Company Quick10K Filing
Southwestern Public Service
Price-0.01 EPS2,180,000
Shares0 P/E-0
MCap-0 P/FCF-0
Net Debt2,272 EBIT327
TTM 2019-09-30, in MM, except price, ratios
10-K 2020-12-31 Filed 2021-02-17
10-Q 2020-09-30 Filed 2020-10-29
10-Q 2020-06-30 Filed 2020-07-31
10-Q 2020-03-31 Filed 2020-05-07
10-K 2019-12-31 Filed 2020-02-21
10-Q 2019-09-30 Filed 2019-10-25
10-Q 2019-06-30 Filed 2019-08-01
10-Q 2019-03-31 Filed 2019-04-26
10-K 2018-12-31 Filed 2019-02-22
10-Q 2018-09-30 Filed 2018-10-26
10-Q 2018-06-30 Filed 2018-07-27
10-Q 2018-03-31 Filed 2018-04-27
10-K 2017-12-31 Filed 2018-02-23
10-Q 2017-09-30 Filed 2017-10-27
10-Q 2017-06-30 Filed 2017-07-28
10-Q 2017-03-31 Filed 2017-04-28
10-K 2016-12-31 Filed 2017-02-24
10-Q 2016-09-30 Filed 2016-10-31
10-Q 2016-06-30 Filed 2016-08-04
10-Q 2016-03-31 Filed 2016-05-13
10-K 2015-12-31 Filed 2016-02-22
10-Q 2015-09-30 Filed 2015-11-02
10-Q 2015-06-30 Filed 2015-08-03
10-Q 2015-03-31 Filed 2015-05-04
10-K 2014-12-31 Filed 2015-02-23
10-Q 2014-09-30 Filed 2014-11-03
10-Q 2014-06-30 Filed 2014-08-01
10-Q 2014-03-31 Filed 2014-05-05
10-K 2013-12-31 Filed 2014-02-24
10-Q 2013-09-30 Filed 2013-10-28
10-Q 2013-06-30 Filed 2013-08-05
10-Q 2013-03-31 Filed 2013-05-06
10-K 2012-12-31 Filed 2013-02-25
10-Q 2012-09-30 Filed 2012-10-29
10-Q 2012-06-30 Filed 2012-08-06
10-Q 2012-03-31 Filed 2012-04-30
10-K 2011-12-31 Filed 2012-02-27
10-Q 2011-09-30 Filed 2011-10-31
10-Q 2011-06-30 Filed 2011-08-01
10-Q 2011-03-31 Filed 2011-05-02
10-K 2010-12-31 Filed 2011-02-28
10-Q 2010-09-30 Filed 2010-11-01
10-Q 2010-06-30 Filed 2010-08-02
10-Q 2010-03-31 Filed 2010-05-03
10-K 2009-12-31 Filed 2010-03-01
8-K 2020-05-18
8-K 2020-01-14
8-K 2019-11-22
8-K 2019-10-24
8-K 2019-08-30
8-K 2019-08-08
8-K 2019-08-01
8-K 2019-07-01
8-K 2019-06-18
8-K 2019-06-07
8-K 2019-04-25
8-K 2019-02-15
8-K 2019-01-31
8-K 2018-11-05
8-K 2018-10-25
8-K 2018-07-26
8-K 2018-04-26
8-K 2018-02-07

SPS 10K Annual Report

Part I
Item 1A - Risk Factors
Item 1B - Unresolved Staff Comments
Item 2 - Properties
Item 3 - Legal Proceedings
Item 4 - Mine Saftey Disclosures
Part II
Item 5 - Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6 - Selected Financial Data
Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A - Quantitative and Qualitative Disclosures About Market Risk
Item 8 - Financial Statements and Supplementary Data
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A - Controls and Procedures
Item 9B - Other Information
Part III
Item 10 - Directors, Executive Officers and Corporate Governance
Item 11 - Executive Compensation
Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13 - Certain Relationships and Related Transactions, and Director Independence
Item 14 - Principal Accountant Fees and Services
Part IV
Item 15 - Exhibit and Financial Statement Schedules
Item 16 - Form 10 - K Summary
EX-23.01 spsex230110-k2020.htm
EX-31.01 spsex310110-k2020.htm
EX-31.02 spsex310210-k2020.htm
EX-32.01 spsex320110-k2020.htm

Southwestern Public Service Earnings 2020-12-31

Balance SheetIncome StatementCash Flow
Assets, Equity
Rev, G Profit, Net Income
Ops, Inv, Fin

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Washington, D.C.  20549
(Mark One)
For the fiscal year ended December 31, 2020 or
(Commission File Number)
(Exact name of registrant as specified in its charter)
New Mexico
(State or Other Jurisdiction of Incorporation or Organization)(IRS Employer Identification No.)
790 South Buchanan Street,
   (Address of Principal Executive Offices)(Zip Code)
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading SymbolName of each exchange on which registered
Securities registered pursuant to Section 12(g) of the Act:  None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.   Yes  No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.   Yes  No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes    No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).   Yes   No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated Filer  Accelerated Filer  Non-accelerated Filer Smaller Reporting Company Emerging Growth Company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).   Yes    No
As of Feb. 17, 2021, 100 shares of common stock, par value $1.00 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.
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 2021 Annual Meeting of Shareholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 6, 2021. Such information set forth under such heading is incorporated herein by this reference hereto.
Southwestern Public Service Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).

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Item 11 —
Item 12 —
Item 13 —
Item 14 —
Item 15 —
Item 16 —

This Form 10-K is filed by Southwestern Public Service Company, a New Mexico corporation (SPS). SPS is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available on various filings with the Securities and Exchange Commission. This report should be read in its entirety.

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Definitions of Abbreviations
Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
NSP-MinnesotaNorthern States Power Company, a Minnesota corporation
NSP-WisconsinNorthern States Power Company, a Wisconsin corporation
PSCoPublic Service Company of Colorado
SPSSouthwestern Public Service Company
Utility subsidiariesNSP-Minnesota, NSP-Wisconsin, PSCo and SPS
Xcel EnergyXcel Energy Inc. and its subsidiaries
Federal and State Regulatory Agencies
D.C. CircuitUnited States Court of Appeals for the District of Columbia Circuit
EPAUnited States Environmental Protection Agency
FERCFederal Energy Regulatory Commission
IRSInternal Revenue Service
NERCNorth American Electric Reliability Corporation
NMPRCNew Mexico Public Regulation Commission
PHMSAPipeline and Hazardous Materials Safety Administration
PUCTPublic Utility Commission of Texas
SECSecurities and Exchange Commission
TCEQTexas Commission on Environmental Quality
Electric and Resource Adjustment Clauses
DCRFDistribution cost recovery factor
DSMDemand side management
EECRFEnergy efficiency cost recovery factor
FPPCACFuel and purchased power cost adjustment clause
PCRFPower cost recovery factor
RPSRenewable portfolio standards
TCRFTransmission cost recovery factor (recovers transmission infrastructure improvement costs and changes in wholesale transmission charges)
ADITAccumulated deferred income taxes
AFUDCAllowance for funds used during construction
ALJAdministrative Law Judge
AROAsset retirement obligation
ASCFASB Accounting Standards Codification
ASUFASB Accounting Standards Update
BARTBest available retrofit technology
CEOChief executive officer
CFOChief financial officer
C&ICommercial and Industrial
COVID-19Novel coronavirus
CWIPConstruction work in progress
DSMDemand side management
ELGEffluent limitations guidelines
ETREffective tax rate
FASBFinancial Accounting Standards Board
FTRFinancial transmission right
GAAPGenerally accepted accounting principles
GHGGreenhouse gas
IMIntegrated Marketplace
IPPIndependent power producing entity
IRPIntegrated Resource Plan
ITCInvestment tax credit
MGPManufactured gas plant
Moody’sMoody’s Investor Services
NAAQSNational Ambient Air Quality Standard
Native loadCustomer demand of retail and wholesale customers whereby a utility has an obligation to serve under statute or long-term contract
NAVNet asset value
NOLNet operating loss
O&MOperating and maintenance
OATTOpen Access Transmission Tariff
PPAPurchased power agreement
PTCProduction tax credit
RECRenewable energy credit
ROEReturn on equity
RTORegional Transmission Organization
SERPSupplemental executive retirement plan
Sulfur dioxide
SPPSouthwest Power Pool, Inc.
S&PStandard & Poor’s Global Ratings
TCJA2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act
VIEVariable interest entity
WOTUSWaters of the U.S.
KWhKilowatt hours
MMBtuMillion British thermal units
MWhMegawatt hours

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 future sales, future bad debt expense, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings and expectations regarding regulatory proceedings, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information.

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The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2020 (including risk factors listed from time to time by SPS in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K hereto), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: uncertainty around the impacts and duration of the COVID-19 pandemic; operational safety; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee work force and third-party contractor factors; ability to recover costs; changes in regulation; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of SPS to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; 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.
Where to Find More Information
SPS is a wholly owned subsidiary of Xcel Energy Inc., and Xcel Energy’s website address is 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 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 customers0.4 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$8.9 billion
Rate Base (estimated)$5.4 billion
ROE (net income / average stockholder's equity)9.54%
Electric generating capacity5,232 MW
Electric transmission lines (conductor miles)40,019 miles
Electric distribution lines (conductor miles)21,984 miles
Electric Operations
Electric operations consist of energy supply, generation, transmission and distribution activities. SPS had electric sales volume of 31,084 (millions of KWh), 0.4 million customers and electric revenues of $1,870 (millions of dollars) for 2020.


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Sales/Revenue Statistics (a)
KWH sales per retail customer51,694 53,123 
Revenue per retail customer$2,925 $3,147 
Residential revenue per KWh9.77 ¢10.04 ¢
Large C&I revenue per KWh3.65 ¢4.01 ¢
Small C&I revenue per KWh6.99 ¢7.17 ¢
Total retail revenue per KWh5.66 ¢5.92 ¢
(a) See Note 6 to the financial statements for further information.
Owned and Purchased Energy Generation — 2020
Electric Energy Sources
Total electric generation by source (including energy market purchases) for the year ended Dec. 31, 2020:
*Distributed generation from the Solar*Rewards® program is not included (approximately 14 million KWh for 2020).
Carbon–Free Energy
SPS’ carbon–free energy portfolio includes wind and solar power from both owned generating facilities and PPAs. Carbon–free percentages will vary year over year based on system additions, weather, system demand and transmission constraints.
See Item 2 — Properties for further information.
Carbon–free energy as a percentage of total energy for 2020:

Owned — Owned and operated wind farms with corresponding capacity:
Wind Farms
Capacity (a)
Wind Farms
Capacity (b)
2967 MW1460 MW
(a) Summer 2020 net dependable capacity.
(b) Summer 2019 net dependable capacity.
PPAs — Number of PPAs with capacity range:
181 MW — 250 MW181 MW — 250 MW
Capacity — Wind capacity:
2,535 MW2,027 MW
Average Cost (Owned) — Average cost per MWh of wind energy from owned generation:
Average Cost (PPAs) — Average cost per MWh of wind energy under existing PPAs:
Wind Development
SPS placed approximately 500 MW of owned wind into service during 2020:
Capacity (a)(b)
Sagamore507 MW
(a)Summer 2020 net dependable capacity.
(b)Values disclosed are the maximum generation levels for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).
Solar energy PPAs:
Distributed Generation11 MW
Utility-Scale190 MW
Total 201 MW
Average Cost (PPAs) — Average cost per MWh of solar energy under existing PPAs:
Fossil Fuel Energy
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.
SPS owns and operates coal units with approximately 2,100 MW of total 2020 net summer dependable capacity.


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Approved and proposed early coal plant retirements:
Approved / Authorized
YearPlant UnitCapacity
Harrington (a)
1,018 MW
(a)Reflects expected conversion from coal to natural gas following the TCEQ order that Harrington cease use of coal fuel by Jan. 1, 2025, pending PUCT and NMPRC review.
YearPlant UnitCapacity
2032Tolk 1532 MW
2032Tolk 2535 MW
Coal Fuel Cost
Delivered cost per MMBtu of coal consumed for owned electric generation and percentage of total fuel requirements:
2020$2.28 40 %
20192.19 45 
Natural Gas
SPS has eight natural gas plants with approximately 2,200 MW of total 2020 net summer dependable capacity.
Natural gas supplies, transportation and storage services for power plants are procured to provide an adequate supply of fuel. Remaining requirements are procured through a liquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to natural gas indices. Natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes or payments in lieu of delivery.
Natural Gas Cost
Delivered cost per MMBtu of natural gas consumed for owned electric generation and percentage of total fuel requirements:
Natural Gas
2020$1.43 60 %
20191.14 55 
Capacity and Demand
Uninterrupted system peak demand and occurrence date:
System Peak Demand (in MW)
4,195 July 144,261 Aug. 5
Transmission lines deliver electricity over long distances from power sources to transmission substations closer to homes and businesses. A strong transmission system ensures continued reliable and affordable service, ability to meet state and regional energy policy goals, and support for a diverse generation mix, including renewable energy. SPS owns more than 40,000 conductor miles of transmission lines across its service territory.

During 2020, SPS completed the following transmission projects:
TUCO-Yoakum Co.107 345 KV
Eddy Co.-Kiowa34 345 KV
Mustang-Seminole20 115 KV
Loving South-Phantom21 115 KV
Upcoming transmission projects:
ProjectMilesSizeCompletion Date
Roadrunner-China Draw41 345 KV2021
Distribution lines allow electricity to travel at lower voltages from substations directly to homes and businesses. SPS has a vast distribution network, owning and operating approximately 22,000 conductor miles of distribution lines across our service territory, both above ground and underground. To continue providing reliable, affordable electric service and enable more flexibility for customers, we are working to digitize the distribution grid, while at the same time keeping it secure.
See Item 2 - Properties for further information.
Public Utility Regulation
See Item 7 for discussion of public utility regulation.
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.
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 system of SPS on a comparable basis to serve their native load.

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FERC Order No. 1000 established competition for construction and operation of certain new electric transmission facilities. State utilities commissions have also created resource planning programs that promote competition for electricity generation resources used to provide service to retail customers.
SPS has franchise agreements with cities subject to periodic renewal; however, a city could seek alternative means to access electric power, such as municipalization. No municipalization activities are occurring presently.
While facing these challenges, SPS believes its rates and services are competitive with alternatives currently available.
Environmental Regulation
Our facilities are regulated by federal and state agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous 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 operate in compliance with applicable environmental standards and related monitoring and reporting requirements. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to 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 present/future environmental regulations to encourage use of clean energy technologies and regulate emissions of GHGs. SPS has undertaken numerous initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. Future environmental regulations may result in substantial costs.
In July 2019, the EPA adopted the Affordable Clean Energy rule, which required states to develop plans by 2022 for GHG reductions from coal-fired power plants. In a Jan. 19, 2021 decision, the U.S. Court of Appeals for the D.C. Circuit issued a decision vacating and remanding the Affordable Clean Energy rule. That decision, if not successfully appealed or reconsidered, would allow the EPA to proceed with alternate regulation of coal-fired power plants, either reviving the Clean Power Plan or proposing additional regulation. It is too early to predict an outcome, but new rules could require substantial additional investment, even in plants slated for retirement. SPS believes, based on prior state commission practices, the cost of these initiatives or replacement generation would be recoverable through rates.
In October 2020, the TCEQ approved an agreement that ensures SPS will convert the Harrington plant from coal to natural gas by Jan. 1, 2025. This conversion is necessary to attain Federal Clean Air Act standards for emissions of SO2.
SPS seeks to address climate change and potential climate change regulation through efforts to reduce its GHG emissions in a balanced, cost-effective manner.
As of Dec. 31, 2020, SPS had 1,141 full-time employees and no part-time employees, of which 769 were covered under collective-bargaining agreements.
Xcel Energy, which includes SPS, is subject to a variety of risks, many of which are beyond our control. Risks that may adversely affect the business, financial condition, results of operations or cash flows are described below. These risks should be carefully considered together with the other information set forth in this report and future reports that Xcel Energy files with the SEC.
Oversight of Risk and Related Processes
SPS’ Board of Directors is responsible for the oversight of material risk and maintaining an effective risk monitoring process. Management and the Board of Directors have responsibility for overseeing the identification and mitigation of key risks.
At a threshold level, SPS maintains a robust compliance program through promoting a culture of compliance beginning with the tone at the top. The risk mitigation process includes adherence to our code of conduct and compliance policies, operation of formal risk management structures and overall business management. SPS further mitigates inherent risks through formal risk committees and corporate functions such as internal audit, and internal controls over financial reporting and legal.
Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Identification and risk analysis occurs formally through risk assessment conducted by senior management, the financial disclosure process, hazard risk procedures, internal audit and compliance with financial and operational controls.
Management also identifies and analyzes risk through the business planning process, development of goals and establishment of key performance indicators, including identification of barriers to implementing our strategy. The business planning process also identifies likelihood and mitigating factors to prevent the assumption of inappropriate risk to meet goals.
Management communicates regularly with the Board of Directors and its sole stockholder regarding risk. Senior management presents and communicates a periodic risk assessment to the Board of Directors, providing information on the risks that management believes are material, including financial impact, timing, likelihood and mitigating factors. The Board of Directors regularly reviews management’s key risk assessments, which includes areas of existing and future financial, operational and security risks.
Overall, the oversight, management and mitigation of risk is an integral and continuous part of the Board of Directors’ governance of SPS. Processes are in place to ensure appropriate risk oversight, as well as identification and consideration of new risks.

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Risks Associated with Our Business
Operational Risks
Our electric transmission and distribution and involve numerous risks that may result in accidents and other operating risks and costs.
Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses. Our natural gas transmission activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. We maintain insurance against some, but not all, of these risks and losses. The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations and cash flows.
Other uncertainties and risks inherent in operating and maintaining SPS’ facilities include, but are not limited to:
Risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned.
Failures in the availability, acquisition or transportation of fuel or other necessary supplies.
The impact of unusual or adverse weather conditions and natural disasters, including, but not limited to, tornadoes, icing events, floods and droughts.
Performance below expected or contracted levels of output or efficiency (e.g., performance guarantees).
Availability of replacement equipment.
Availability of adequate water resources and ability to satisfy water intake and discharge requirements.
Inability to identify, manage properly or mitigate equipment defects.
Use of new or unproven technology.
Risks associated with dependence on a specific type of fuel or fuel source, such as commodity price risk, availability of adequate fuel supply and transportation and lack of available alternative fuel sources.
Increased competition due to, among other factors, new facilities, excess supply, shifting demand and regulatory changes.
Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the Department of Transportation’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with these 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 electric transmission and distribution operations and natural gas transmission operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services.
Our utility operations are subject to long-term planning and project risks.
Most electric utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of 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 significant change (e.g, increases in energy efficiency, wider adoption of distributed generation and shifts away from fossil fuel generation to renewable generation).
Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, and potentially stranded costs if we are not able to fully recover costs and investments.
Changing customer expectations and technologies are requiring significant investments in advanced grid infrastructure, which increases exposure to technology obsolescence. Additionally, evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may put pressure on our ability to recover capital investments in natural gas generation and delivery.
The magnitude and timing of resource additions and changes in customer demand may not coincide with evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. Additionally, multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets.
We are subject to longer-term availability of inputs such as coal, natural gas and water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.
We are subject to commodity risks and other risks associated with energy markets and energy production.
In the event fuel costs increase, customer demand could decline and bad debt expense may rise, which may have a material impact on our results of operations. Despite existing fuel recovery mechanisms, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows 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.

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We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result, we are subject to market supply and commodity price risk.
Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability. The management of risks associated with hedging and trading is based, in part, on programs and procedures which utilize historical prices and trends.
Due to the inherent uncertainty involved in price movements and potential deviation from historical pricing, SPS is unable to fully assure that its risk management programs and procedures would be effective to protect against all significant adverse market deviations. In addition, SPS cannot fully assure that its controls will be effective against all potential risks, including, without limitation, employee misconduct. If such controls are not effective, SPS’ results of operations, financial condition or cash flows could be materially impacted.
Failure to attract and retain a qualified workforce could have an adverse effect on operations.
Specialized knowledge is required of our technical employees for construction and operation of transmission, generation and distribution assets. Our business strategy is dependent on our ability to recruit, retain and motivate employees. There is competition and a tightening market for skilled employees. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.
Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.
We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance standards, progress payments, insurance requirements and security for performance. Poor vendor performance could impact ongoing operations, restoration operations, our reputation and could introduce financial risk or risks of fines.
We are a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.
All of the members of our Board of Directors, as well as many of our executive officers, are officers of Xcel Energy Inc. Our Board or Directors makes determinations with respect to a number of significant corporate events, including the payment of our dividends.
We have historically paid quarterly dividends to Xcel Energy Inc. In 2020, 2019 and 2018 we paid $313 million, $333 million and $131 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs. This could adversely affect our liquidity. The most restrictive dividend limitation for SPS is imposed by its state regulatory commissions. State regulatory commissions indirectly limit the amount of dividends that
SPS can pay Xcel Energy Inc., by requiring a minimum equity-to-total capitalization ratio.
See Note 5 to the financial statements for further information.
Financial Risks
Our profitability depends on our ability to recover costs from our customers and changes in regulation may impair our ability to recover costs from our customers.
We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.
The profitability of our operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on our capital investment. Our rates are generally regulated and based on an analysis of our costs incurred in a test year. We are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates we are allowed to charge may or may not match our costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.
There can also be no assurance that our regulatory commissions will judge all our costs to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair our ability to recover costs historically collected from customers, or we could exceed caps on capital costs required by commissions and result in less than full recovery.
Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.
In a continued low interest rate environment there has been increased downward pressure on allowed ROE. Conversely, higher than expected inflation or tariffs may increase costs of construction and operations. Also, rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers.
Adverse regulatory rulings or the imposition of additional regulations could have an adverse impact on our results of operations and materially affect our ability to meet our financial obligations, including debt payments.
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.
We cannot be assured that our current credit ratings will remain in effect, or that a rating will not be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, lower returns on equity, changes to equity ratios and impacts of tax policy may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.
Any credit ratings downgrade could lead to higher borrowing costs and could impact our ability to access capital markets. Also, we may enter into contracts that require posting of collateral or settlement if credit ratings fall below investment grade.

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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. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital market disruption and financial market distress could prevent us from issuing short-term commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results.
We are subject to credit risks.
Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the economy and unemployment rates. Credit risk also includes the risk that 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 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, (e.g., SPP, PJM Interconnection, LLC, Midcontinent Independent System Operator, Inc. and Electric Reliability Council of Texas), in which any credit losses are socialized to all market participants.
We have additional indirect credit exposure to financial institutions from 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 S&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, 2020, Xcel Energy Inc. and its utility subsidiaries had approximately $19.6 billion of long-term debt and $1.0 billion of short-term debt and current maturities. Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.
Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees.
As of Dec. 31, 2020, Xcel Energy had guarantees outstanding with a $2 million maximum stated amount and immaterial exposure. Xcel Energy also had additional guarantees of $60 million at Dec. 31, 2020 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 of these plans. Estimates and assumptions may change. In addition, the Pension Protection Act sets the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and 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 obligations 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 estimated federal, state and local tax 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. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases 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.

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We operate in a capital intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates.
We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.
The global outbreak of COVID-19 is impacting countries, communities, supply chains and markets. A high degree of uncertainty continues to exist regarding the pandemic, the duration and magnitude of business restrictions, re-shut downs, if any, and the level and pace of economic recovery. While we are implementing contingency plans, there are no guarantees these plans will be sufficient to offset the impact of COVID-19.
Although the impact of the pandemic to the 2020 results was largely mitigated due to management’s actions, we cannot ultimately predict whether it will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact of the virus on the health of our employees, our supply chain or our ability to recover higher costs associated with managing through the pandemic. The impact of COVID-19 may exacerbate other risks discussed herein, which could have a material effect on us. The situation is evolving and additional impacts may arise.
Operations could be impacted by war, terrorism or other events.
Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows.
The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have already incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.
A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, 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 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 workforce disruption.
In addition, major catastrophic events throughout the world may disrupt our business. Xcel Energy participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to reliably serve our customers.
A major disruption could result in a significant decrease in revenues and additional costs to repair assets, which could have a material impact on our results of operations, financial condition or cash flows. SPS participates in grid security and emergency response exercises (GridEx). These efforts, led by the NERC, test and further develop the coordination, threat sharing and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid.
A cyber incident or security breach could have a material effect on our business.
We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors and other individuals.
Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error. Our industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States and individuals. Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability.
Our generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers’ operations, could also negatively impact our business.
Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. Cyber security incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.
We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including asset failure or unauthorized access to assets or information. A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability.
Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.
Our electric utility business is seasonal and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations, or cash flows.

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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 may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations.
In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. The Biden Administration will establish a new nationally determined contribution for the United States. The Paris Agreement could result in future additional GHG reductions in the United States. In addition, the Biden Administration has announced plans to implement new climate change programs, including potential regulation of GHG emissions targeting the utility industry.
The Biden Administration has also announced a one year suspension of new oil and natural gas drilling on federal lands to allow for a review of oil and gas leasing regulations. The form of these regulations is uncertain, but, depending on the requirements imposed in the short and long term, they could impose substantial costs on our oil and gas customers or result in substantial increases to the cost of fuel we use in our electricity and gas businesses.
Many states and localities continue to pursue their own climate policies. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation or retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies.
We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.
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 may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cyber or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows.
Environmental Risks
We are subject to environmental laws and regulations, with which compliance could be difficult and costly.
We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements.
Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. 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 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 O&M costs incurred to comply with the requirements.
In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.
We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.
Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events.
Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues.
Climate change may impact the 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.

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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 power plants and increase the cost for energy. We may not recover all costs related to mitigating these physical and financial risks.
Virtually all of the utility plant property of SPS is subject to the lien of its first mortgage bond indenture.
Station, Location and UnitFuelInstalled
MW (a)
Cunningham-Hobbs, NM, 2 UnitsNatural Gas1957 - 1965225 
Harrington-Amarillo, TX, 3 Units (b)
Coal1976 - 19801,018 
Jones-Lubbock, TX, 2 UnitsNatural Gas1971 - 1974486 
Maddox-Hobbs, NM, 1 UnitNatural Gas1967112 
Nichols-Amarillo, TX, 3 UnitsNatural Gas1960 - 1968457 
Plant X-Earth, TX, 4 UnitsNatural Gas1952 - 1964298 
Tolk-Muleshoe, TX, 2 Units (d)
Coal1982 - 19851,067 
Combustion Turbine:
Cunningham-Hobbs, NM, 2 UnitsNatural Gas1997207 
Jones-Lubbock, TX, 2 UnitsNatural Gas2011 - 2013334 
Maddox-Hobbs, NM, 1 UnitNatural Gas1963 - 197661 
Hale-Plainview, TX, 239 UnitsWind2019460 
Sagamore-Dora, NM, 240 UnitsWind2020507 
(a)    Summer 2020 net dependable capacity.
(b)    Harrington is expected to be converted to natural gas by the end of 2024.
(c)     Values disclosed are the generation levels at the point-of-interconnection for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero)
(d)    Tolk Unit 1 and 2 are expected to be retired in 2032.
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2020:
Conductor Miles
345 KV11,019 
230 KV9,795 
115 KV14,830 
Less than 115 KV4,375 
Total Transmission40,019 
Less than 115 KV21,984 
SPS had 457 electric utility transmission and distribution substations at Dec. 31, 2020.
Natural gas utility mains at Dec. 31, 2020:
SPS is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on SPS’ financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.
See Note 10 to the financial statements, Item 1 and Item 7 for further information.
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 2020 and 2019 were as follows:
(Millions of Dollars)20202019
First quarter$76 $58 
Second quarter55 84 
Third quarter136 114 
Fourth quarter54 78 

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Omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
Discussion of financial condition and liquidity for SPS is omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis and the results of operations for the current year as set forth in general instructions I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
Non-GAAP Financial Measures
The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as, electric margin and ongoing earnings. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from measures calculated and presented in accordance with GAAP.
SPS’ management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.
Electric Margins
Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues. Management believes electric margins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses. These margins can be reconciled to operating income, a GAAP measure, by including other operating revenues, cost of sales-other, O&M expenses, conservation and DSM expenses, depreciation and amortization and taxes (other than income taxes).
Earnings Adjusted for Certain Items (Ongoing Earnings)
Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. We use these non-GAAP financial measures to evaluate and provide details of SPS’ core earnings and underlying performance.
We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of SPS. For the years ended Dec. 31, 2020 and 2019, there were no adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings.
Results of Operations
2020 Comparison with 2019
SPS’ net income was $295 million for 2020, compared with net income of $263 million for 2019. The increase was primarily due to higher electric margin (wholesale transmission revenue and regulatory outcomes offset lower sales due to COVID-19) and lower O&M expenses, partially offset by increased depreciation, interest expense and taxes (other than income taxes).
Electric Margin
Electric fuel and purchased power expenses are impacted by fluctuations in the price of natural gas and coal. However, these fluctuations have minimal impact on margin due to fuel recovery mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and margin (offset by lower tax expense).
(Millions of Dollars)20202019
Electric revenues$1,870 $1,826 
Electric fuel and purchased power(835)(875)
Electric margin$1,035 $951 
The following tables summarize the components of the changes in electric margin for the year ended Dec. 31, 2020:
(Millions of Dollars)2020 vs. 2019
Regulatory rate outcomes (Texas and New Mexico) (a)
Wholesale transmission revenue (net)26 
Purchased capacity costs
Estimated impact of weather
PTCs flowed back to customers (offset by lower ETR)(42)
New Mexico tax reform related regulatory settlement (2019)(10)
Firm wholesale generation(9)
Sales and demand(8)
Other (net)
Total increase in electric margin$84 
(a)Includes approximately $70 million of revenue and margin due to the Texas rate case outcome, which is largely offset by recognition of previously deferred costs.
Non-Fuel Operating Expense and Other Items
O&M Expenses — O&M expense decreased $10 million, or 3.5%, for 2020 compared with the prior year. The decrease was due to management actions to reduce costs to offset the impact of lower sales from COVID-19, including allocation of workforce, material and supply management and timing of maintenance activities, as well as plant outages in 2019. The decrease was partially offset by an increase in wind related O&M expenses from our renewable expansion and recognition of previously deferred amounts related to the 2019 Texas Electric Rate Case.
Depreciation and Amortization — Depreciation and amortization expense increased $65 million, or 28.3%, for 2020 compared with the prior year. The increase was primarily driven by the Hale and Sagamore wind farms being placed into service in June 2019 and December 2020, respectively, in addition to system expansion. The increase is also due to new FERC transmission rates implemented in March 2020 and implementation of new depreciation rates in New Mexico and Texas as part of regulatory outcomes in 2020.
Interest Charges — Interest charges increased $20 million, or 20.2% for 2020 compared with the prior year. The increase was primarily due to higher debt levels to fund capital investments.

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Income Taxes — Income tax expense decreased $36 million for 2020. The decrease was primarily driven by an increase in wind PTCs and an increase in plant-related regulatory differences. Wind PTCs are largely credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income. The ETR was (3.5)% for 2020 compared with 9.0% for 2019, largely due to the adjustments referenced above.
Public Utility Regulation
The FERC and state and local regulatory commissions regulate SPS. SPS is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with 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. Our utility subsidiaries request changes in rates for utility services through filings with governing commissions. Changes in operating costs can affect SPS’ financial results, depending on the timing of rate case filings and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital.
In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact SPS’ results of operations.
See Rate Matters within Note 10 to the financial statements for further information.
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Regulatory Body / RTO
Additional Information
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.
Retail electric operations, retail rates and services and the construction of transmission or generation.
Wholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce.
SPP RTO and SPP IM Wholesale Market
SPS is a transmission owning member of the SPP RTO and operates within the SPP RTO and SPP IM wholesale market. SPS is authorized to make wholesale electric sales at market-based prices.
Recovery Mechanisms
Additional Information
Recovers distribution costs not included in rates in Texas.
Recovers costs for energy efficiency programs in Texas.
Energy Efficiency Rider
Recovers costs for energy efficiency programs in New Mexico.
Adjusts monthly to recover actual fuel and purchased power costs in New Mexico.
Allows recovery of purchased power costs not included in Texas rates.
Recovers deferred costs for renewable energy programs in New Mexico.
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
ProceedingAmount (in millions)Filing DateApproval
2019 New Mexico Electric Rate Case$31July 2019Received
2019 Texas Electric Rate Case88August 2019Received
2021 New Mexico Electric Rate Case88January 2021Pending
2021 Texas Electric Rate Case143February 2021Pending
Additional Information:
2019 New Mexico Electric Rate Case — In May 2020, the NMPRC approved a settlement between SPS and intervening parties, which reflects the following terms: a base rate increase of $31 million, an ROE of 9.45% and an equity ratio of 54.77%. New rates and tariffs were effective in May 2020.
2019 Texas Electric Rate Case — In August 2020, the PUCT approved a settlement between SPS and intervening parties, which reflects the following terms: a rate increase of $88 million; ROE of 9.45% and equity ratio of 54.62% for AFUDC purposes. In December 2020, SPS filed to surcharge the final under-recovered amount, estimated to be approximately $72 million, offset by the recognition of previously deferred costs.
2021 New Mexico Electric Rate Case — On Jan. 4, 2021, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately $88 million. SPS' net rate increase to New Mexico customers is expected to be approximately $48 million, or 10%, as a result of offsetting fuel cost reductions and PTCs attributable to wind energy provided by the Sagamore wind project. PTCs are being credited to customers through the fuel clause.
The request is based on a historic test year ended Sept. 30, 2020, including expected capital additions through Feb. 28, 2021, a ROE of 10.35%, an equity ratio of 54.72% and retail rate base of approximately $1.9 billion (total company rate base of approximately $6.0 billion).
Additionally, the request includes the effect of approximately 400 MW of reduced peak load in 2021 from a wholesale transmission customer and changes to depreciation rates to reflect a reduction to the service lives of SPS’ Tolk power plant (from 2037 to 2032) and the coal handling assets at the Harrington facility (to 2024).

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The NMPRC suspended new rates for nine months beyond the 30-day notice period, consistent with historic practice.
The next steps in the procedural schedule are expected to be as follows:
Staff and intervenor testimony — May 17, 2021.
Rebuttal testimony — June 9, 2021.
Deadline to file stipulation — June 23, 2021.
Public hearing or hearing on stipulation — July 26 - Aug. 6, 2021.
End of nine month suspension — Nov. 3, 2021.
A NMPRC decision and implementation of final rates is anticipated in the fourth quarter of 2021.
2021 Texas Rate Case — On Feb. 8, 2021, SPS filed an electric rate case with the PUCT and its 81 municipalities with original rate jurisdiction seeking an increase in base rates of approximately $143 million. SPS' net rate increase to Texas customers is expected to be approximately $74 million, or 9.2%, as a result of offsetting $69 million in fuel cost reductions and PTCs from the Sagamore wind project.
The request is primarily driven by additional capital investment in new and upgraded electric facilities and equipment since SPS’ previous rate case in 2019, including the 522 MW Sagamore wind project.
The request is based on an ROE of 10.35%, an equity ratio of 54.60% (based on actual capital structure), a Texas retail rate base of approximately $3.3 billion and a historic test year based on the 12-month period ended Dec. 31, 2020 (with the final three months based on estimates). In March 2021, SPS will file to update estimates to actuals through Dec. 31, 2020.
Additionally, the request includes the effect of approximately 400 MW from a wholesale transmission customer and changes to depreciation rates to reflect a reduction to the service lives of SPS’ Tolk power plant (from 2037 to 2032) and the coal handling assets of the Harrington facility (to 2024).
Summary of SPS’ request:
Rate Request (Millions of Dollars)
Sagamore wind project$67 
Other capital investments25 
Cost of capital20 
Property taxes
Reduced sales, partially offset by changes in O&M
Allocator changes
Depreciation rate change
Other, net
Total rate request$143 
Fuel cost reductions and PTCs — Sagamore wind project(69)
Net rate increase$74 
SPS is requesting the PUCT set current rates as temporary on March 15, 2021. Once final rates are approved, a surcharge will be requested from March 15, 2021 through the effective date of new base rates. A PUCT decision is expected in the first quarter of 2022.
Texas State ROFR Litigation — In May 2019, the Governor signed a ROFR bill into law, which grants incumbent utilities a ROFR to build transmission infrastructure when it directly interconnects to the utility’s existing facility. In June 2019, a complaint was filed in the United States District Court for the Western District of Texas claiming the new ROFR law to be unconstitutional. In February 2020, the federal court complaint was dismissed by the district court. In March 2020, the district court ruling was appealed to the Fifth Circuit. A decision is pending.
New Mexico FPPCAC Continuation — In December 2020, the Hearing Examiner recommended the NMPRC approve SPS’ request for the continued use of the FPPCAC and the reconciliation of its fuel costs for the reporting period (September 2015 through June 2019). Additionally, the Hearing Examiner recommended the NMPRC deny the proposed Annual Deferred Fuel Balance True-Up. The proposed true-up is designed to maintain the Deferred Fuel and Purchased Power balance within a bandwidth of plus or minus 5% of annual New Mexico fuel and purchased power costs. A decision is pending.
Resource Plan — SPS is required to file an IRP in New Mexico every three years and will file its next IRP in July 2021.
Purchased Power Arrangements and Transmission Service Providers
SPS expects to use electric generating stations, power purchases, DSM and new generation options to meet its system capacity requirements.
Purchased Power — SPS purchases power from other utilities and IPPs. Long-term purchased power contracts typically require periodic capacity and energy charges. SPS also makes short-term purchases to meet system load and energy requirements to replace owned generation, meet operating reserve obligations or obtain energy at a lower cost.
Purchased Transmission Services — SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers.
Natural Gas
SPS does not provide retail natural gas service, but purchases and transports natural gas for its generation facilities and operates natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines. SPS is subject to the jurisdiction of the FERC with respect to natural gas transactions in interstate commerce and the PHMSA and PUCT for pipeline safety compliance.
Wholesale and Commodity Marketing Operations
SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. SPS uses physical and financial instruments to minimize commodity price and credit risk and to hedge sales and purchases.
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 certain credit and non-performance risk.

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Distress in the financial markets may impact counterparty risk, the fair value of the securities in the pension fund, and SPS’ ability to earn a return on short-term investments.
Commodity Price Risk — SPS is exposed to commodity price risk in its electric operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products. Commodity price risk is also managed through the use of financial derivative instruments.
SPS’ risk management policy allows it to manage commodity price risk per commission approved hedge plans.
Wholesale and Commodity Trading Risk — SPS conducts wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments, including derivatives. SPS’ risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee.
Interest Rate Risk — SPS is subject to interest rate risk. SPS’ risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.
A 100-basis-point change in the benchmark rate on SPS’ variable rate debt would have a $3 million and no impact on pretax interest expense annually in 2020 and 2019, 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 monitor these policies to reflect changes and scope of operations.
At Dec. 31, 2020, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $1 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $1 million. At Dec. 31, 2019, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $1 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $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 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, 2020.
Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are recorded as other comprehensive income or deferred as regulatory assets and liabilities. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. The impact of discounting commodity derivative liabilities for credit risk was immaterial at Dec. 31, 2020.
See Note 8 to the financial statements for further information.
Natural Gas Fuel and Electricity Purchases
In February 2021, the United States experienced winter storm Uri and extreme cold temperatures in the central United States. This severe weather event increased the demand for natural gas used in our electric business. Certain operational assets were impacted by extreme cold temperatures and the cold further impacted the availability of renewable generation across the region (which typically acts as a hedge against commodity prices) contributing to extremely high market prices for natural gas and electricity. As a result, electric and natural gas fuel costs increased approximately $200 million. These amounts are preliminary estimates through Feb. 16, 2021 and are subject to final settlement.
SPS has fuel recovery mechanisms in all of its states to recover the increased cost of natural gas and electricity. However, given the impact of these higher costs to our customers during a pandemic, we expect our regulators to undertake a heightened review and we intend to work with our commissions to recover these costs over time to help mitigate the impacts on customer bills. SPS is taking action to increase planned debt issuances to ensure adequate liquidity for the timing difference between fuel payments and revenue collection from customers and to address any potential need to post collateral.
See 15-1 for an index of financial statements included herein.
See Note 12 to the financial statements for further information.


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Management Report on Internal Control 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, 2020. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2020, SPS’ internal control over financial reporting is effective at the reasonable assurance level based on those criteria.
Ben FowkeBrian J. Van Abel
Chairman, Chief Executive Officer and DirectorExecutive Vice President, Chief Financial Officer and Director
Feb. 17, 2021Feb. 17, 2021


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To the stockholder and Board of Directors of Southwestern Public Service Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Southwestern Public Service Company (the "Company") as of December 31, 2020 and 2019, the related statements of income, comprehensive income, cash flows and common stockholder's equity, for each of the three years in the period ended December 31, 2020, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Assets and Liabilities - Impact of Rate Regulation on the Financial Statements — Refer to Notes 4 and 10 to the consolidated financial statements.
Critical Audit Matter Description
The Company is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric transmission and distribution companies in New Mexico and Texas. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission for its wholesale electric operations, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with North American Electric Reliability Corporation standards, asset transactions and mergers and natural gas transactions in interstate commerce, (collectively with state utility regulatory agencies, the “Commissions”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation affects multiple financial statement line items and disclosures, including property, plant and equipment, regulatory assets and liabilities, operating revenues and expenses, and income taxes.
The Company is subject to regulatory rate setting processes. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in assets required to deliver services to customers. Accounting for the Company’s regulated operations provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. The Commissions’ regulation of rates is premised on the full recovery of incurred costs and a reasonable rate of return on invested capital. Decisions by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. In the rate setting process, the Company’s rates result in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.

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We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant, and 3) a refund due to customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the recognition of regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
We read relevant regulatory orders issued by the Commissions for the Company, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We also evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. If the full recovery of project costs is being challenged by intervenors, we evaluated management’s assessment of the probability of a disallowance. We evaluated the external information and compared to the Company’s recorded regulatory assets and liabilities for completeness.
We obtained management’s analysis and correspondence from counsel, as appropriate, regarding regulatory assets or liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
Minneapolis, Minnesota
February 17, 2021
We have served as the Company’s auditor since 2002.


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(amounts in millions)
Year Ended Dec. 31
Operating revenues$1,870 $1,826 $1,933 
Operating expenses
Electric fuel and purchased power835 875 1,043 
Operating and maintenance expenses275 285 283 
Demand side management expenses16 17 18 
Depreciation and amortization295 230 210 
Taxes (other than income taxes)90 72 68 
Total operating expenses1,511 1,479 1,622 
Operating income359 347 311 
Other (expense) income, net(2)2 (3)
Allowance for funds used during construction — equity332719
Interest charges and financing costs
Interest charges — includes other financing costs of $4, $3 and $3, respectively
119 99 84 
Allowance for funds used during construction — debt(14)(12)(9)
Total interest charges and financing costs1058775
Income before income taxes285 289 252 
Income tax (benefit) expense(10)26 39 
Net income$295 $263 $213 
See Notes to Financial Statements


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(amounts in millions)
Year Ended Dec. 31
Operating activities
Net income$295 $263 $213 
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization298 232 210 
Demand side management program amortization  2 
Deferred income taxes22 29 22 
Allowance for equity funds used during construction(33)(27)(19)
Provision for bad debts6 6 5 
Changes in operating assets and liabilities:
Accounts receivable(14)(9)(20)
Accrued unbilled revenues (1)15 
Prepayments and other(14)3 1 
Accounts payable8 (9)(7)
Net regulatory assets and liabilities(115)14 38 
Other current liabilities13 6 12 
Pension and other employee benefit obligations(16)(18)(16)
Other, net(1)5 6 
Net cash provided by operating activities414 473 446 
Investing activities
Utility capital/construction expenditures(1,142)(844)(1,021)
Investments in utility money pool arrangement(4)(133)(285)
Receipts from utility money pool arrangement4 133 350 
Net cash used in investing activities(1,142)(844)(956)
Financing activities
Proceeds from (repayments of) short-term borrowings, net250 (42)42 
Proceeds from issuance of long-term debt, net343 292 295 
Borrowings under utility money pool arrangement561 296 595 
Repayments under utility money pool arrangement(561)(296)(595)
Capital contributions from parent438