatory liabilities | | 0 | | | 0 | | | (1) | | | (1) | |
| Noncurrent regulatory liabilities | | 0 | | | 0 | | | (18) | | | (12) | |
| Total | | $ | 185 | | | $ | 209 | | | $ | (19) | | | $ | (13) | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Pension Benefits | | Postretirement Benefits |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 | | 2019 | | 2018 | | 2017 |
| Service cost | | $ | 8.8 |
| | $ | 9.7 |
| | $ | 9.8 |
| | $ | 0.9 |
| | $ | 1.1 |
| | $ | 0.9 |
|
| Interest cost | | 20.1 |
| | 18.4 |
| | 19.7 |
| | 1.7 |
| | 1.6 |
| | 1.7 |
|
| Expected return on plan assets | | (28.6 | ) | | (28.3 | ) | | (27.9 | ) | | (2.0 | ) | | (2.5 | ) | | (2.4 | ) |
| Amortization of prior service credit | | (0.1 | ) | | (0.1 | ) | | — |
| | (0.5 | ) | | (0.4 | ) | | (0.4 | ) |
| Amortization of net loss | | 11.3 |
| | 14.1 |
| | 13.0 |
| | (0.4 | ) | | (0.4 | ) | | (0.6 | ) |
Settlement charge (a) | | 2.4 |
| | 3.2 |
| | — |
| | — |
| | — |
| | — |
|
| Net periodic pension cost (credit) | | 13.9 |
| | 17.0 |
| | 14.6 |
| | (0.3 | ) | | (0.6 | ) | | (0.8 | ) |
| Costs not recognized due to effects of regulation | | 0.9 |
| | (2.2 | ) | | 0.3 |
| | — |
| | — |
| | — |
|
| Net benefit cost (credit) recognized for financial reporting | | $ | 14.8 |
| | $ | 14.8 |
| | $ | 14.9 |
| | $ | (0.3 | ) | | $ | (0.6 | ) | | $ | (0.8 | ) |
| Significant Assumptions Used to Measure Costs: | | | | | | | | | | | | |
| Discount rate | | 4.31 | % | | 3.63 | % | | 4.13 | % | | 4.32 | % | | 3.62 | % | | 4.13 | % |
| Expected average long-term increase in compensation level | | 3.75 |
| | 3.75 |
| | 3.75 |
| | — |
| | — |
| | — |
|
| Expected average long-term rate of return on assets | | 6.78 |
| | 6.78 |
| | 6.78 |
| | 5.30 |
| | 5.80 |
| | 5.80 |
|
| |
(a)
| A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2019 and 2018, as a result of lump-sum distributions during the 2019 and 2018 plan years, SPS recorded a total pension settlement charge of $2.4 million and $3.2 million in 2019 and 2018, respectively. A total of $0.6 million and $0.7 million of that amount was recorded in the income statement in 2019 and 2018, respectively. |
|
| | | | | | | | | | | | | | | | |
| | | Pension Benefits | | Postretirement Benefits |
| (Millions of Dollars) | | 2019 | | 2018 | | 2019 | | 2018 |
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | | | | | | | | |
| Net loss | | $ | 209.7 |
| | $ | 230.9 |
| | $ | (11.9 | ) | | $ | (9.6 | ) |
| Prior service credit | | (1.1 | ) | | (1.2 | ) | | (1.4 | ) | | (1.8 | ) |
| Total | | $ | 208.6 |
| | $ | 229.7 |
| | $ | (13.3 | ) | | $ | (11.4 | ) |
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: | | | | | | | | |
| Current regulatory assets | | $ | 11.0 |
| | $ | 12.9 |
| | $ | — |
| | $ | — |
|
| Noncurrent regulatory assets | | 197.6 |
| | 216.8 |
| | — |
| | — |
|
| Current regulatory liabilities | | — |
| | — |
| | (0.8 | ) | | (0.9 | ) |
| Noncurrent regulatory liabilities | | — |
| | — |
| | (12.5 | ) | | (10.5 | ) |
| Total | | $ | 208.6 |
| | $ | 229.7 |
| | $ | (13.3 | ) | | $ | (11.4 | ) |
|
| | | | | | | | | | | | | | | | | | | | | |
| Measurement date | | Dec. 31, 2020 | | Dec. 31, 2019 | | Dec. 31, 20182020 | | Dec. 31, 2019 | | Dec. 31, 2018 |
Cash Flows— Cash fundingFunding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. Required contributions were made in 2017 - 20202018 — 2021 to meet minimum funding requirements.
Total voluntary and required pension funding contributions across all 4 of Xcel Energy’s pension plans were as follows:
•$125 million in January 2021, of which $14 million was attributable to SPS.
•$150 million in January 2020, of which $14 million was attributable to SPS;SPS.
•$154 million in 2019, of which $18 million was attributable to SPS;SPS.
•$150 million in 2018, of which $8 million was attributable to SPS; and
$162 million in 2017, of which $24 million was attributable to SPS.
For future years, Xcel Energy and SPS anticipate contributions will be made as necessary.
The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Xcel Energy’s voluntary postretirement funding contributions were as follows:
Expects to contribute approximately $10•$10 million during 2020;2021.
•$11 million during 2020.
•$15 million during 2019;2019.
•$11 million during 2018;2018.
$20 million during 2017; and
•Amounts attributable to SPS were immaterial.
Target asset allocations:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits | | Postretirement Benefits |
| | 2020 | | 2019 | | 2020 | | 2019 |
| Domestic and international equity securities | | 35 | % | | 37 | % | | 15 | % | | 15 | % |
| Long-duration fixed income securities | | 35 | | | 30 | | | 0 | | | 0 | |
| Short-to-intermediate fixed income securities | | 13 | | | 14 | | | 72 | | | 72 | |
| Alternative investments | | 15 | | | 17 | | | 9 | | | 9 | |
| Cash | | 2 | | | 2 | | | 4 | | | 4 | |
| Total | | 100 | % | | 100 | % | | 100 | % | | 100 | % |
|
| | | | | | | | | | | | |
| | | Pension Benefits | | Postretirement Benefits |
| | | 2019 | | 2018 | | 2019 | | 2018 |
| Domestic and international equity securities | | 37 | % | | 35 | % | | 15 | % | | 18 | % |
| Long-duration fixed income securities | | 30 |
| | 32 |
| | — |
| | — |
|
| Short-to-intermediate fixed income securities | | 14 |
| | 16 |
| | 72 |
| | 70 |
|
| Alternative investments | | 17 |
| | 15 |
| | 9 |
| | 8 |
|
| Cash | | 2 |
| | 2 |
| | 4 |
| | 4 |
|
| Total | | 100 | % | | 100 | % | | 100 | % | | 100 | % |
Plan Amendments — Xcel Energy, which includes SPS, amended the Xcel Energy Inc. Nonbargaining Pension Plan (South) in 2017 to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans.
In 2020, 2019, and 2018, there were no significant plan amendments made which affected the benefit obligation.
Projected Benefit Payments
SPS’ projected benefit payments:
|
| | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Projected
Pension Benefit
Payments | | Gross Projected
Postretirement
Health Care
Benefit Payments | | Expected
Medicare Part D
Subsidies | | Net Projected
Postretirement
Health Care
Benefit Payments |
| 2020 | | $ | 30.7 |
| | $ | 2.9 |
| | $ | — |
| | $ | 2.9 |
|
| 2021 | | 29.4 |
| | 2.9 |
| | — |
| | 2.9 |
|
| 2022 | | 30.3 |
| | 2.9 |
| | — |
| | 2.9 |
|
| 2023 | | 30.4 |
| | 2.9 |
| | — |
| | 2.9 |
|
| 2024 | | 30.4 |
| | 2.8 |
| | — |
| | 2.8 |
|
| 2025-2029 | | 153.5 |
| | 13.2 |
| | 0.1 |
| | 13.1 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Projected
Pension Benefit
Payments | | Gross Projected
Postretirement
Health Care
Benefit Payments | | Expected
Medicare Part D
Subsidies | | Net Projected
Postretirement
Health Care
Benefit Payments |
| 2021 | | $ | 32 | | | $ | 3 | | | $ | 0 | | | $ | 3 | |
| 2022 | | 31 | | | 3 | | | 0 | | | 3 | |
| 2023 | | 31 | | | 3 | | | 0 | | | 3 | |
| 2024 | | 31 | | | 3 | | | 0 | | | 3 | |
| 2025 | | 31 | | | 3 | | | 0 | | | 3 | |
| 2026-2030 | | 152 | | | 12 | | | 0 | | | 12 | |
Defined Contribution Plans
Xcel Energy, which includes SPS, maintains 401(k) and other defined contribution plans that cover most employees. The expense to these plans for SPS was approximately $3 million in 2020, 2019 2018 and 2017.2018.
|
| |
| 10. Commitments and Contingencies |
Legal
SPS is involved in various litigation matters that are being defended and handled 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 that are probable of being incurred and subject to reasonable estimation.
Management may beis 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.
In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
For current proceedings not specifically reported, herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on SPS’ financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.
Rate Matters
Texas Fuel Reconciliation—In December 2018,SPS filed an application with the PUCT for reconciliation of fuel costs for the period Jan. 1, 2016, through June 30, 2018, to determine whether all fuel costs incurred were eligible for recovery. In December 2019, the PUCT issued an order disallowing recovery of costs for Texas customers related to two specific solar PPAs. These PPAs were previously approved by the NMPRC as reasonable, necessary and economic. SPS recorded a total disallowance of approximately $6 million in December 2019.
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 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 previously unbilled charges was remanded to the FERC. In February 2019, the FERC reversed its 2016 decision and ordered SPP to refund charges retroactively collected from its transmission customers, including SPS, related to periods before September 2015. In April 2019, several parties, includingMarch 2020, SPP and Oklahoma Gas & Electric separately filed requestspetitions for rehearing. Timingreview of a FERC response to rehearing requests is uncertain.the FERC’s orders at the 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 SPP assessed upgrade charges to SPS in violation of the SPP OATT. In March 2018, the FERC issued an order denying the SPS complaint. SPS filed a request for rehearing in April 2018. The FERC grantedissued a tolling order granting a rehearing for further consideration in May 2018. 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 amountsamount through future SPS customer rates. In October 2020, SPS filed a petition for review of the FERC’s March 2018 order and May 2018 tolling order at the D.C. Circuit. This appeal is stayed pending the outcome of the separate appeal initiated in 2020 by Oklahoma Gas & Electric and SPP.
SPP Filing to Assign GridLiance Facilities to SPS Rate Zone — In August 2018, SPP filed a request with the FERC to amend its OATT to include costs of the GridLiance High Plains, LLC. facilities in the SPS rate zone. In a previous filing, the FERC determined that some of these facilities did not qualify as transmission facilities under the SPP OATT. SPP’s proposed tariff changes resulted in an increase in the annual transmission revenue requirement of $10 million per year, with $6 million allocated to SPS’ retail customers. The remaining $4 million would be paid by other wholesale loads in the SPS rate zone. On March 16, 2020, GridLiance also filed additional rate increases for 2020 which would raise their annual revenue requirement to $14 million, with approximately $9 million allocated to SPS’ retail customers. The hearing portion of this proceeding was concluded on Sept. 11, 2020.
In September 2018, SPS protestedThe initial post-hearing brief was filed on Oct. 27, 2020 and the proposed SPP tariff charges,ALJ’s decision on this case is expected on May 3, 2021. The FERC will then rule on the judge’s decision and asked the FERC to reject the SPP filing. On Oct. 31, 2018, the FERC issued aneither sustain it, overturn it, or order accepting the proposed charges, subject to refund, as of Nov. 1, 2018, and set the case for settlement hearing procedures. Hearings are scheduled for May 2020, with the ALJs’ initial decision expected in October 2020.further proceedings. SPS has incurred approximately $6$15 million in associated charges as of Dec. 31, 2019.
SPS Filing to Modify Wholesale Transmission Rates —2020. In 2018, SPS filed revisions to its wholesale transmission formula rate. The proposal includes an update to depreciation rates for transmission plant. The new formula rate would also provide a credit to customers of “excess” ADIT resulting from the TCJA and recover certain wholesale regulatory commission expenses.
Proposed changes would increase wholesale transmission revenues by approximately$9.4 million, with approximately $4.4 million of the total recovered in SPP regional transmission rates. SPS proposed formula rate changes be effective Feb. 1, 2019.
In January 2019, theAugust 2020, FERC issued an order acceptingon a question certified by the proposed rate changes ashearing judge for the FERC’s review, in which FERC made certain findings in SPS’ favor regarding the legal standard that applies to the ongoing hearing proceeding. In November 2020, FERC denied GridLiance’s request for rehearing of Feb. 1, 2019, subjectthis August 2020 order. In December 2020, GridLiance filed a petition for review at the D.C. Circuit of the August 2020 and November 2020 orders on the certified question.
Wind Operating Commitments — PUCT and NMPRC orders related to the Hale and Sagamore wind projects included certain operating and savings minimums. In general, annual generation must exceed a net capacity factor of 48%. If annual generation is below the guaranteed level, SPS would be obligated to refund an amount equal to foregone PTCs and settlement procedures. Onfuel savings. Additionally, retail customer savings must exceed project costs included in base rates over the first ten years of operations. SPS would be required to refund excess costs, if any, after ten years of operations. As of Dec. 23, 2019,31, 2020, SPS fileddoes not expect refunds to be probable under either of these commitments.
Contract Termination — SPS and Lubbock Power & Light are parties to a Stipulation25-year, 170 MW partial requirements contract. In October 2020, Lubbock Power & Light initiated discussions with SPS concerning the interpretation of contractual terms related to early termination and Agreementdefault. If the parties are unable to reach resolution, the contract calls for the matter to proceed to arbitration. The amount of Settlement. If approved by the FERC, the settlement would implement the requested depreciationany damages depends on multiple factors and TCJA related changes, but would not modify current treatment of wholesale regulatory commission expenses.is currently unknown.
Environmental
New and changing federal and state environmental mandates can create financial liabilities for SPS, which are normally recovered through the regulated rate process.
Site Remediation —
Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. SPS may sometimes pay all or a portion of the cost to remediate sites where past activities of SPS’ predecessors or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which SPS is alleged to have sent wastes to that site.
MGP, Landfill orand Disposal Sites—
SPS is currently remediating the site of a former facility.disposal site. SPS 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 costs incurred.
Environmental Requirements — Water and Waste
Federal CWA WOTUS Rule — In 2015,April 2020, the EPA and U.S. Army Corps published a finalof Engineers (“Agencies”) replaced the 2015 WOTUS rule that significantly broadenedand narrowed the scopedefinition of waters underWOTUS (“2020 WOTUS Rule”). The new definition simplifies the CWA thatprocess whether waters are subject to federalCWA jurisdiction referred to as “WOTUS”. In 2019,and streamlines the EPA repealed the 2015 rule and published a draft replacement rule. Until a final rule is issued,permitting process. SPS cannot estimate potential impacts, but anticipatesdoes not anticipate that compliance costs will be recoverable through regulatory mechanisms.material.
Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power plants that discharge treated effluent to surface waters as well as utility-owned landfills that receive CCRs.coal combustion residuals. In 2017,October 2020, the EPA delayedpublished a final rule revising the compliance date for flue gas desulfurization wastewater and bottom ash transport until November 2020. After 2020,regulations. SPS estimatesanticipates that ELG compliance costs will not be immaterial. The EPA, however, is conducting a rulemaking process to revise certain effluent limitationsmaterial and pretreatment standards, which may impact compliance costs. SPS anticipates these costs will be fully recoverable through regulatory mechanisms.
Environmental Requirements — Air
Regional Haze Rules — The regional haze program requires SO2, nitrogen oxide and particulate matter emission controls at power plants to reduce visibility impairment in national parks and wilderness areas. The program includes BART and reasonable further progress. Texas’ first regional haze plan has undergone federal review as described below.review.
All states are now subject to a second round of regional haze planning/rulemaking, focusing on additional reductions to meet reasonable progress requirements. Any additional impacts to SPS facilities are expected to be minimal.
BART Determination for Texas: The EPA has issued a revised final rule adopting a BART alternative Texas only SO2 trading program that applies to all Harrington and Tolk units. Under the trading program, SPS expects the allowance allocations to be sufficient for SO2 emissions. The anticipated costs of compliance are not expected to have a material impact; and SPS believes that compliance costs would be recoverable through regulatory mechanisms.
Several parties have challenged whether the final rule issued by the EPA should be considered to have met the requirements imposed in a Consent Decree entered by the United States District Court for the District of Columbia that established deadlines for the EPA to take final action on state regional haze plan submissions. The court has required status reports from the parties while the EPA works on the reconsideration rulemaking.
In December 2017, the National Parks Conservation Association, Sierra Club, and Environmental Defense Fund appealed the EPA’s 2017 final BART rule to the Fifth Circuit and filed a petition for administrative reconsideration. In January 2018, the court granted SPS’ motion to intervene in the Fifth Circuit litigation in support of the EPA’s final rule. The court has held the litigation in abeyance while the EPA decided whether to reconsider the rule. In August 2018, the EPA started a reconsideration rulemaking, which was supplemented by an additional agency noticerulemaking. The EPA reaffirmed the rule in November 2019. ItAugust 2020 with minor changes.
The 2020 EPA Action has been challenged. All pending actions could be consolidated, and may proceed in the Fifth Circuit or the D.C. Circuit, where a parallel challenge has been filed. The timing of final decisions is not known when the EPA will make a final decision on this proposal.unclear.
Reasonable Progress Rule: In 2016, the EPA adopted a final rule establishing a federal implementation plan for reasonable further progress under the regional haze program for the state of Texas. The rule imposes SO2 emission limitations that would require the installation of dry scrubbers on Tolk Units 1 and 2, with compliance required by February 2021. Investment costs associated with dry scrubbers could be $600 million. SPS appealed the EPA’s decision and obtained a stay of the final rule.
In March 2017, the Fifth Circuit remanded the rule to the EPA for reconsideration, leaving the stay in effect. In a future rulemaking, the EPA will address whether SO2 emission reductions beyond those required in the BART alternative rule are needed at Tolk under the “reasonable progress” requirements. TheAs states are now proceeding with the second regional haze planning period, the EPA hasmay choose not announced a schedule for actingto act on the remanded rule.
Implementation of the NAAQS for SO2 — The EPA has designated all areas near SPS’ generating plants as attaining the SO2 NAAQS with an exception. The EPA issued final designations, which found the area near the Harrington plant as “unclassifiable.” The area near the Harrington plant iswas monitored for the three years ending in 2019 and the monitoring showed the area to be monitoredexceeding the standard.
To address this issue, SPS negotiated an order with the TCEQ providing for three yearsthe end of coal combustion and a final designation is expected to be made by December 2020.
If the area nearconversion of the Harrington plant is designated nonattainment in 2020, the TCEQ will need to develop an implementation plan, designed to achieve the NAAQSa natural gas fueled facility by Jan. 1, 2025. The TCEQ could require additional SO2 controls at Harrington as part of such a plan. SPS cannot evaluate the impacts until the final designation is made and any required state plans are developed.
SPS believes that should SO2 control systems be required for a plant, compliance costs or the costs of alternative cost-effective generation will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial condition or cash flows.
AROs — AROs have been recorded for SPS’ assets.
SPS’ AROs were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2020 |
(Millions of
Dollars) | | Jan. 1, 2020 | | Amounts Incurred (a) | | Amounts Settled (b) | | Accretion | | Dec. 31, 2020 (c) |
| Electric | | | | | | | | | | |
| Steam and other production | | $ | 51 | | | $ | 0 | | | $ | (2) | | | $ | 3 | | | $ | 52 | |
| Wind | | 16 | | | 33 | | | 0 | | | 1 | | | 50 | |
| Distribution | | 10 | | | 0 | | | 0 | | | 0 | | | 10 | |
| Total liability | | $ | 77 | | | $ | 33 | | | $ | (2) | | | $ | 4 | | | $ | 112 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2019 |
(Millions of Dollars) | | Jan. 1, 2019 | | Amounts Incurred (a) | | Amounts
Settled (b) | | Accretion | | Cash Flow Revisions (c) | | Dec. 31, 2019 |
| Electric | | | | | | | | | | | | |
| Steam and other production | | $ | 22.0 |
| | $ | — |
| | $ | (1.6 | ) | | $ | 1.4 |
| | $ | 29.5 |
| | $ | 51.3 |
|
| Wind | | — |
| | 16.0 |
| | — |
| | 0.4 |
| | — |
| | 16.4 |
|
| Distribution | | 9.1 |
| | — |
| | — |
| | 0.4 |
| | — |
| | 9.5 |
|
| Miscellaneous | | 1.3 |
| | — |
| | — |
| | — |
| | (1.2 | ) | | 0.1 |
|
| Total liability | | $ | 32.4 |
| | $ | 16.0 |
| | $ | (1.6 | ) | | $ | 2.2 |
| | $ | 28.3 |
| | $ | 77.3 |
|
| |
(a)(b)Amounts settled related mainly to asbestos abatement projects. (c)No AROs were revised in 2020. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2019 | (Millions of
Dollars) | | Jan. 1, 2019 | | Amounts Incurred (a) | | Amounts Settled (b) | | Accretion | | Cash Flow Revisions (c) | | Dec. 31, 2019 | | Electric | | | | | | | | | | | | | | Steam and other production | | $ | 22 | | | $ | 0 | | | $ | (2) | | | $ | 1 | | | $ | 30 | | | $ | 51 | | | Wind | | 0 | | | 16 | | | 0 | | | 0 | | | 0 | | | 16 | | | Distribution | | 9 | | | 0 | | | 0 | | | 1 | | | 0 | | | 10 | | | Miscellaneous | | 1 | | | 0 | | | 0 | | | 0 | | | (1) | | | 0 | | | Total liability | | $ | 32 | | | $ | 16 | | | $ | (2) | | | $ | 2 | | | $ | 29 | | | $ | 77 | |
(a)Amounts incurred related to the Hale wind farm placed in service in 2019. (b)Amounts settled related to asbestos abatement projects. (c)In 2019, AROs were revised for changes in timing and estimates of cash flows. Changes in steam production AROs primarily related to the cost estimates to remediate ponds at production facilities. | Amounts incurred related to the Hale wind farm placed in service in 2019. |
| |
(b)
| Amounts settled related to asbestos abatement projects. |
| |
(c)
| In 2019, AROs were revised for changes in timing and estimates of cash flows. Changes in steam production AROs primarily related to the cost estimates to remediate ponds at production facilities. |
|
| | | | | | | | | | | | | | | | |
| | | 2018 |
(Millions of Dollars) | | Jan. 1, 2018 | | Accretion | | Cash Flow Revisions (a) | | Dec. 31, 2018 (b) |
| Electric | | | | | | | | |
Steam and other production | | $ | 20.3 |
| | $ | 1.2 |
| | $ | 0.5 |
| | $ | 22.0 |
|
| Distribution | | 7.0 |
| | 0.3 |
| | 1.8 |
| | 9.1 |
|
| Miscellaneous | | 1.2 |
| | 0.1 |
| | — |
| | 1.3 |
|
| Total liability | | $ | 28.5 |
| | $ | 1.6 |
| | $ | 2.3 |
| | $ | 32.4 |
|
| |
(a)
| In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes in electric distribution AROs were primarily related to increased labor costs. |
| |
(b)
| There were no ARO amounts incurred or settled in 2018. |
Indeterminate AROs — Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of SPS’ facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2019.2020. Therefore, an ARO has not been recorded for these facilities.
Removal Costs — SPS records a regulatory liability for the plant removal costs that are recovered currently in rates. Removal costs have accumulated based on varying rates as authorized by the appropriate regulatory entities. SPS has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Removal costs as of Dec. 31, 2019 and 2018 were $174.5 million and $187.7 million, respectively.
Leases
SPS evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. Under ASC Topic 842, adopted by SPS on Jan. 1, 2019, aA contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine if the arrangement is a finance lease.
ROU assets represent SPS’ rights to use leased assets. Starting in 2019, theThe present value of future operating lease payments are recognized in current and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets.
Most of SPS’ leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the estimated incremental borrowing rate (weighted-average of 4.4%). SPS 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 purposes of lease accounting and disclosure. Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the balance sheet.
Operating lease ROU assets:
|
| | | | |
| (Millions of Dollars) | | Dec. 31, 2019 |
| PPAs | | $ | 500.3 |
|
| Other | | 48.0 |
|
| Gross operating lease ROU assets | | 548.3 |
|
| Accumulated amortization | | (25.9 | ) |
| Net operating lease ROU assets | | $ | 522.4 |
|
| | | | | | | | | | | | | | |
| (Millions of Dollars) | | Dec. 31, 2020 | | Dec. 31, 2019 |
| PPAs | | $ | 500 | | | $ | 500 | |
| Other | | 50 | | | 48 | |
| Gross operating lease ROU assets | | 550 | | | 548 | |
| Accumulated amortization | | (58) | | | (26) | |
| Net operating lease ROU assets | | $ | 492 | | | $ | 522 | |
Components of lease expense:
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2020 | | 2019 | | 2018 |
| Operating leases | | | | | | |
| PPA capacity payments | | $ | 48 | | | $ | 48 | | | $ | 51 | |
Other operating leases (a) | | 3 | | | 5 | | | 8 | |
Total operating lease expense (b) | | $ | 51 | | | $ | 53 | | | $ | 59 | |
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 |
| Operating leases | | | | | | |
| PPA capacity payments | | $ | 48.1 |
| | $ | 51.1 |
| | $ | 51.4 |
|
Other operating leases (a) | | 4.9 |
| | 7.9 |
| | 6.4 |
|
Total operating lease expense (b) | | $ | 53.0 |
| | $ | 59.0 |
| | $ | 57.8 |
|
| |
(a)(b)PPA capacity payments are included in electric fuel and purchased power on the statements of income. Expense for other operating leases is included in O&M expense. | Includes short-term lease expense of $1.5 million, $1.1 million and $1.2 million for 2019, 2018 and 2017, respectively. |
| |
(b)
| PPA capacity payments are included in electric fuel and purchased power on the statements of income. Expense for other operating leases is included in O&M expense. |
Commitments under operating leases as of Dec. 31, 2019:2020:
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | PPA (a) (b) Operating Leases | | Other Operating Leases | | Total
Operating Leases |
| 2021 | | $ | 46 | | | $ | 3 | | | $ | 49 | |
| 2022 | | 46 | | | 3 | | | 49 | |
| 2023 | | 46 | | | 3 | | | 49 | |
| 2024 | | 46 | | | 3 | | | 49 | |
| 2025 | | 46 | | | 3 | | | 49 | |
| Thereafter | | 359 | | | 43 | | | 402 | |
| Total minimum obligation | | 589 | | | 58 | | | 647 | |
| Interest component of obligation | | (139) | | | (17) | | | (156) | |
| Present value of minimum obligation | | 450 | | | 41 | | | 491 | |
| Less current portion | | | | | | (28) | |
| Noncurrent operating and finance lease liabilities | | | | | | $ | 463 | |
| | | | | | |
| Weighted-average remaining lease term in years | | | | | | 13.0 |
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | PPA (a) (b) Operating Leases | | Other Operating Leases | | Total
Operating Leases |
| 2020 | | $ | 46.2 |
| | $ | 3.4 |
| | $ | 49.6 |
|
| 2021 | | 46.2 |
| | 3.3 |
| | 49.5 |
|
| 2022 | | 46.2 |
| | 3.4 |
| | 49.6 |
|
| 2023 | | 46.2 |
| | 3.4 |
| | 49.6 |
|
| 2024 | | 46.2 |
| | 3.5 |
| | 49.7 |
|
| Thereafter | | 404.5 |
| | 51.3 |
| | 455.8 |
|
| Total minimum obligation | | 635.5 |
| | 68.3 |
| | 703.8 |
|
| Interest component of obligation | | (160.0 | ) | | (21.6 | ) | | (181.6 | ) |
| Present value of minimum obligation | | 475.5 |
| | 46.7 |
| | 522.2 |
|
| Less current portion | | | | | | (26.9 | ) |
| Noncurrent operating lease liabilities | | | | | | $ | 495.3 |
|
| | | | | | | |
| Weighted-average remaining lease term in years | | | | | | 14.1 |
|
| |
(a)(a)Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.
| 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. |
Commitments under(b)PPA operating leases as of Dec. 31, 2018:contractually expire at various dates through 2033.
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | PPA (a) (b) Operating Leases | | Other Operating Leases | | Total
Operating Leases |
| 2019 | | $ | 46.7 |
| | $ | 5.2 |
| | $ | 51.9 |
|
| 2020 | | 46.2 |
| | 5.2 |
| | 51.4 |
|
| 2021 | | 46.2 |
| | 5.1 |
| | 51.3 |
|
| 2022 | | 46.2 |
| | 5.1 |
| | 51.3 |
|
| 2023 | | 46.2 |
| | 5.1 |
| | 51.3 |
|
| Thereafter | | 450.8 |
| | 56.3 |
| | 507.1 |
|
| |
(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. |
PPAs and Fuel Contracts
Non-Lease PPAs — SPS has entered into PPAs with other utilities and energy suppliers with various expiration dates through 2024 for purchased power to meet system load and energy requirements and operating reserve obligations.
In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Capacity payments are contingent on the IPP meeting contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on financial results are mitigated through purchased energy cost recovery mechanisms.
Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts, were payments for capacity of $19.9$12 million, $57.6$20 million and $58.4$58 million in 2020, 2019 and 2018, and 2017, respectively.
At Dec. 31, 2019,2020, the estimated future payments for capacity that SPS is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:
|
| | | | |
| (Millions of Dollars) | | Capacity |
| 2020 | | $ | 12.3 |
|
| 2021 | | 12.5 |
|
| 2022 | | 12.7 |
|
| 2023 | | 13.0 |
|
| 2024 | | 5.9 |
|
| Thereafter | | — |
|
| Total | | $ | 56.4 |
|
| | | | | | | | |
| (Millions of Dollars) | | Capacity |
| 2021 | | $ | 12 | |
| 2022 | | 12 | |
| 2023 | | 13 | |
| 2024 | | 6 | |
| 2025 | | 0 | |
| Thereafter | | 0 | |
| Total | | $ | 43 | |
Fuel Contracts — SPS has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal and natural gas requirements. These contracts expire between 20202021 and 2033. SPS is required to pay additional amounts depending on actual quantities shipped under these agreements.
Estimated minimum purchases under these contracts as of Dec. 31, 2019:2020:
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | Coal | | Natural gas
supply | | Natural gas
storage and
transportation |
| 2020 | | $ | 96.7 |
| | $ | 12.3 |
| | $ | 28.9 |
|
| 2021 | | 67.7 |
| | — |
| | 23.3 |
|
| 2022 | | 38.8 |
| | — |
| | 17.4 |
|
| 2023 | | — |
| | — |
| | 12.7 |
|
| 2024 | | — |
| | — |
| | 6.7 |
|
| Thereafter | | — |
| | — |
| | 26.3 |
|
| Total | | $ | 203.2 |
| | $ | 12.3 |
| | $ | 115.3 |
|
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | Coal | | Natural gas
supply | | Natural gas
storage and
transportation |
| 2021 | | $ | 80 | | | $ | 33 | | | $ | 31 | |
| 2022 | | 35 | | | 0 | | | 31 | |
| 2023 | | 0 | | | 0 | | | 29 | |
| 2024 | | 0 | | | 0 | | | 16 | |
| 2025 | | 0 | | | 0 | | | 12 | |
| Thereafter | | 0 | | | 0 | | | 20 | |
| Total | | $ | 115 | | | $ | 33 | | | $ | 139 | |
VIEs
PPAs— Under certain PPAs, SPS purchases power from IPPs for which SPS is required to reimburse fuel costs, or to participate in tolling arrangements under which SPS procures the natural gas required to produce the energy that it purchases. SPS has determined that certain IPPs are VIEs. SPS is not subject to risk of loss from the operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity.
In addition, certain solar PPAs provide an option to purchase emission allowances or sharing provisions related to production credits generated by the solar facility under contract. These specific PPAs create a variable interest in the IPP.
SPS evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities. SPS concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.
SPS had approximately 1,197 MW of capacity under long-term PPAs at both Dec. 31, 20192020 and 20182019 with entities that have been determined to be VIEs. These agreements have expiration dates through 2041.
Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk plant from TUCO Inc. under contracts that will expire in December 2022. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing, and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.
SPS has not provided any significant financial support to TUCO, other than contractual payments for delivered coal. However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of fuel procurement costs. SPS has determined that TUCO is a VIE. SPS has concluded that it is not the primary beneficiary of TUCO, because SPS does not have the power to direct the activities that most significantly impact TUCO’s economic performance.
|
|
11. Other Comprehensive Income |
Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31: |
| | | | | | | | | | | | |
| | | 2019 |
| (Millions of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total |
| Accumulated other comprehensive loss at Jan. 1 | | $ | (0.7 | ) | | $ | (0.7 | ) | | $ | (1.4 | ) |
| Other comprehensive loss before reclassifications (net of taxes of $0 and $(0.1), respectfully | | — |
| | (0.2 | ) | | (0.2 | ) |
| Losses reclassified from net accumulated other comprehensive loss: | | | | | | |
| Amortization of net actuarial loss (net of taxes of $0) | | — |
| | 0.2 |
| (a) | 0.2 |
|
| Net current period other comprehensive income (loss) | | — |
| | — |
| | — |
|
| Accumulated other comprehensive loss at Dec. 31 | | $ | (0.7 | ) | | $ | (0.7 | ) | | $ | (1.4 | ) |
| |
(a)
| Included in the computation of net periodic pension and postretirement benefit costs. See Note 9 for further information. |
|
| | | | | | | | | | | | |
| | | 2018 |
| (Millions of Dollars) | | Gains and Losses on Cash Flow Hedges | | Defined Benefit Pension and Postretirement Items | | Total |
| Accumulated other comprehensive loss at Jan. 1 | | $ | (0.8 | ) | | $ | (0.7 | ) | | $ | (1.5 | ) |
| Losses reclassified from net accumulated other comprehensive loss: | |
|
| |
|
| |
|
|
| Interest rate derivatives (net of taxes of $0) | | 0.1 |
| (a) | — |
| | 0.1 |
|
| Net current period other comprehensive income | | 0.1 |
| | — |
| | 0.1 |
|
| Accumulated other comprehensive loss at Dec. 31 | | $ | (0.7 | ) | | $ | (0.7 | ) | | $ | (1.4 | ) |
| |
(a)
| Included in interest charges. |
|
|
12.11. Related Party Transactions |
Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including SPS. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. SPS uses the service provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned.
Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS have established a utility money pool arrangement with the utility subsidiaries.arrangement.
See Note 5 for further information.
Significant affiliate transactions among the companies and related parties for the years ended Dec. 31:
|
| | | | | | | | | | | | |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 |
| Operating expenses: | | | | | | |
| Purchased power | | $ | — |
| | $ | — |
| | $ | 1.4 |
|
| Other operating expenses — paid to Xcel Energy Services Inc. | | 192.0 |
| | 195.1 |
| | 196.6 |
|
| Interest expense | | 0.2 |
| | 0.6 |
| | — |
|
| | | | | | | | | | | | | | | | | | | | |
| (Millions of Dollars) | | 2020 | | 2019 | | 2018 |
| Operating expenses: | | | | | | |
| | | | | | |
| Other operating expenses — paid to Xcel Energy Services Inc. | | $ | 200 | | | $ | 192 | | | $ | 195 | |
| Interest expense | | 0 | | | 0 | | | 1 | |
Accounts receivable and payable with affiliates at Dec. 31 were:
|
| | | | | | | | | | | | | | | | |
| | | 2019 | | 2018 |
| (Millions of Dollars) | | Accounts
Receivable | | Accounts
Payable | | Accounts
Receivable | | Accounts
Payable |
| NSP-Minnesota | | $ | 4.2 |
| | $ | — |
| | $ | 4.7 |
| | $ | — |
|
| PSCo | | — |
| | 0.4 |
| | — |
| | 0.7 |
|
| Other subsidiaries of Xcel Energy Inc. | | — |
| | 20.0 |
| | 5.8 |
| | 19.2 |
|
| | | $ | 4.2 |
| | $ | 20.4 |
| | $ | 10.5 |
| | $ | 19.9 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2020 | | 2019 |
| (Millions of Dollars) | | Accounts Receivable | | Accounts Payable | | Accounts Receivable | | Accounts Payable |
| NSP-Minnesota | | $ | 3 | | | $ | 0 | | | $ | 4 | | | $ | 0 | |
| PSCo | | 6 | | | 0 | | | 0 | | | 0 | |
| Other subsidiaries of Xcel Energy Inc. | | 0 | | | 17 | | | 0 | | | 20 | |
| | $ | 9 | | | $ | 17 | | | $ | 4 | | | $ | 20 | |
|
| |
13.12. Summarized Quarterly Financial Data (Unaudited) |
|
| | | | | | | | | | | | | | | | |
| | | Quarter Ended |
| (Millions of Dollars) | | March 31, 2019 | | June 30, 2019 | | Sept. 30, 2019 | | Dec. 31, 2019 |
| Operating revenues | | $ | 454.1 |
| | $ | 410.5 |
| | $ | 533.1 |
| | $ | 428.1 |
|
| Operating income | | 74.5 |
| | 81.9 |
| | 135.4 |
| | 54.9 |
|
| Net income | | 54.1 |
| | 58.8 |
| | 105.1 |
| | 45.1 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Quarter Ended |
| (Millions of Dollars) | | March 31, 2020 | | June 30, 2020 | | Sept. 30, 2020 | | Dec. 31, 2020 |
| Operating revenues | | $ | 395 | | | $ | 423 | | | $ | 615 | | | $ | 437 | |
| Operating income | | 53 | | | 80 | | | 163 | | | 63 | |
| Net income | | 43 | | | 72 | | | 127 | | | 53 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Quarter Ended |
| (Millions of Dollars) | | March 31, 2019 | | June 30, 2019 | | Sept. 30, 2019 | | Dec. 31, 2019 |
| Operating revenues | | $ | 454 | | | $ | 411 | | | $ | 533 | | | $ | 428 | |
| Operating income | | 75 | | | 82 | | | 135 | | | 55 | |
| Net income | | 54 | | | 59 | | | 105 | | | 45 | |
|
| | | | | | | | | | | | | | | | |
| | | Quarter Ended |
| (Millions of Dollars) | | March 31, 2018 | | June 30, 2018 | | Sept. 30, 2018 | | Dec. 31, 2018 |
| Operating revenues | | $ | 447.2 |
| | $ | 481.3 |
| | $ | 540.1 |
| | $ | 464.6 |
|
Operating income (a) | | 57.1 |
| | 87.6 |
| | 111.0 |
| | 56.0 |
|
| Net income | | 33.1 |
| | 58.5 |
| | 81.5 |
| | 40.2 |
|
| |
(a)
| In 2018, SPS implemented ASU No. 2017-07 related to net periodic benefit cost, which resulted in retrospective reclassification of pension costs from O&M expense to other income. |
|
|
| ITEM 9 — CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
|
| |
ITEM 9A — CONTROLS AND PROCEDURES |
Disclosure Controls and Procedures
SPS maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the CEO and CFO, allowing timely decisions regarding required disclosure. As of Dec. 31, 2019,2020, based on an evaluation carried out under the supervision and with the participation of SPS’ management, including the CEO and CFO, of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that SPS’ disclosure controls and procedures were effective.
Internal Control Over Financial Reporting
No changes in SPS’ internal control over financial reporting occurred during SPS’ most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, SPS’ internal control over financial reporting. SPS maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. SPS has evaluated and documented its controls in process activities, general computer activities, and on an entity-wide level.
During the year and in preparation for issuing its report for the year ended Dec. 31, 20192020 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, SPS conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, SPS did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board, as approved by the SEC and as indicated in SPS’ Management Report on Internal Controls over Financial Reporting, which is contained in Item 8 herein.
This annual report does not include an attestation report of SPS’ independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by SPS’ independent registered public accounting firm pursuant to the rules of the SEC that permit SPS to provide only management’s report in this annual report.
|
| |
ITEM 9B — OTHER INFORMATION |
None.
PART III
Items 10, 11, 12 and 13 of Part III of Form 10-K have been omitted from this report for SPS in accordance with conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly-owned subsidiaries.
|
| |
| ITEM 10 — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
|
| |
| ITEM 11 — EXECUTIVE COMPENSATION |
|
| |
| ITEM 12 — SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
|
| |
| ITEM 13 — CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
Information required under this Item is contained in Xcel Energy Inc.’s definitive Proxy Statement for its 20202021 Annual Meeting of Shareholders, which is incorporated by reference.
|
| |
| ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES |
The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm – Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for its 20202021 Annual Meeting of Shareholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 6, 2020.2021. Such information set forth under such heading is incorporated herein by this reference hereto.
PART IV
|
| |
ITEM 15 — EXHIBITS,EXHIBIT AND FINANCIAL STATEMENT SCHEDULES |
|
| | | | |
| 1 | Financial Statements |
| Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2019.2020. |
| Report of Independent Registered Public Accounting Firm — Financial Statements |
| Statements of Income — For each of the three years ended Dec. 31, 2020, 2019 2018 and 2017.2018. |
| Statements of Comprehensive Income — For each of the three years ended Dec. 31, 2020, 2019 2018 and 2017.2018. |
| Statements of Cash Flows — For each of the three years ended Dec. 31, 2020, 2019 2018 and 2017.2018. |
| Balance Sheets — As of Dec. 31, 20192020 and 2018.2019. |
| Statements of Common Stockholder’s Equity — For each of the three years ended Dec. 31, 2020, 2019 2018 and 2017.2018. |
| |
| 2 | Schedule II — Valuation and Qualifying Accounts and Reserves for each of the years ended Dec. 31, 2020, 2019 2018 and 2017.2018. |
| |
| 3 | Exhibits |
| * | Indicates incorporation by reference |
| + | Executive Compensation Agreements and Benefit Plans Covering Executive Officers and Directors |
|
| | | | | | | | | | |
| Exhibit Number | Description | Report or Registration Statement | SEC File or Registration Number | Exhibit Reference |
| | SPS Form 10-Q for the quarter ended Sept. 30, 2017 | 001-03789 | 3.01 |
| | SPS Form 10-K for the year ended Dec. 31, 2018 | 001-03789 | 3.02 |
| | SPS Form 8-K dated Feb. 25, 1999 | 001-03789 | 99.2 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2003 | 001-03034 | 4.04 |
| | SPS Form 8-K dated Oct. 3, 2006 | 001-03789 | 4.01 |
| | SPS Form 8-K dated Aug. 10, 2011 | 001-03789 | 4.01 |
| | SPS Form 8-K dated Aug. 10, 2011 | 001-03789 | 4.02 |
| | SPS Form 8-K dated June 9, 2014 | 001-03789 | 4.02 |
| | SPS Form 8-K dated Aug. 12, 2016 | 001-03789 | 4.02 |
| | SPS Form 8-K dated Aug. 9, 2017 | 001-03789 | 4.02 |
|
| | | | |
| | SPS Form 8-K dated Nov. 5, 2018 | 001-03789 | 4.02 |
| | SPS Form 8-K dated June 18, 2019 | 001-03789 | 4.02 |
| | SPS Form 8-K dated May 18, 2020 | 4.02 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 001-03034 | 10.02 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 001-03034 | 10.05 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 20082011 | 001-03034 | 10.0810.18 |
| | Xcel Energy Inc. Form U5B dated Nov. 16, 200010-Q for the quarter ended June 30, 2016 | 001-03034 | H-110.01 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018 | 10.01 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2020 | 10.02 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2020 | 10.01 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 001-03034 | 10.17 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009 | 001-03034 | 10.06 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009 | 001-03034 | 10.08 |
| | Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010 | 001-03034 | Appendix A |
| | Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013 | 10.01 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009 | 10.08 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 10.07 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011 | 10.17 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013 | 10.22 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016 | 10.01 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017 | 10.1 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 10.34 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 10.35 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019 | 10.32 |
| | Xcel Energy Inc. Definitive Proxy Statement dated April 5, 2011 | 001-03034 | Appendix A |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 001-03034 | 10.07 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011 | 001-03034 | 10.18 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011 | 001-03034 | 10.17 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013 | 001-03034 | 10.01 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013 | 001-03034 | 10.02 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013 | 001-03034 | 10.22 |
| | Xcel Energy Inc. Form 8-K dated May 20, 2015 | 001-0303410.02 |
| 10.02 | | | | | | | | | | |
| | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2016 | 001-03034 | 10.01 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016 | 001-03034 | 10.01 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017 | 001-03034 | 10.1 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 20172020 | 001-03034 | 10.3010.22 |
| | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018 | 001-03034 | 10.01 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 001-03034 | 10.34 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 001-03034 | 10.35 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 001-03034 | 10.36 |
| | Xcel Energy Inc. Form U5B dated Nov. 16, 2000 | H-1 |
| Third Amended and Restated Credit Agreement, dated as of June 7, 2019 among SPS, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, Wells Fargo Bank, National Association, MUFG Bank, Ltd., and Citibank, N.A., as Documentation Agents | Xcel Energy Inc. Form 8-K dated June 7, 2019 | 001-03034 | 99.04 |
| | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019 | 001-03034 | 10.33 |
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| 101.INS | Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document |
| 101.SCH | Inline XBRL Schema |
| 101.CAL | Inline XBRL Calculation |
| 101.DEF | Inline XBRL Definition |
| 101.LAB | Inline XBRL Label |
|
| 101.PRE | | | | Inline XBRL Presentation |
101.PRE104 | XBRL Presentation |
104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
SCHEDULE II
Southwestern Public Service Co. Valuation and Qualifying Accounts Years Ended Dec. 31
| | | | | | | | | | | | | | | | | | | | |
| | Allowance for bad debts |
| (Millions of Dollars) | | 2020 | | 2019 | | 2018 |
| Balance at Jan. 1 | | $ | 5 | | | $ | 6 | | | $ | 6 | |
| Additions charged to costs and expenses | | 6 | | | 6 | | | 5 | |
Additions charged to other accounts (a) | | 2 | | | 2 | | | 1 | |
Deductions from reserves (b) | | (5) | | | (9) | | | (6) | |
| Balance at Dec. 31 | | $ | 8 | | | $ | 5 | | | $ | 6 | |
(a)Recovery of amounts previously written-off.
(b)Deductions related primarily to bad debt write-offs.
|
| | | | | | | | | | | | |
| | | Allowance for bad debts |
| (Millions of Dollars) | | 2019 | | 2018 | | 2017 |
| Balance at Jan. 1 | | $ | 5.6 |
| | $ | 6.4 |
| | $ | 6.4 |
|
| Additions charged to costs and expenses | | 5.7 |
| | 4.9 |
| | 5.1 |
|
Additions charged to other accounts (a) | | 1.5 |
| | 1.0 |
| | 1.2 |
|
Deductions from reserves (b) | | (7.5 | ) | | (6.7 | ) | | (6.3 | ) |
| Balance at Dec. 31 | | $ | 5.3 |
| | $ | 5.6 |
| | $ | 6.4 |
|
| |
(a)
| Recovery of amounts previously written off. |
| |
(b)
| Deductions related primarily to bad debt write-offs. |
|
|
| ITEM 16 — FORM 10-K SUMMARY |
None.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned thereunto duly authorized.
| | | | | | | | |
| | SOUTHWESTERN PUBLIC SERVICE COMPANY |
| | |
| Feb. 17, 2021 | | SOUTHWESTERN PUBLIC SERVICE COMPANY/s/ BRIAN J. VAN ABEL |
| | Brian J. Van Abel |
Feb. 21, 2020 | | /s/ ROBERT C. FRENZEL |
| | Robert C. Frenzel |
| | Executive Vice President, Chief Financial Officer and Director |
| | (Principal Financial Officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the date indicated above.
| | | | | | | | |
| /s/ BEN FOWKE | | /s/ DAVID T. HUDSON |
| Ben Fowke | | David T. Hudson |
| Chairman, Chief Executive Officer and Director | | President and Director |
| (Principal Executive Officer) | | |
| | |
/s/ BEN FOWKEBRIAN J. VAN ABEL | | /s/ DAVID T. HUDSON |
Ben Fowke | | David T. Hudson |
Chairman, Chief Executive Officer and Director | | President and Director |
(Principal Executive Officer) | | |
| | |
/s/ ROBERT C. FRENZEL | | /s/ JEFFREY S. SAVAGE |
Robert C. FrenzelBrian J. Van Abel | | Jeffrey S. Savage |
| Executive Vice President, Chief Financial Officer and Director | | Senior Vice President, Controller |
| (Principal Financial Officer) | | (Principal Accounting Officer) |
| | |
/s/ DAVID L. EVESROBERT C. FRENZEL | | |
David L. EvesRobert C. Frenzel | | |
Executive Vice President, Group President, UtilitiesChief Operating Officer and Director | | |
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT
SPS has not sent, and does not expect to send, an annual report or proxy statement to its security holder.
