UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
| ☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the fiscal year ended December 31, 20192021 or
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the transition period from _____ to _____
| 001-03789 | ||
| (Commission File Number) | ||
| (Exact name of registrant as specified in its charter) | ||
| New Mexico | 75-0575400 | ||||
| (State or Other Jurisdiction of Incorporation or Organization) | (IRS Employer Identification No.) | ||||
| 790 South Buchanan Street, | Amarillo, | Texas | 79101 | ||||||||||||||||||||
(Address of Principal Executive Offices) | (Zip Code) | ||||||||||||||||||||||
| (303) | 571-7511 | ||||||||||||||||||||||
| (Registrant’s Telephone Number, Including Area Code) | |||||||||||||||||||||||
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading | 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 Filerfiler ☐ Accelerated Filerfiler ☒ Non-accelerated filer Non-accelerated Filer☐ Smaller Reporting Companyreporting company ☐ Emerging Growth Companygrowth 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, 2020,23, 2022, 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 20202022 Annual Meeting of Shareholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 6, 2020.5, 2022. 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 InstructionInstructions 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
| PART I | ||||||||
| Item 1 — | ||||||||
| Item 1A — | ||||||||
| Item 1B — | ||||||||
| Item 2 — | ||||||||
| Item 3 — | ||||||||
| Item 4 — | ||||||||
| PART | ||||||||
| Item 5 — | ||||||||
| Item 6 — | ||||||||
| Item 7 — | ||||||||
| Item 7A — | ||||||||
| Item 8 — | ||||||||
| Item 9 — | ||||||||
| Item 9A — | ||||||||
| Item 9B — | ||||||||
| Item 9C — | ||||||||
| PART III | ||||||||
| Item 10 — | ||||||||
| Item 11 — | ||||||||
| Item 12 — | ||||||||
| Item 13 — | ||||||||
| Item 14 — | ||||||||
| PART IV | ||||||||
| Item 15 — | ||||||||
| Item 16 — | ||||||||
This Form 10-K is filed by SPS. SPS is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available onin various filings with the SEC. This report should be read in its entirety.
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PART I
ITEM l — BUSINESS | ||
Definitions of Abbreviations
| 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 | ||||
| Federal and State Regulatory Agencies | |||||
| 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 | ||||
| PHMSA | Pipeline and Hazardous Materials Safety Administration | ||||
| PUCT | Public Utility Commission of Texas | ||||
| SEC | Securities and Exchange Commission | ||||
| TCEQ | Texas Commission on Environmental Quality | ||||
| Other | |||||
| AFUDC | Allowance for funds used during construction | ||||
| ARO | Asset retirement obligation | ||||
| ASC | FASB Accounting Standards Codification | ||||
| BART | Best available retrofit technology | ||||
| C&I | Commercial and Industrial | ||||
| CEO | Chief executive officer | ||||
| CFO | Chief financial officer | ||||
| COVID-19 | Novel coronavirus | ||||
| CWA | Clean Water Act | ||||
| CWIP | Construction work in progress | ||||
| D.C. Circuit | United States Court of Appeals for the District of Columbia Circuit | ||||
| Demand side management | |||||
| ELG | Effluent limitations guidelines | ||||
| ETR | Effective tax rate | ||||
| FASB | Financial Accounting Standards Board | ||||
| Fifth Circuit | United States | ||||
| Generally accepted accounting principles | |||||
| GHG | Greenhouse gas | ||||
| Independent power producing entity | |||||
| Independent System Operators | |||||
| LP&L | Lubbock Power and Light | ||||
| 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 | ||||
| NAV | Net asset value | ||||
| NOL | Net operating loss | ||||
| NOPR | Notice of proposed rulemaking | ||||
| O&M | Operating and maintenance | ||||
| OATT | Open Access Transmission Tariff | ||||
| Per- and PolyFluoroAlkyl Substances | |||||
| PPA | Purchased power agreement | ||||
| Production tax credit | |||||
| REC | Renewable energy credit | ||||
| ROE | Return on equity | ||||
| Regional Transmission Organization | |||||
| Standard & Poor’s Global Ratings | |||||
| SERP | Supplemental executive retirement plan | ||||
SO2 | Sulfur dioxide | ||||
| SPP | Southwest Power Pool, Inc. | ||||
| 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 | ||||
| Measurements | |||||
| KV | Kilovolts | ||||
| KWh | Kilowatt hours | ||||
| MMBtu | Million British thermal units | ||||
| MW | Megawatts | ||||
| MWh | Megawatt hours | ||||
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Forward-Looking Statements |
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 those relating to future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions regarding regulatory proceedings, and expected impact on our results of operations, financial condition and cash flows of resettlement calculations and credit losses relating to certain energy transactions, 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, 20192021 (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, including workforce impacts resulting from vaccination requirements, quarantine policies or government restrictions, and sales volatility; 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; violations of our Codes of Conduct; 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, supply chain constraints, and their impact on capital expenditures andand/or 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.penalties; and regulatory changes and/or limitations to the use of natural gas as an energy source.
Where to Find More Information | ||
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.
| Company Overview | ||
 | |||||||||||||||||
| 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 | $ | ||||||||||||||||
| Rate | $ | ||||||||||||||||
| ROE (net income / average stockholder's equity) | |||||||||||||||||
| Electric generating capacity | |||||||||||||||||
Electric transmission lines (conductor miles) | |||||||||||||||||
Electric distribution lines (conductor miles) | |||||||||||||||||
4
| Electric Operations | ||
Electric operations consist of energy supply, generation, transmission and distribution activities. SPS had electric sales volume of 30,89429,900 (millions of KWh), 395,8280.4 million customers and electric revenues of $1,825.8$2,465 (millions of dollars) for 2019.2021.
Retail Sales/Revenue Statistics(a)
| 2021 | 2020 | |||||||||||||
| KWH sales per retail customer | 51,872 | 51,694 | ||||||||||||
| Revenue per retail customer | $ | 3,469 | $ | 2,925 | ||||||||||
| Residential revenue per KWh | 11.56 | ¢ | 9.77 | ¢ | ||||||||||
| Large C&I revenue per KWh | 4.53 | ¢ | 3.65 | ¢ | ||||||||||
| Small C&I revenue per KWh | 8.08 | ¢ | 6.99 | ¢ | ||||||||||
| Total retail revenue per KWh | 6.69 | ¢ | 5.66 | ¢ | ||||||||||
| 2019 | 2018 | |||||||
| KWH sales per retail customer | 53,123 | 52,074 | ||||||
| Revenue per retail customer | $3,147 | $3,124 | ||||||
| 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 — 20192021
Electric Energy Sources
Total electric energy generation by source (including energy market purchases) for the year ended Dec. 31, 2019:
2021:
*Distributed generation from the Solar*Rewards® program is not included (approximately 12.95 million KWh for 2019)2021).
Carbon–Free
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, commodity costs, weather, system demand and transmission constraints.
See Item 2 — Properties for further information.
Wind Energy Sources
Owned — Owned and operated wind farms with corresponding capacity:
| 2021 | 2020 | |||||||||||||||||||
| Wind Farms | Capacity (a) | Wind Farms | Capacity (b) | |||||||||||||||||
| 2 | 984 MW | 2 | 967 MW | |||||||||||||||||
| 2019 | 2018 | |||||
| Wind Farms | Capacity | Wind Farms | Capacity | |||
| 1 | 478 MW | — | — | |||
(b)Summer 2020 net dependable capacity.
PPAs — Number of PPAs with capacity range:
| 2019 | 2018 | |||||
| PPAs | Range | PPAs | Range | |||
| 18 | 0.7 MW - 250.0 MW | 18 | 0.7 MW - 250.0 MW | |||
| 2021 | 2020 | |||||||||||||||||||
| PPAs | Range | PPAs | Range | |||||||||||||||||
| 17 | 1 MW — 250 MW | 18 | 1 MW — 250 MW | |||||||||||||||||
Capacity — Wind capacity:
| 2021 | 2020 | |||||||
| 2,548 MW | 2,535 MW | |||||||
| 2019 | 2018 | |
| 2,045 MW | 1,565 MW | |
5
Average Cost (Owned) — Average cost per MWh of wind energy from owned generation:
| 2021 | 2020 | |||||||
| $ | 17 | $ | 17 | |||||
Average Cost (PPAs) — Average cost per MWh of wind energy under existing PPAs:
| 2021 | 2020 | |||||||
| $ | 27 | $ | 26 | |||||
| 2019 | 2018 | |
| $25 | $26 | |
Solar energy PPAs:
| Capacity | ||||||||||
| Utility-Scale | ||||||||||
| Total | 207 | |||||||||
| 2021 | 2020 | |||||||
| $ | 61 | $ | 59 | |||||
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 20192021 net summer dependable capacity.
| 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.
| Proposed | ||||||||||||||
| Year | Plant Unit | Capacity (MW) | ||||||||||||
| 2034 | Tolk 1 | 532 | ||||||||||||
| 2034 | Tolk 2 | 535 | ||||||||||||
Coal Fuel Cost
Delivered cost per MMBtu of coal consumed for owned electric generation and the percentage of total fuel requirements:
| Coal | ||||||||||||||
| Cost | Percent | |||||||||||||
| 2021 | $ | 2.07 | 66 | % | ||||||||||
| 2020 | 2.28 | 40 | ||||||||||||
| Coal | |||||||
| Cost | Percent | ||||||
| 2019 | $ | 2.19 | 45 | % | |||
| 2018 | 2.04 | 56 | |||||
| Natural Gas | |||||||
| Cost | Percent | ||||||
| 2019 | $ | 1.14 | 55 | % | |||
| 2018 | 2.24 | 44 | |||||
| System Peak Demand (in MW) | ||||||||
| 2019 | 2018 | |||||||
| 4,261 | Aug. 5 | 4,648 | July 19 | |||||
| Project | Miles | Size | Completion Date | ||||
| TUCO-Yoakum-Hobbs | 106 | 345 KV | 2020 | ||||
| Eddy-Kiowa | 34 | 345 KV | 2020 | ||||
Natural Gas
SPS does not provide retailhas eight natural gas service, but purchasesplants with approximately 2,200 MW of total 2021 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 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 the percentage of total fuel requirements:
| Natural Gas | ||||||||||||||
| Cost | Percent | |||||||||||||
2021 (a) | $ | 6.72 | 34 | % | ||||||||||
| 2020 | 1.43 | 60 | ||||||||||||
(a)Reflective of Winter Storm Uri.
Capacity and Demand
Uninterrupted system peak demand and occurrence date:
| System Peak Demand (MW) | ||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||
| 4,054 | Aug. 9 | 4,195 | July 14 | |||||||||||||||||
Transmission
Transmission lines deliver electricity over long distances from power sources to transmission substations closer to customers. A strong transmission system ensures continued reliable and affordable service, ability to meet state and regional energy policy goals, and support for a diverse generation mix, including renewable energy. SPS owns more than 40,000 conductor miles of transmission lines across its service territory.
Transmission projects completed in 2021 include:
| Project | Miles | Size | ||||||||||||
| Roadrunner-China Draw | 41 | 345 KV | ||||||||||||
Notable upcoming projects:
| Project | Miles | Size (KV) | Completion Date | |||||||||||||||||
| Tolk Plant Substation | ||||||||||||||||||||
| Bus Reconfiguration | n/a | 345, 230 | 2022 | |||||||||||||||||
| Twist to Wilco Line | 4 | 115 | 2024 | |||||||||||||||||
See Item 2 - Properties for further information.
Distribution
Distribution lines allow electricity to travel at lower voltages from substations directly to customers. SPS has a vast distribution network, owning and operating approximately 23,000 conductor miles of distribution lines across our service territory. 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.
6
| Governmental Regulations | ||
Public Utility Regulation
See Item 7 for discussion of public utility regulation.
Environmental Regulation
Our facilities are regulated by federal and state agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid and hazardous wastes or substances. Certain 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 strive to operate in compliance with applicable environmental standards and operatesrelated monitoring and reporting requirements. However, it is not possible to determine what additional facilities or modifications of existing or planned facilities will be required as a result of changes to regulations, interpretations or enforcement policies or what effect future laws or regulations may have.
SPS must comply with emission levels that may require the purchase of emission allowances.
There are significant 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. Future environmental regulations may result in substantial costs.
In July 2019, the EPA adopted the Affordable Clean Energy rule, which requires states to develop plans by 2022 for GHG reductions from coal-fired power plants. In January 2021, the U.S. Court of Appeals for the D.C. Circuit issued a decision vacating and remanding the Affordable Clean Energy rule. That decision would allow the EPA to proceed with alternate regulation of coal-fired power plants. However, the Court of Appeals decision is now before the U.S. Supreme Court, where the Court is expected to rule on the nature and extent of the EPA’s GHG regulatory authority. If any new rules require additional investment, SPS believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.
In October 2020, the TCEQ approved an agreement that SPS will convert the Harrington plant from coal to natural gas pipeline facilities connectingby 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.
Emerging Environmental Regulation
New regulations and legislation are being considered to regulate PFAS in drinking water, water discharges, commercial products, wastes, and other areas. PFAS are man-made chemicals found in many consumer products that can persist and accumulate in the generation facilitiesenvironment. These chemicals have received heightened attention from environmental regulators. Increased regulation of PFAS and other emerging contaminants at the federal, state, and local level could have a potential adverse effect on our operations but at this time, it is uncertain what impact, if any, there will be on our operations, financial condition or cash flows. SPS will continue to interstate natural gas pipelines. SPSmonitor these regulatory developments and their potential impact on its operations.
Other
Our operations are subject to workplace safety standards under the Federal Occupational Safety and Health Act of 1970 (“OSHA”) and comparable state laws that regulate the protection of worker health and safety. In addition, the Company is subject to other government regulations impacting such matters as labor, competition, data privacy, etc. Based on information to date and because our policies and business practices are designed to comply with all applicable laws, we do not believe the jurisdictioneffects of the FERC with respect to natural gas transactions in interstate commerce and the PHMSA and PUCT for pipeline safety compliance.compliance on our operations, financial condition or cash flows are material.
| General | ||
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 operationownership of certain new electric transmission facilities. State utilities commissionsfacilities under Federal regulations. Some states have also createdstate laws that allow the incumbent a Right of First Refusal to own these transmission facilities.
FERC Order 2222 requires that RTO and ISO markets allow participation of aggregations of distributed energy resources. This order is expected to incentivize distributed energy resource planning programs that promote competition for electricity generation resources usedadoption, however implementation is expected to provide service to retail customers.vary by RTO/ISO and the near, medium, and long-term impacts of Order 2222 remain unclear.
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.
7
| Employees |
As of Dec. 31, 2019,2021, SPS had 1,1581,099 full-time employees and noone part-time employees,employee, of which 779736 were covered under collective-bargaining agreements.
| ITEM 1A — RISK FACTORS | ||
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. Although the risks are organized by heading, and each risk is described separately, many of the risks are interrelated. These risks should be carefully considered together with the other information set forth in this report and future reports that Xcel Energy fileswe file with the SEC. You should not interpret the disclosure of any risk factor to imply that the risk has not already materialized. While we believe we have identified and discussed below the key risk factors affecting our business, there may be additional risks and uncertainties that are not presently known or that are not currently believed to be significant that may adversely affect our business, financial condition, results of operations or cash flows in the future.
Oversight of Risk and Related Processes
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 macroeconomic, financial, operational, policy, environmental and security risks.
Operational Risks
Our electric generation, transmission and distribution and gas operations involve numerous risks that may result in accidents and other operating risks and costs.
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.
8
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.
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.
Our utilities are highly dependent on suppliers to deliver components in accordance with short and long-term project schedules.
Our products contain components that are globally sourced from suppliers who, in turn, source components from their suppliers. A shortage of key components in which an alternative supplier is not identified could significantly impact project plans. Such impacts could include timing of projects, including potential for project cancellation. Failure to adhere to project budgets and timelines could adversely impact our results of operations, financial condition or cash flows.
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 programs and procedures 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.
9
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 or contractor unavailability could impact ongoing operations, restoration operations, our reputation and could introduce financial risk or risks of fines.
Our employees, directors, third-party contractors, or suppliers may violate or be perceived to violate our Codes of Conduct, which could have an adverse effect on our reputation.
We are exposed to risk of employee or third-party contractor fraud or other misconduct. All employees and members of the Board of Directors are subject to comply with our Code of Conduct and are required to participate in annual training. Additionally, suppliers are subject to comply with our supplier Code of Conduct. SPS does not tolerate discrimination, violations of our Code of Conduct or other unacceptable behaviors. However, it is not always possible to identify and deter misconduct by employees and other third-parties, which may result in governmental investigations, other actions or lawsuits. If such actions are taken against us we may suffer loss of reputation and such actions could have a material effect on our financial condition, results of operations and cash flows.
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 2019, 20182021, 2020 and 20172019 we paid $332.7$310 million, $131.0$313 million and $108.8$333 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.
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 significantlyuse of historic test years, elimination or riders or interim rates, increasing depreciation lives, 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 andor lower proceeds from equity issuances. It could also 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.rates or lower proceeds from equity issuances. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results.
10
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 the 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, 2019,2021, Xcel Energy Inc. and its utility subsidiaries had approximately $17.4$21.8 billion of long-term debt and $1.3$1.6 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, 2019,2021, Xcel Energy had guarantees outstanding with a $1 million maximum stated amount of approximately $2.0 million and immaterial exposure. Xcel Energy also had additional guarantees of $60.4$59 million at Dec. 31, 20192021 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.
11
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 continues to impact countries, communities, supply chains and markets. A high degree of uncertainty continues to exist regarding the pandemic; the duration and magnitude of business restrictions (domestically and globally); the potential shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; re-shutdowns, if any, and the level and pace of economic recovery.
Although the financial impact of the pandemic on our financial results has largely been mitigated, 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.
SPS participates in biennialGridEx, which is the largest grid security and emergency response exercises (GridEx).exercise in North America. 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. During the normal course of business, we have experienced and expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets. To date, no cybersecurity incident or attack has had a material impact on our business or results of operation.
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.
12
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. Such regulationsInternational agreements could impose substantial costsadditionally lead to future federal or state regulations.
In 2015, the United Nations Framework Convention on our system.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. In April 2021, ahead of the United Nations Climate Change Conference in Glasgow, the Biden Administration committed the U.S. to a Nationally Determined Contribution of 50-52% net GHG emissions reduction economy-wide from 2005 levels. This commitment and other agreements made in Glasgow 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.
Many states and localities continue to pursue their own climate policies. The steps SPS 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.
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.
The continued use of natural gas for power generation has increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for power generation, which could impact our ability to reliably and affordably serve our customers.
In recent years, there have been various local and state agency proposals within and outside our service territories that would attempt to restrict the use and availability of natural gas. If such policies were to prevail, we may be forced to make new resource investment decisions which could potentially result in stranded costs if we are not able to fully recover costs and investments and impact the overall reliability of our service.
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.
13
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.
We have committed to a number of long-term climate change goals, which in part are dependent on future technologies not currently in existence. Given the long-term nature of these goals, there is an inherent uncertainty due to internal and external factors regarding our ability to achieve our stated climate change goals. To the extent climate change goals are not met, this could negatively impact our reputation and potentially result in financial risk.
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. Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks.
| ITEM 1B — UNRESOLVED STAFF COMMENTS | ||
None.
ITEM 2 — PROPERTIES | ||
Virtually all of the utility plant property of SPS is subject to the lien of its first mortgage bond indenture.
| Station, Location and Unit at Dec. 31, 2021 | 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 | 477 | (c) | |||||||||||||||||||
| Sagamore-Dora, NM, 240 Units | Wind | 2020 | 507 | (c) | |||||||||||||||||||
| Total | 5,249 | ||||||||||||||||||||||
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 | |||||||
(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 proposed to be retired in 2034. |
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2019:
2021:
| Conductor Miles | ||||||
| 230 KV | 9,763 | |||||
| 161 KV | — | |||||
| 138 KV | — | |||||
| 115 KV | 14,880 | |||||
| Less than 115 KV | ||||||
| Total Transmission | 40,754 | |||||
| Distribution | ||||||
| Less than 115 KV | 22,651 | |||||
| Total | 63,405 | |||||
SPS had 452458 electric utility transmission and distribution substations at Dec. 31, 2019.2021.
14
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, legalLegal fees are generally expensed as incurred.
See Note 10 to the financial statements, Item 1 and Item 7 for further information.
ITEM 4 — MINE | ||
None.
PART II
ITEM 5 — MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER | ||
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 20192021 and 20182020 were as follows:
| (Millions of Dollars) | 2021 | 2020 | ||||||||||||
| First quarter | $ | 52 | $ | 76 | ||||||||||
| Second quarter | 79 | 55 | ||||||||||||
| Third quarter | 123 | 136 | ||||||||||||
| Fourth quarter | 60 | 54 | ||||||||||||
| (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 — [RESERVED] | ||
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.
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, 2021 and 2020, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings.
| Results of Operations | ||
2021 Comparison with 2020
SPS’ net income was $318 million for 2021, compared with net income of $295 million for 2020. The increase was primarily due to capital investment recovery, other regulatory outcomes and higher sales and demand, partially offset by decreased AFUDC.
Electric MarginsMargin
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).
Electric Margin
Electric Revenues, Fuel and unit cost changes in fuelPurchased Power and purchased power. Electric Margin
| (Millions of Dollars) | 2021 | 2020 | ||||||||||||
| Electric revenues | $ | 2,465 | $ | 1,870 | ||||||||||
| Electric fuel and purchased power | (1,432) | (835) | ||||||||||||
| Electric margin | $ | 1,033 | $ | 1,035 | ||||||||||
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Changes in fuel or purchased power costs can impact earnings as the fuel and purchased power cost recovery mechanismsElectric Margin
| (Millions of Dollars) | 2021 vs. 2020 | |||||||
Texas 2019 rate case surcharge(a) | $ | (70) | ||||||
| PTCs flowed back to customers (offset by lower ETR) | (45) | |||||||
| Wholesale transmission revenue (net) | 14 | |||||||
| Sales and demand | 23 | |||||||
| Regulatory rate outcomes (Texas and New Mexico) | 63 | |||||||
| Other (net) | 13 | |||||||
| Total decrease in electric margin | $ | (2) | ||||||
(a)Impact is due to the Texas and New Mexico jurisdictions may not allow for complete recoveryrate case outcome, which resulted in a revenue increase that was recognized in the third quarter of all expenses. Electric revenues and margin for 2018 are before and after the impact2020 (largely offset by recognition of the TCJA:
| (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) | 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
AFUDC, Equity and Debt — AFUDC increased by $11.1decreased $41 million or 39.6% for 2019 compared with the prior year. The increase wasyear-to-date, primarily due to the Hale and Sagamore wind farms.
Income Taxes — Income tax expense decreased $13.3benefit increased $49 million for 2019 compared with the prior year.2021. The decreaseincrease was primarily driven by an increase in wind PTCs; partially offset by higher pretax income.PTCs. Wind PTCs are generally credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income.
| Other | ||
In February 2021, the United States experienced Winter Storm Uri. Extreme cold temperatures impacted certain operational assets as well as the availability of renewable generation. The cold weather also affected the country’s supply and demand for natural gas. These factors contributed to extremely high market prices for natural gas and electricity. As a result of the extremely high market prices, SPS incurred net natural gas, fuel and purchased energy costs of approximately $100 million (largely deferred as regulatory assets).
Regulatory Overview The ETR was 8.9% for 2019 compared with 15.4% for 2018. The lower ETR in 2019 was primarily due to the items referenced above.
Xcel Energy which includes SPS, attemptshas natural gas, fuel and purchased energy mechanisms in each jurisdiction for recovering incurred costs. However, the utility subsidiaries have deferred February 2021 cost increases for future recovery and sought recovery of the cost increases over a period of up to 30 months to mitigate the riskimpact to customer bills. Additionally, we did not request recovery of regulatory penalties through formal training on prohibited practices and a compliance function that reviews interaction withfinancing costs in order to further limit the markets under FERC and Commodity Futures Trading Commission jurisdictions.
Proceedings initiated:
| Texas | As part of the Texas fuel surcharge filing, SPS In the third quarter, SPS filed a supplemental application and testimony to recover an additional $26 million in under-collected purchased power and fuel costs through June 2021 resulting primarily from SPP resettlements and continued increases in natural gas prices. In November 2021, the Administrative Law Judge abated the hearing schedule to allow the parties to continue settlement negotiations. In December 2021, SPS filed its triennial Fuel Reconciliation, under which the PUCT will consider prudence of SPS’ fuel costs for the period July 2018 - June 2021, including Winter Storm Uri. In January 2022, SPS and other parties filed a stipulation/motion for interim rates. The filing covers all fuel under-collections occurring between January 2020 and August 2021, totaling $121 million. The settlement does not address the prudence of Winter Storm Uri costs nor the retention of $11 million related to market sales during the event. These items will be reviewed through the triennial Fuel Reconciliation proceeding and are subject to a final PUCT decision. Interim rates, designed to collect up to $110 million over a period of 30 months, will begin on Feb. 1, 2022. | |||||||||||||
In | ||||||||||||||
| (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 | % | |||||
The next stepsFERC and state and local regulatory commissions regulate SPS. SPS is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric distribution companies in New Mexico and Texas.
Rates are designed to recover plant investment, operating costs and an allowed return on investment. SPS requests changes in utility rates through commission filings. Changes in operating costs can affect SPS’ financial results, depending on the procedural schedule are expected to be as follows:
In May 2019,addition, the Governor signed into law Senate Bill 1938, which grants incumbent utilities a ROFR to build transmission infrastructure when it directly interconnects toregulatory commissions authorize the utility’s existing facility. In June 2019, a complaint was filedROE, capital structure and depreciation rates in the United States District Court for the Western Districtrate proceedings. Decisions by these regulators can significantly impact SPS’ results of Texas claiming the new ROFR law to be unconstitutional. The Texas Attorney General has made a motion to dismiss the federal court complaint. A ruling on the dismissal motion is expected in the first quarter of 2020.operations.
See Rate Matters within Note 10 to the financial statements for further information.
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Summary of Regulatory Agencies / RTO and Areas 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 Integrated and Wholesale Markets | SPS is a transmission owning member of the SPP RTO and operates within the SPP RTO and SPP integrated and wholesale markets. SPS is authorized to make wholesale electric sales at market-based prices. | |||||||
Recovery Mechanisms
| Mechanism | Additional Information | |||||||
| Distribution Cost Recovery Factor | Recovers distribution costs not included in rates in Texas. | |||||||
| Energy Efficiency Cost Recovery Factor | Recovers costs for energy efficiency programs in Texas. | |||||||
| Energy Efficiency Rider | Recovers costs for energy efficiency programs in New Mexico. | |||||||
| Fuel and Purchased Power Cost Adjustment Clause | Adjusts monthly to recover actual fuel and purchased power costs in New Mexico. | |||||||
| Power Cost Recovery Factor | Allows recovery of purchased power costs not included in Texas rates. | |||||||
| Renewable Portfolio Standards | Recovers deferred costs for renewable energy programs in New Mexico. | |||||||
| Transmission Cost Recovery Factor | 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 Recently Concluded Regulatory Proceedings
2021 New Mexico Electric Rate Case — In January 2021, SPS filed an electric rate case with the NMPRC with a current requested base rate increase of approximately $84 million.
In June 2021, SPS and various parties filed an uncontested stipulation with the NMPRC, which reflected a $62 million rate increase, a change in the depreciation life of the Tolk coal plant to 2032, an equity ratio of 54.72% and ROE of 9.35% for reconciliation statements and determining the revenue requirements for the Sagamore and Hale wind projects. In December 2021, the Hearing Examiner issued a recommendation that the NMPRC approve the rate case settlement agreement without modification.
On Feb. 2, 2022, the NMPRC voted 3-2 to reject the uncontested stipulation as filed. The NMPRC then approved a modified settlement, which would maintain the proposed revenue requirement increase of $62 million, but would adjust the class cost allocation such that all rate classes would have a uniform increase of 4.89%. The NMPRC required the parties to either file their acceptance or opposition to the modified settlement.
On Feb. 9, 2022, the signatories informed the NMPRC they did not unanimously support the modifications. Accordingly, the Hearing Examiner will issue a procedural order for further proceedings on SPS’ originally filed application.
On Feb. 10, 2022, SPS filed a motion requesting the NMPRC either approve the original settlement or approve the modified settlement.
On Feb. 16, 2022, the NMPRC voted to reconsider its order and voted 3-2 to approve the stipulation without modification. New rates will go into effect on Feb. 26, 2022.
2021 Texas Rate Case — In February 2021, SPS filed an electric rate case with the PUCT and its municipalities, seeking an increase in base rates of approximately $140 million. SPS’ proposed net rate increase to Texas customers was approximately $71 million, or 9.2%, as a result of the offsetting $69 million in fuel cost reductions and PTCs from the Sagamore wind project.
The request is based on a ROE of 10.35%, an equity ratio of 54.60%, a rate base of approximately $3.3 billion and a historic test year based on the 12-month period ended Dec. 31, 2020. The request includes the effect of losing approximately 400 MW from a wholesale transmission customer and changes to depreciation lives of SPS’ Tolk power plant (from 2037 to 2032) and coal handling assets at the Harrington facility (to 2024).
On Jan. 26, 2022, SPS and intervenors filed a blackbox settlement. Key terms include:
•A base rate increase of approximately $89 million effective back to March 15, 2021.
•A 9.35% ROE and 7.01% weighted average cost of capital for AFUDC purposes only.
•The depreciation lives for Tolk moved up to 2034 and Harrington coal assets moved up to 2024.
In February 2022, the ALJ issued an order approving interim rates to be effective on March 1, 2022. A PUCT decision is expected in the first quarter of 2022.
FERC NOPR on ROE Incentive Adders — In April 2021, the FERC issued a NOPR proposing to limit collection of ROE incentive adders for RTO membership to the first three years after an entity begins participation in an RTO. If adopted as a final rule, SPS would prospectively discontinue charging their current 50 basis point ROE incentive adders. Amounts related to a discontinuance of the adder would ultimately be offset by an increase in retail rates, subject to future rate cases.
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.
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Natural Gas
SPS does not provide retail natural gas service, but purchases and transports natural gas for its generation facilities and operates limited 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.
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 noa $2 million and $3 million impact on annual pretax interest expense annually in 20192021 and $0.4 million in 2018,2020, respectively.
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, 2019,2021, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $1.2$3 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $1.2$3 million. At Dec. 31, 2018,2020, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $1.5$1 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $1.5$1 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, 2019.2021.
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, 2019.2021.
| ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA | ||
See Item 15-1 for an index of financial statements included herein.
See Note 1312 to the financial statements for further information.
18
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, 2019.2021. 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, 2019,2021, SPS’ internal control over financial reporting is effective at the reasonable assurance level based on those criteria.
| /s/ ROBERT C. FRENZEL | /s/ BRIAN J. VAN ABEL | |||||||||
| Robert C. Frenzel | Brian J. Van Abel | |||||||||
| Chairman, Chief Executive Officer and Director | Executive Vice President, Chief Financial Officer and Director | |||||||||
| Feb. | Feb. | |||||||||
19
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the 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, 20192021 and 2018,2020, the related statements of income, comprehensive income, cash flows and common stockholder's equity and cash flows for each of the three years in the period ended December 31, 2019,2021, 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, 20192021 and 2018,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2021, 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 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.
20
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 schedules and memorandums, filings made by intervenors, experts’ testimony 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.
| /s/ DELOITTE & TOUCHE LLP | ||
| Minneapolis, Minnesota | ||
| February | ||
| We have served as the Company’s auditor since 2002. | ||
21
SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF INCOME
(amounts in millions)
| Year Ended Dec. 31 | ||||||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | Year Ended Dec. 31 | |||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||||||||||||||
| Operating revenues | $ | 1,825.8 | $ | 1,933.2 | $ | 1,918.0 | Operating revenues | $ | 2,465 | $ | 1,870 | $ | 1,826 | |||||||||||||||||||
| Operating expenses | Operating expenses | |||||||||||||||||||||||||||||||
| Electric fuel and purchased power | 875.4 | 1,043.5 | 1,055.3 | Electric fuel and purchased power | 1,432 | 835 | 875 | |||||||||||||||||||||||||
| Operating and maintenance expenses | 285.3 | 282.7 | 285.4 | Operating and maintenance expenses | 271 | 275 | 285 | |||||||||||||||||||||||||
| Demand side management program expenses | 16.6 | 17.7 | 15.5 | |||||||||||||||||||||||||||||
| Demand side management expenses | Demand side management expenses | 17 | 16 | 17 | ||||||||||||||||||||||||||||
| Depreciation and amortization | 229.9 | 209.6 | 193.9 | Depreciation and amortization | 300 | 295 | 230 | |||||||||||||||||||||||||
| Taxes (other than income taxes) | 71.9 | 68.0 | 67.0 | Taxes (other than income taxes) | 79 | 90 | 72 | |||||||||||||||||||||||||
| Total operating expenses | 1,479.1 | 1,621.5 | 1,617.1 | Total operating expenses | 2,099 | 1,511 | 1,479 | |||||||||||||||||||||||||
| Operating income | 346.7 | 311.7 | 300.9 | Operating income | 366 | 359 | 347 | |||||||||||||||||||||||||
| Other income (expense), net | 2.2 | (3.0 | ) | (1.8 | ) | Other income (expense), net | 1 | (2) | 2 | |||||||||||||||||||||||
| Allowance for funds used during construction — equity | 26.8 | 19.1 | 9.3 | Allowance for funds used during construction — equity | 4 | 33 | 27 | |||||||||||||||||||||||||
| 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, $4 and $3, respectively | Interest charges — includes other financing costs of $4, $4 and $3, respectively | 114 | 119 | 99 | ||||||||||||||||||||||||||||
| Allowance for funds used during construction — debt | (12.3 | ) | (8.9 | ) | (5.4 | ) | Allowance for funds used during construction — debt | (2) | (14) | (12) | ||||||||||||||||||||||
| Total interest charges and financing costs | 87.0 | 75.6 | 80.8 | Total interest charges and financing costs | 112 | 105 | 87 | |||||||||||||||||||||||||
| Income before income taxes | 288.7 | 252.2 | 227.6 | Income before income taxes | 259 | 285 | 289 | |||||||||||||||||||||||||
| Income taxes | 25.6 | 38.9 | 68.4 | |||||||||||||||||||||||||||||
| Income tax (benefit) expense | Income tax (benefit) expense | (59) | (10) | 26 | ||||||||||||||||||||||||||||
| Net income | $ | 263.1 | $ | 213.3 | $ | 159.2 | Net income | $ | 318 | $ | 295 | $ | 263 | |||||||||||||||||||
See Notes to Financial Statements
22
| 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 | |||||
SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF CASH FLOWS
(amounts in millions)
| Year Ended Dec. 31 | Year Ended Dec. 31 | |||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | 2021 | 2020 | 2019 | |||||||||||||||||||||||
| Operating activities | Operating activities | |||||||||||||||||||||||||||
| Net income | $ | 263.1 | $ | 213.3 | $ | 159.2 | Net income | $ | 318 | $ | 295 | $ | 263 | |||||||||||||||
| 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 | 303 | 298 | 232 | |||||||||||||||||||||
| Demand side management program amortization | — | 1.7 | 1.7 | |||||||||||||||||||||||||
| Deferred income taxes | 29.0 | 22.1 | 126.5 | Deferred income taxes | (47) | 22 | 29 | |||||||||||||||||||||
| Allowance for equity funds used during construction | (26.8 | ) | (19.1 | ) | (9.3 | ) | Allowance for equity funds used during construction | (4) | (33) | (27) | ||||||||||||||||||
| Provision for bad debts | 5.7 | 4.9 | 5.1 | Provision for bad debts | 6 | 6 | 6 | |||||||||||||||||||||
| 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 | (29) | (14) | (9) | ||||||||||||||||||
| Accrued unbilled revenues | (0.6 | ) | 15.3 | (10.4 | ) | Accrued unbilled revenues | (10) | — | (1) | |||||||||||||||||||
| Inventories | (20.5 | ) | (16.0 | ) | (1.9 | ) | Inventories | (21) | (35) | (21) | ||||||||||||||||||
| Prepayments and other | 2.8 | 0.5 | 4.3 | Prepayments and other | 16 | (14) | 3 | |||||||||||||||||||||
| Accounts payable | (8.5 | ) | (6.6 | ) | 11.8 | Accounts payable | 4 | 8 | (9) | |||||||||||||||||||
| Net regulatory assets and liabilities | 13.8 | 38.2 | 38.1 | Net regulatory assets and liabilities | (154) | (115) | 14 | |||||||||||||||||||||
| Other current liabilities | 5.8 | 11.6 | 3.4 | Other current liabilities | (1) | 13 | 6 | |||||||||||||||||||||
| Pension and other employee benefit obligations | (17.7 | ) | (16.0 | ) | (21.7 | ) | Pension and other employee benefit obligations | (18) | (16) | (18) | ||||||||||||||||||
| Other, net | 3.5 | 5.8 | (19.9 | ) | Other, net | (4) | (1) | 5 | ||||||||||||||||||||
| Net cash provided by operating activities | 472.8 | 446.3 | 470.5 | Net cash provided by operating activities | 359 | 414 | 473 | |||||||||||||||||||||
| Investing activities | Investing activities | |||||||||||||||||||||||||||
| Utility capital/construction expenditures | (844.4 | ) | (1,020.9 | ) | (550.6 | ) | Utility capital/construction expenditures | (580) | (1,142) | (844) | ||||||||||||||||||
| Investments in utility money pool arrangement | (133.0 | ) | (285.0 | ) | (142.0 | ) | Investments in utility money pool arrangement | (83) | (4) | (133) | ||||||||||||||||||
| Receipts from utility money pool arrangement | 133.0 | 350.0 | 77.0 | Receipts from utility money pool arrangement | 83 | 4 | 133 | |||||||||||||||||||||
| Other | — | — | (0.5 | ) | ||||||||||||||||||||||||
| Net cash used in investing activities | (844.4 | ) | (955.9 | ) | (616.1 | ) | Net cash used in investing activities | (580) | (1,142) | (844) | ||||||||||||||||||
| Financing activities | Financing activities | |||||||||||||||||||||||||||
| (Repayments of) proceeds from short-term borrowings, net | (42.0 | ) | 42.0 | (50.0 | ) | (Repayments of) proceeds from short-term borrowings, net | (113) | 250 | (42) | |||||||||||||||||||
| 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 issuance of long-term debt, net | Proceeds from issuance of long-term debt, net | 247 | 343 | 292 | ||||||||||||||||||||||||
| Borrowings under utility money pool arrangement | 296.0 | 595.0 | 335.0 | Borrowings under utility money pool arrangement | 539 | 561 | 296 | |||||||||||||||||||||
| Repayments under utility money pool arrangement | (296.0 | ) | (595.0 | ) | (335.0 | ) | Repayments under utility money pool arrangement | (448) | (561) | (296) | ||||||||||||||||||
| Capital contributions from parent | 426.3 | 336.8 | 143.7 | Capital contributions from parent | 301 | 438 | 426 | |||||||||||||||||||||
| Dividends paid to parent | (332.7 | ) | (131.0 | ) | (108.8 | ) | Dividends paid to parent | (310) | (313) | (333) | ||||||||||||||||||
| Net cash provided by financing activities | 343.8 | 542.8 | 155.6 | Net cash provided by financing activities | 216 | 718 | 343 | |||||||||||||||||||||
| 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 | (5) | (10) | (28) | ||||||||||||||||||||||||
| Cash, cash equivalents and restricted cash at beginning of period | Cash, cash equivalents and restricted cash at beginning of period | 6 | 16 | 44 | ||||||||||||||||||||||||
| Cash, cash equivalents and restricted cash at end of period | Cash, cash equivalents and restricted cash at end of period | $ | 1 | $ | 6 | $ | 16 | |||||||||||||||||||||
| 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) | $ | (108) | $ | (98) | $ | (84) | ||||||||||||
| Cash received (paid) for income taxes, net | 11.9 | (10.6 | ) | 41.5 | ||||||||||||||||||||||||
| 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 | |||||||||||||||||||||||||
| Cash received for income taxes, net | Cash received for income taxes, net | 21 | 10 | 12 | ||||||||||||||||||||||||
| 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 | $ | 37 | $ | 99 | $ | 95 | |||||||||||||||||||||
| Inventory transfers to property, plant and equipment | Inventory transfers to property, plant and equipment | 6 | 31 | 23 | ||||||||||||||||||||||||
| Operating lease right-of-use assets | 548.3 | — | — | Operating lease right-of-use assets | — | — | 548 | |||||||||||||||||||||
| Allowance for equity funds used during construction | 26.8 | 19.1 | 9.3 | Allowance for equity funds used during construction | 4 | 33 | 27 | |||||||||||||||||||||
See Notes to Financial Statements
23
SOUTHWESTERN PUBLIC SERVICE CO.
BALANCE SHEETS
(amounts in millions, except share and per share data)
| Dec. 31 | Dec. 31 | |||||||||||||||||||||
| 2019 | 2018 | 2021 | 2020 | |||||||||||||||||||
| Assets | Assets | |||||||||||||||||||||
| Current assets | Current assets | |||||||||||||||||||||
| Cash and cash equivalents | $ | 16.2 | $ | 44.0 | Cash and cash equivalents | $ | 1 | $ | 6 | |||||||||||||
| Accounts receivable, net | 92.7 | 90.7 | Accounts receivable, net | 115 | 94 | |||||||||||||||||
| Accounts receivable from affiliates | 4.2 | 10.5 | Accounts receivable from affiliates | 9 | 9 | |||||||||||||||||
| Investments in money pool arrangements | — | — | ||||||||||||||||||||
| Accrued unbilled revenues | 115.1 | 114.5 | Accrued unbilled revenues | 125 | 114 | |||||||||||||||||
| Inventories | 31.0 | 33.9 | Inventories | 51 | 36 | |||||||||||||||||
| Regulatory assets | 20.0 | 26.0 | Regulatory assets | 193 | 76 | |||||||||||||||||
| Derivative instruments | 15.0 | 17.8 | Derivative instruments | 30 | 10 | |||||||||||||||||
| Prepaid taxes | 0.8 | 14.2 | Prepaid taxes | 3 | 18 | |||||||||||||||||
| Prepayments and other | 21.4 | 10.7 | Prepayments and other | 21 | 20 | |||||||||||||||||
| Total current assets | 316.4 | 362.3 | Total current assets | 548 | 383 | |||||||||||||||||
| Property, plant and equipment, net | 6,631.6 | 5,946.4 | Property, plant and equipment, net | 7,838 | 7,603 | |||||||||||||||||
| Other assets | Other assets | |||||||||||||||||||||
| Regulatory assets | 364.0 | 366.2 | Regulatory assets | 380 | 357 | |||||||||||||||||
| Derivative instruments | 12.6 | 15.8 | Derivative instruments | 6 | 9 | |||||||||||||||||
| Operating lease right-of-use assets | 522.4 | — | Operating lease right-of-use assets | 463 | 492 | |||||||||||||||||
| Other | 3.9 | 5.1 | Other | 27 | 15 | |||||||||||||||||
| Total other assets | 902.9 | 387.1 | Total other assets | 876 | 873 | |||||||||||||||||
| Total assets | $ | 7,850.9 | $ | 6,695.8 | Total assets | $ | 9,262 | $ | 8,859 | |||||||||||||
| Liabilities and Equity | Liabilities and Equity | |||||||||||||||||||||
| Current liabilities | Current liabilities | |||||||||||||||||||||
| Short-term debt | $ | — | $ | 42.0 | Short-term debt | $ | 137 | $ | 250 | |||||||||||||
| Borrowings under utility money pool arrangement | Borrowings under utility money pool arrangement | 91 | — | |||||||||||||||||||
| Accounts payable | 168.1 | 191.8 | Accounts payable | 172 | 198 | |||||||||||||||||
| Accounts payable to affiliates | 20.4 | 19.9 | Accounts payable to affiliates | 16 | 17 | |||||||||||||||||
| Regulatory liabilities | 118.1 | 85.8 | Regulatory liabilities | 54 | 57 | |||||||||||||||||
| Taxes accrued | 40.4 | 41.6 | Taxes accrued | 47 | 54 | |||||||||||||||||
| Accrued interest | 26.2 | 25.8 | Accrued interest | 30 | 29 | |||||||||||||||||
| Dividends payable | 46.3 | 45.2 | ||||||||||||||||||||
| Dividends payable to parent | Dividends payable to parent | 58 | 54 | |||||||||||||||||||
| Derivative instruments | 3.7 | 3.6 | Derivative instruments | 4 | 4 | |||||||||||||||||
| Operating lease liabilities | 26.9 | — | Operating lease liabilities | 30 | 28 | |||||||||||||||||
| Other | 30.7 | 28.3 | Other | 24 | 25 | |||||||||||||||||
| Total current liabilities | 480.8 | 484.0 | Total current liabilities | 663 | 716 | |||||||||||||||||
| Deferred credits and other liabilities | Deferred credits and other liabilities | |||||||||||||||||||||
| Deferred income taxes | 671.8 | 619.1 | Deferred income taxes | 702 | 725 | |||||||||||||||||
| Regulatory liabilities | 732.3 | 780.9 | Regulatory liabilities | 709 | 718 | |||||||||||||||||
| Asset retirement obligations | 77.3 | 32.4 | Asset retirement obligations | 116 | 112 | |||||||||||||||||
| Derivative instruments | 12.8 | 16.4 | Derivative instruments | 6 | 9 | |||||||||||||||||
| Pension and employee benefit obligations | 67.0 | 92.4 | Pension and employee benefit obligations | 8 | 42 | |||||||||||||||||
| Operating lease liabilities | 495.3 | — | Operating lease liabilities | 434 | 463 | |||||||||||||||||
| Other | 9.4 | 7.9 | Other | 8 | 12 | |||||||||||||||||
| Total deferred credits and other liabilities | 2,065.9 | 1,549.1 | Total deferred credits and other liabilities | 1,983 | 2,081 | |||||||||||||||||
| Commitments and contingencies | Commitments and contingencies | 0 | 0 | |||||||||||||||||||
| Capitalization | Capitalization | |||||||||||||||||||||
| Long-term debt | 2,419.7 | 2,126.1 | Long-term debt | 3,013 | 2,764 | |||||||||||||||||
| 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, 2021 and Dec. 31, 2020, respectively | Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2021 and Dec. 31, 2020, respectively | — | — | |||||||||||||||||||
| Additional paid in capital | 2,350.9 | 1,932.3 | Additional paid in capital | 3,091 | 2,790 | |||||||||||||||||
| Retained earnings | 535.0 | 605.7 | Retained earnings | 513 | 509 | |||||||||||||||||
| 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 | 3,603 | 3,298 | |||||||||||||||||||
| Total liabilities and equity | $ | 7,850.9 | $ | 6,695.8 | Total liabilities and equity | $ | 9,262 | $ | 8,859 | |||||||||||||
See Notes to Financial Statements
24
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 | |||||||||||||||||||||||||||||||||||||||||||||
| Net income | 213.3 | 213.3 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive loss | 0.1 | 0.1 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Common dividends declared to parent | (149.2 | ) | (149.2 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Contribution of capital by parent | 342.1 | 342.1 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at Dec. 31, 2018 | 100 | $ | — | $ | 1,932.3 | $ | 605.7 | $ | (1.4 | ) | $ | 2,536.6 | Balance at Dec. 31, 2018 | 100 | $ | — | $ | 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 | $ | — | $ | 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 | $ | — | $ | 2,790 | $ | 509 | $ | (1) | $ | 3,298 | |||||||||||||||||||||||||||||||||||||||||||||
| Net income | Net income | 318 | 318 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Common dividends declared to parent | Common dividends declared to parent | (314) | (314) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Contribution of capital by parent | Contribution of capital by parent | 301 | 301 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at Dec. 31, 2021 | Balance at Dec. 31, 2021 | 100 | $ | — | $ | 3,091 | $ | 513 | $ | (1) | $ | 3,603 | |||||||||||||||||||||||||||||||||||||||||||||
See Notes to Financial Statements
25
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, 20192021 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 onfor 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 an evaluation of whether future recovery is expected.
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 ITCsinvestment tax credits 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.
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SPS records depreciation expense using the straight-line method over the plant’s commission-approved 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 is based on current factors used in existing depreciation rates. Depreciation expense, expressed as a percentage of average depreciable property, was 3.3% in 2021, 3.1% in 2020 and 2.9% in 2019, 2.9% in 2018 and 2.8% in 2017.2019.
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 anFor certain environmental expense iscosts related to facilities currently in use, such as for 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 three3 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, 20192021 and 2018,2020, the allowance for bad debts was $5.3$12 million and $5.6$8 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, 2021 | Dec. 31, 2020 | ||||||||||||
| Inventories | ||||||||||||||
| Materials and supplies | $ | 29 | $ | 27 | ||||||||||
| Fuel | 22 | 9 | ||||||||||||
| Total inventories | $ | 51 | $ | 36 | ||||||||||
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.
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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.mandate or from other instances where the regulator authorizes a future surcharge in response to past activities or completed events. 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 and purchased power costs for the cost of RECs and records that costreceived. An inventory accounting model is used to account for RECs recognized on the balance sheet, however these assets are classified as a regulatory asset when the amount isassets if amounts are 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.
| 3. Property, Plant and Equipment | ||
Major classes of property, plant and equipment
| (Millions of Dollars) | Dec. 31, 2021 | Dec. 31, 2020 | ||||||||||||
| Property, plant and equipment, net | ||||||||||||||
| Electric plant | $ | 9,639 | $ | 9,229 | ||||||||||
Plant to be retired (a) | 299 | 316 | ||||||||||||
| CWIP | 171 | 146 | ||||||||||||
| Total property, plant and equipment | 10,109 | 9,691 | ||||||||||||
| Less accumulated depreciation | (2,271) | (2,088) | ||||||||||||
| Property, plant and equipment, net | $ | 7,838 | $ | 7,603 | ||||||||||
| (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 | ||||