sps-20201231

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)


☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2020 or


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


001-03789
(Commission File Number)


SOUTHWESTERN PUBLIC SERVICE COMPANY
(Exact name of registrant as specified in its charter)


New Mexico			75-0575400
(State or Other Jurisdiction of Incorporation or Organization)			(IRS Employer Identification No.)

790 South Buchanan Street,

Amarillo,

Texas

79101

(Address of Principal Executive Offices)

(Zip Code)

(303)

571-7511

(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol

Name of each exchange on which registered

N/A

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒ Yes ☐ No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes ☒ No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act. ☐ Large accelerated Filer ☐ Accelerated Filer ☒ Non-accelerated Filer ☐ Smaller Reporting Company ☐ Emerging Growth Company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No

As of Feb. 17, 2021, 100 shares of common stock, par value $1.00 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm – Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the 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).

TABLE OF CONTENTS


PART I
Item 1 —	Business	3
	Definition of Abbreviations	3
	Forward-Looking Statements	3
	Where To Find More Information	4
	Overview	4
	Electric Operations	4
	Public Utility Regulation	6
	General	6
	Environmental	7
	Employees	7
Item 1A —	Risk Factors	7
Item 1B —	Unresolved Staff Comments	13
Item 2 —	Properties	13
Item 3 —	Legal Proceedings	13
Item 4 —	Mine Safety Disclosures	13

PART II		13
Item 5 —	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	13
Item 6 —	Selected Financial Data	14
Item 7 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
Item 7A —	Quantitative and Qualitative Disclosures About Market Risk	17
Item 8 —	Financial Statements and Supplementary Data	17
Item 9 —	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	40
Item 9A —	Controls and Procedures	41
Item 9B —	Other Information	41

PART III		41
Item 10 —	Directors, Executive Officers and Corporate Governance	41
Item 11 —	Executive Compensation	41
Item 12 —	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	41
Item 13 —	Certain Relationships and Related Transactions, and Director Independence	41
Item 14 —	Principal Accountant Fees and Services	41

PART IV		41
Item 15 —	Exhibit and Financial Statement Schedules	41
Item 16 —	Form 10-K Summary	43

Signatures		44

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.

Table of Con tents

PART I


ITEM l — BUSINESS

Definitions of Abbreviations


Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
NSP-Minnesota			Northern States Power Company, a Minnesota corporation
NSP-Wisconsin			Northern States Power Company, a Wisconsin corporation
PSCo			Public Service Company of Colorado
SPS			Southwestern Public Service Company
Utility subsidiaries			NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
Xcel Energy			Xcel Energy Inc. and its subsidiaries


Federal and State Regulatory Agencies
D.C. Circuit			United States Court of Appeals for the District of Columbia Circuit
EPA			United States Environmental Protection Agency
FERC			Federal Energy Regulatory Commission
IRS			Internal Revenue Service
NERC			North American Electric Reliability Corporation
NMPRC			New Mexico Public Regulation Commission
PHMSA			Pipeline and Hazardous Materials Safety Administration
PUCT			Public Utility Commission of Texas
SEC			Securities and Exchange Commission
TCEQ			Texas Commission on Environmental Quality


Electric and Resource Adjustment Clauses
DCRF			Distribution cost recovery factor
DSM			Demand side management
EECRF			Energy efficiency cost recovery factor
FPPCAC			Fuel and purchased power cost adjustment clause
PCRF			Power cost recovery factor
RPS			Renewable portfolio standards
TCRF			Transmission cost recovery factor (recovers transmission infrastructure improvement costs and changes in wholesale transmission charges)


Other
ADIT			Accumulated deferred income taxes
AFUDC			Allowance for funds used during construction
ALJ			Administrative Law Judge
ARO			Asset retirement obligation
ASC			FASB Accounting Standards Codification
ASU			FASB Accounting Standards Update
BART			Best available retrofit technology
CEO			Chief executive officer
CFO			Chief financial officer
C&I			Commercial and Industrial
COVID-19			Novel coronavirus
CWIP			Construction work in progress
DSM			Demand side management


ELG			Effluent limitations guidelines
ETR			Effective tax rate
FASB			Financial Accounting Standards Board
FTR			Financial transmission right
GAAP			Generally accepted accounting principles
GHG			Greenhouse gas
IM			Integrated Marketplace
IPP			Independent power producing entity
IRP			Integrated Resource Plan
ITC			Investment tax credit
MGP			Manufactured gas plant
Moody’s			Moody’s Investor Services
NAAQS			National Ambient Air Quality Standard
Native load			Customer demand of retail and wholesale customers whereby a utility has an obligation to serve under statute or long-term contract
NAV			Net asset value
NOL			Net operating loss
O&M			Operating and maintenance
OATT			Open Access Transmission Tariff
PPA			Purchased power agreement
PTC			Production tax credit
REC			Renewable energy credit
ROE			Return on equity
ROFR			Right-of-first-refusal
ROU			Right-of-use
RTO			Regional Transmission Organization
SERP			Supplemental executive retirement plan
SO2			Sulfur dioxide
SPP			Southwest Power Pool, Inc.
S&P			Standard & Poor’s Global Ratings
TCJA			2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act
VIE			Variable interest entity
WOTUS			Waters of the U.S.


Measurements
KV			Kilovolts
KWh			Kilowatt hours
MMBtu			Million British thermal units
MW			Megawatts
MWh			Megawatt 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.

Table of Con tents

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 www.xcelenergy.com. Xcel Energy makes available, free of charge through its website, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the SEC. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically at http://www.sec.gov. The information on Xcel Energy’s website is not a part of, or incorporated by reference in, this annual report on Form 10-K.


Company Overview

Electric customers

0.4 million

SPS was incorporated in 1921 under the laws of New Mexico. SPS conducts business in Texas and New Mexico and generates, purchases, transmits, distributes and sells electricity.

Total assets

$8.9 billion

Rate Base (estimated)

$5.4 billion

ROE (net income / average stockholder's equity)

9.54%

Electric generating capacity

5,232 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)


	2020			2019
KWH sales per retail customer	51,694			53,123
Revenue per retail customer	$	2,925		$	3,147
Residential revenue per KWh	9.77		¢	10.04		¢
Large C&I revenue per KWh	3.65		¢	4.01		¢
Small C&I revenue per KWh	6.99		¢	7.17		¢
Total retail revenue per KWh	5.66		¢	5.92		¢

(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:

Wind

Owned — Owned and operated wind farms with corresponding capacity:


2020		2019
Wind Farms	Capacity (a)	Wind Farms	Capacity (b)
2	967 MW	1	460 MW

(a) Summer 2020 net dependable capacity.

(b) Summer 2019 net dependable capacity.

PPAs — Number of PPAs with capacity range:


2020		2019
PPAs	Range	PPAs	Range
18	1 MW — 250 MW	18	1 MW — 250 MW

Capacity — Wind capacity:


2020						2019
2,535 MW						2,027 MW

Average Cost (Owned) — Average cost per MWh of wind energy from owned generation:


2020						2019
$17						$—

Average Cost (PPAs) — Average cost per MWh of wind energy under existing PPAs:


2020						2019
$26						$25

Wind Development

SPS placed approximately 500 MW of owned wind into service during 2020:


Project						Capacity (a)(b)
Sagamore						507 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

Solar energy PPAs:


Type						Capacity
Distributed Generation						11 MW
Utility-Scale						190 MW
Total						201 MW

Average Cost (PPAs) — Average cost per MWh of solar energy under existing PPAs:


2020						2019
$59						$56

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.

Coal

SPS owns and operates coal units with approximately 2,100 MW of total 2020 net summer dependable capacity.

Table of Con tents

Approved and proposed early coal plant retirements:

Approved / Authorized

Year

Plant Unit

Capacity

2024

Harrington (a)

1,018 MW

(a)Reflects expected conversion from coal to natural gas following the TCEQ order that Harrington cease use of coal fuel by Jan. 1, 2025, pending PUCT and NMPRC review.

Proposed

Year

Plant Unit

Capacity

2032

Tolk 1

532 MW

2032

Tolk 2

535 MW

Coal Fuel Cost

Delivered cost per MMBtu of coal consumed for owned electric generation and percentage of total fuel requirements:


	Coal
	Cost		Percent
2020	$	2.28	40	%
2019	2.19		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
	Cost		Percent
2020	$	1.43	60	%
2019	1.14		55

Capacity and Demand

Uninterrupted system peak demand and occurrence date:


System Peak Demand (in MW)
2020		2019
4,195	July 14	4,261	Aug. 5

Transmission

Transmission lines deliver electricity over long distances from power sources to transmission substations closer to homes and businesses. A strong transmission system ensures continued reliable and affordable service, ability to meet state and regional energy 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:

Project

Miles

Size

TUCO-Yoakum Co.

107

345 KV

Eddy Co.-Kiowa

345 KV

Mustang-Seminole

115 KV

Loving South-Phantom

115 KV

Upcoming transmission projects:

Project

Miles

Size

Completion Date

Roadrunner-China Draw

345 KV

2021

Distribution

Distribution lines allow electricity to travel at lower voltages from substations directly to homes and businesses. SPS has a vast distribution network, owning and operating approximately 22,000 conductor miles of distribution lines across our service territory, both above ground and underground. To continue providing reliable, affordable electric service and enable more flexibility for customers, we are working to digitize the distribution grid, while at the same time keeping it secure.

See Item 2 - Properties for further information.


Public Utility Regulation

See Item 7 for discussion of public utility regulation.


General

Seasonality

Demand for electric power is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, SPS’ operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.

Competition

SPS is subject to public policies that promote competition and development of energy markets. SPS’ industrial and large commercial customers have the ability to generate their own electricity. In addition, customers may have the option of substituting other fuels or relocating their facilities to a lower cost region.

Customers have the opportunity to supply their own power with distributed generation including solar generation and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them.

Several states have incentives for the development of rooftop solar, community solar gardens and other distributed energy resources. Distributed generating resources are potential competitors to SPS’ electric service business with these incentives and federal tax subsidies.

The FERC has continued to promote competitive wholesale markets through open access transmission and other means. SPS’ wholesale customers can purchase their output from generation resources of competing suppliers or non-contracted quantities and use the transmission system of SPS on a comparable basis to serve their native load.

Table of Con tents

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

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.


Employees

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.


ITEM 1A — RISK FACTORS

Xcel Energy, which includes SPS, is subject to a variety of risks, many of which are beyond our control. Risks that may adversely affect the business, financial condition, results of operations or cash flows are described below. 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.

Table of Con tents

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.

Table of Con tents

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.

Table of Con tents

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.

Table of Con tents

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.

Table of Con tents

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.


ITEM 1B — UNRESOLVED STAFF COMMENTS

None.


ITEM 2 — PROPERTIES

Virtually all of the utility plant property of SPS is subject to the lien of its first mortgage bond indenture.


Station, Location and Unit	Fuel	Installed	MW (a)
Steam:
Cunningham-Hobbs, NM, 2 Units	Natural Gas	1957 - 1965	225
Harrington-Amarillo, TX, 3 Units (b)	Coal	1976 - 1980	1,018
Jones-Lubbock, TX, 2 Units	Natural Gas	1971 - 1974	486
Maddox-Hobbs, NM, 1 Unit	Natural Gas	1967	112
Nichols-Amarillo, TX, 3 Units	Natural Gas	1960 - 1968	457
Plant X-Earth, TX, 4 Units	Natural Gas	1952 - 1964	298
Tolk-Muleshoe, TX, 2 Units (d)	Coal	1982 - 1985	1,067
Combustion Turbine:
Cunningham-Hobbs, NM, 2 Units	Natural Gas	1997	207
Jones-Lubbock, TX, 2 Units	Natural Gas	2011 - 2013	334
Maddox-Hobbs, NM, 1 Unit	Natural Gas	1963 - 1976	61
Wind:
Hale-Plainview, TX, 239 Units	Wind	2019	460	(c)
Sagamore-Dora, NM, 240 Units	Wind	2020	507	(c)
		Total	5,232

(a) Summer 2020 net dependable capacity.

(b) Harrington is expected to be converted to natural gas by the end of 2024.

(c) Values disclosed are the generation levels at the point-of-interconnection for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero)

(d) Tolk Unit 1 and 2 are expected to be retired in 2032.

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2020:


Conductor Miles
Transmission
345 KV			11,019
230 KV			9,795
115 KV			14,830
Less than 115 KV			4,375
Total Transmission			40,019

Distribution
Less than 115 KV			21,984

Total			62,003

SPS had 457 electric utility transmission and distribution substations at Dec. 31, 2020.

Natural gas utility mains at Dec. 31, 2020:


Miles
Transmission			20


ITEM 3 — LEGAL PROCEEDINGS

SPS is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on SPS’ financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

See Note 10 to the financial statements, Item 1 and Item 7 for further information.


ITEM 4 — MINE SAFTEY DISCLOSURES

None.

PART II


ITEM 5 — MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

SPS is a wholly owned subsidiary of Xcel Energy Inc. and there is no market for its common equity securities.

See Note 5 to the financial statements for further information.

The dividends declared during 2020 and 2019 were as follows:


(Millions of Dollars)	2020		2019
First quarter	$	76	$	58
Second quarter	55		84
Third quarter	136		114
Fourth quarter	54		78

Table of Con tents


ITEM 6 — SELECTED FINANCIAL DATA

Omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).


ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Discussion of financial condition and liquidity for SPS is omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis and the results of operations for the current year as set forth in general instructions I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Non-GAAP Financial Measures

The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as, electric margin and ongoing earnings. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from measures calculated and presented in accordance with GAAP.

SPS’ management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.

Electric Margins

Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues. Management believes electric margins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses. These margins can be reconciled to operating income, a GAAP measure, by including other operating revenues, cost of sales-other, O&M expenses, conservation and DSM expenses, depreciation and amortization and taxes (other than income taxes).

Earnings Adjusted for Certain Items (Ongoing Earnings)

Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. We use these non-GAAP financial measures to evaluate and provide details of SPS’ core earnings and underlying performance.

We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of SPS. For the years ended Dec. 31, 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)	2020		2019
Electric revenues	$	1,870	$	1,826
Electric fuel and purchased power	(835)		(875)
Electric margin	$	1,035	$	951

The following tables summarize the components of the changes in electric margin for the year ended Dec. 31, 2020:


(Millions of Dollars)	2020 vs. 2019
Regulatory rate outcomes (Texas and New Mexico) (a)	$	107
Wholesale transmission revenue (net)	26
Purchased capacity costs	8
Estimated impact of weather	7
PTCs flowed back to customers (offset by lower ETR)	(42)
New Mexico tax reform related regulatory settlement (2019)	(10)
Firm wholesale generation	(9)
Sales and demand	(8)
Other (net)	5
Total increase in electric margin	$	84

(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.

Table of Con tents

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
PUCT						Retail electric operations, rates, services, construction of transmission or generation and other aspects of SPS’ electric operations. The municipalities in which SPS operates in Texas have original jurisdiction over rates in those communities. The municipalities’ rate setting decisions are subject to PUCT review.
NMPRC						Retail electric operations, retail rates and services and the construction of transmission or generation.
FERC						Wholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce.
SPP RTO and SPP IM Wholesale Market						SPS is a transmission owning member of the SPP RTO and operates within the SPP RTO and SPP IM wholesale market. SPS is authorized to make wholesale electric sales at market-based prices.

Recovery Mechanisms


Mechanism						Additional Information
DCRF						Recovers distribution costs not included in rates in Texas.
EECRF						Recovers costs for energy efficiency programs in Texas.
Energy Efficiency Rider						Recovers costs for energy efficiency programs in New Mexico.
FPPCAC						Adjusts monthly to recover actual fuel and purchased power costs in New Mexico.
PCRF						Allows recovery of purchased power costs not included in Texas rates.
RPS						Recovers deferred costs for renewable energy programs in New Mexico.
TCRF						Recovers certain transmission infrastructure improvement costs and changes in wholesale transmission charges not included in Texas base rates.
Fixed Fuel and Purchased Recovery Factor						Provides for the over- or under-recovery of energy expenses in Texas. Regulations require refunding or surcharging over- or under- recovery amounts, including interest, when they exceed 4% of the utility’s annual fuel and purchased energy costs on a rolling 12-month basis, if this condition is expected to continue.
Wholesale Fuel and Purchased Energy Cost Adjustment						SPS recovers fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased energy cost adjustment clause accepted by the FERC. Wholesale customers also pay the jurisdictional allocation of production costs.

Pending and Recently Concluded Regulatory Proceedings

Proceeding

Amount (in millions)

Filing Date

Approval

2019 New Mexico Electric Rate Case

$31

July 2019

Received

2019 Texas Electric Rate Case

August 2019

Received

2021 New Mexico Electric Rate Case

January 2021

Pending

2021 Texas Electric Rate Case

143

February 2021

Pending

Additional Information:

2019 New Mexico Electric Rate Case — In May 2020, the NMPRC approved a settlement between SPS and intervening parties, which reflects the following terms: a base rate increase of $31 million, an ROE of 9.45% and an equity ratio of 54.77%. New rates and tariffs were effective in May 2020.

2019 Texas Electric Rate Case — In August 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).

Table of Con tents

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 investments	25
Cost of capital	20
Property taxes	8
Reduced sales, partially offset by changes in O&M	8
Allocator changes	4
Depreciation rate change	3
Other, net	8
Total rate request	$	143
Fuel cost reductions and PTCs — Sagamore wind project	(69)
Net rate increase	$	74

SPS is requesting the PUCT set current rates as temporary on March 15, 2021. Once final rates are approved, a surcharge will be requested from March 15, 2021 through the effective date of new base rates. A PUCT decision is expected in the first quarter of 2022.

Texas State ROFR Litigation — In May 2019, the Governor signed a ROFR bill into law, 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.


ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Derivatives, Risk Management and Market Risk

SPS is exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.

See Note 8 to the financial statements for further information.

SPS is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While SPS expects that the counterparties will perform under the contracts underlying its derivatives, the contracts expose SPS to certain credit and non-performance risk.

Table of Con tents

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.


ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

See 15-1 for an index of financial statements included herein.

See Note 12 to the financial statements for further information.

Table of Con tents

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.


/s/ BEN FOWKE						/s/ BRIAN J. VAN ABEL
Ben Fowke						Brian J. Van Abel
Chairman, Chief Executive Officer and Director						Executive Vice President, Chief Financial Officer and Director
Feb. 17, 2021						Feb. 17, 2021

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and Board of Directors of Southwestern Public Service Company

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Southwestern Public Service Company (the "Company") as of December 31, 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.


/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 17, 2021

We have served as the Company’s auditor since 2002.

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SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF INCOME

(amounts in millions)


	Year Ended Dec. 31
	2020		2019		2018
Operating revenues	$	1,870	$	1,826	$	1,933

Operating expenses
Electric fuel and purchased power	835		875		1,043
Operating and maintenance expenses	275		285		283
Demand side management expenses	16		17		18
Depreciation and amortization	295		230		210
Taxes (other than income taxes)	90		72		68
Total operating expenses	1,511		1,479		1,622

Operating income	359		347		311

Other (expense) income, net	(2)		2		(3)
Allowance for funds used during construction — equity	33		27		19

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 costs	105		87		75

Income before income taxes	285		289		252
Income tax (benefit) expense	(10)		26		39
Net income	$	295	$	263	$	213

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF CASH FLOWS

(amounts in millions)


	Year Ended Dec. 31
	2020		2019		2018
Operating activities
Net income	$	295	$	263	$	213
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	298		232		210
Demand side management program amortization	—		—		2
Deferred income taxes	22		29		22
Allowance for equity funds used during construction	(33)		(27)		(19)
Provision for bad debts	6		6		5
Changes in operating assets and liabilities:
Accounts receivable	(14)		(9)		(20)
Accrued unbilled revenues	—		(1)		15
Inventories	(35)		(21)		(16)
Prepayments and other	(14)		3		1
Accounts payable	8		(9)		(7)
Net regulatory assets and liabilities	(115)		14		38
Other current liabilities	13		6		12
Pension and other employee benefit obligations	(16)		(18)		(16)
Other, net	(1)		5		6
Net cash provided by operating activities	414		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 arrangement	4		133		350
Net cash used in investing activities	(1,142)		(844)		(956)

Financing activities
Proceeds from (repayments of) short-term borrowings, net	250		(42)		42
Proceeds from issuance of long-term debt, net	343		292		295
Borrowings under utility money pool arrangement	561		296		595
Repayments under utility money pool arrangement	(561)		(296)		(595)
Capital contributions from parent	438		426		337
Dividends paid to parent	(313)		(333)		(131)
Net cash provided by financing activities	718		343		543

Net change in cash and cash equivalents	(10)		(28)		33
Cash and cash equivalents at beginning of period	16		44		11
Cash and cash equivalents at end of period	$	6	$	16	$	44

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(98)	$	(84)	$	(71)
Cash received (paid) for income taxes, net	10		12		(11)

Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	$	99	$	95	$	72
Inventory transfers to property, plant and equipment	31		23		23
Operating lease right-of-use assets	—		548		—
Allowance for equity funds used during construction	33		27		19

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE CO.

BALANCE SHEETS

(amounts in millions, except share and per share data)


	Dec. 31
	2020		2019
Assets
Current assets
Cash and cash equivalents	$	6	$	16
Accounts receivable, net	94		93
Accounts receivable from affiliates	9		4
Accrued unbilled revenues	114		115
Inventories	36		31
Regulatory assets	76		20
Derivative instruments	10		15
Prepaid taxes	18		1
Prepayments and other	20		21
Total current assets	383		316

Property, plant and equipment, net	7,603		6,632

Other assets
Regulatory assets	357		364
Derivative instruments	9		13
Operating lease right-of-use assets	492		522
Other	15		4
Total other assets	873		903
Total assets	$	8,859	$	7,851

Liabilities and Equity
Current liabilities
Short-term debt	$	250	$	—
Accounts payable	198		168
Accounts payable to affiliates	17		20
Regulatory liabilities	57		118
Taxes accrued	54		40
Accrued interest	29		26
Dividends payable to parent	54		46
Derivative instruments	4		4
Operating lease liabilities	28		27
Other	25		31
Total current liabilities	716		480

Deferred credits and other liabilities
Deferred income taxes	725		672
Regulatory liabilities	718		732
Asset retirement obligations	112		77
Derivative instruments	9		13
Pension and employee benefit obligations	42		67
Operating lease liabilities	463		495
Other	12		10
Total deferred credits and other liabilities	2,081		2,066

Commitments and contingencies
Capitalization
Long-term debt	2,764		2,420
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2020 and Dec. 31, 2019, respectively	—		—
Additional paid in capital	2,790		2,351
Retained earnings	509		535
Accumulated other comprehensive loss	(1)		(1)
Total common stockholder's equity	3,298		2,885
Total liabilities and equity	$	8,859	$	7,851

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

(amounts in millions, except share data)


	Common Stock Issued							Accumulated Other Comprehensive Income (Loss)		Total Common Stockholder’s Equity
	Shares	Par Value		Additional Paid In Capital		Retained Earnings
Balance at Dec. 31, 2017	100	$	—	$	1,590	$	541	$	(1)	$	2,130

Net income						213				213

Common dividends declared to parent						(148)				(148)
Contribution of capital by parent				342						342

Balance at Dec. 31, 2018	100	$	—	$	1,932	$	606	$	(1)	$	2,537

Net income						263				263

Common dividends declared to parent						(334)				(334)
Contribution of capital by parent				419						419
Balance at Dec. 31, 2019	100	$	—	$	2,351	$	535	$	(1)	$	2,885

Net income						295				295

Common dividends declared to parent						(321)				(321)
Contribution of capital by parent				439						439
Balance at Dec. 31, 2020	100	$	—	$	2,790	$	509	$	(1)	$	3,298

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE COMPANY

Notes to Financial Statements


1. Summary of Significant Accounting Policies

General — SPS is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity.

SPS’ financial statements are presented in accordance with GAAP. All of SPS’ underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions. Certain amounts in the financial statements or notes have been reclassified for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.

SPS has evaluated events occurring after Dec. 31, 2020 up to the date of issuance of these financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.

Use of Estimates — SPS uses estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used on items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results.

Regulatory Accounting — SPS accounts for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

•Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates.

•Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates or because the amounts were collected in rates prior to the costs being incurred.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.

If changes in the regulatory environment occur, SPS may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on SPS’ results of operations, financial condition and cash flows.

See Note 4 for further information.

Income Taxes — SPS accounts for income taxes using the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. SPS defers income taxes for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities. SPS uses rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.

The effects of SPS’ tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, which would be refundable to utility customers over the remaining life of the related assets. SPS anticipates that a tax rate increase would result in the establishment of a regulatory asset, subject to regulatory approval.

Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of regulatory assets and liabilities related to income taxes. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized.

SPS follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. SPS recognizes a tax position in its financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax expense.

SPS reports interest and penalties related to income taxes within other (expense) income or interest charges in the statements of income.

Xcel Energy Inc. and its subsidiaries, including SPS, file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.

See Note 7 for further information.

Property, Plant and Equipment and Depreciation in Regulated Operations — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.

Table of Con tents

SPS records depreciation expense using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Plant removal costs are recovered in rates as authorized by the appropriate regulatory entities. The amount of removal costs are based on current factors used in existing depreciation rates. Depreciation expense, expressed as a percentage of average depreciable property, was 3.1% in 2020, 2.9% in 2019 and 2.9% in 2018.

See Note 3 for further information.

AROs — SPS accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO.

See Note 10 for further information.

Benefit Plans and Other Postretirement Benefits — SPS maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates.

Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.

See Note 9 for further information.

Environmental Costs — Environmental costs are recorded when it is probable SPS is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for SPS’ expected share of the cost.

Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 10 for further information.

Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. SPS recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs systematically throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is recognized.

SPS does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. SPS presents its revenues net of any excise or sales taxes or fees.

SPS participates in SPP. SPS recognizes physical sales to customers (native load and wholesale) on a gross basis in electric revenues and cost of sales. Revenues and charges for short-term physical wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other revenues and charges settled/facilitated through an RTO are recorded on a net basis in cost of sales.

See Note 6 for further information.

Cash and Cash Equivalents — SPS considers investments in instruments with a remaining maturity of three months or less at the time of purchase to be cash equivalents.

Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. SPS establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.

As of Dec. 31, 2020 and 2019, the allowance for bad debts was $8 million and $5 million, respectively.

Inventory — Inventory is recorded at average cost and consisted of the following:


(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
Inventories
Materials and supplies	$	27	$	25
Fuel	9		6
Total inventories	$	36	$	31

Fair Value Measurements — SPS presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its financial statements. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, SPS may use quoted prices for similar contracts or internally prepared valuation models to determine fair value. For the pension and postretirement plan assets published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security.

See Notes 8 and 9 for further information.

Derivative Instruments — SPS uses derivative instruments in connection with its utility commodity price and interest rate activities, including forward contracts, futures, swaps and options. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on expected recovery of derivative instrument settlements through fuel and purchased energy cost recovery mechanisms. Interest rate hedging transactions are recorded as a component of interest expense.

Table of Con tents

Normal Purchases and Normal Sales — SPS enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale.

See Note 8 for further information.

Other Utility Items

AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in SPS’ rate base for establishing utility rates.

Alternative Revenue — Certain rate rider mechanisms (including DSM programs) qualify as alternative revenue programs. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, including expected collection within 24 months, revenue is recognized equal to the revenue requirement, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers.

See Note 6 for further information.

Conservation Programs — SPS has implemented programs in its jurisdictions to assist customers in conserving energy and reducing peak demand on the electric system. These programs include commercial motor, air conditioner and lighting upgrades, as well as residential rebates for participation in air conditioner interruption and home weatherization.

The costs incurred for some DSM programs are deferred as permitted by the applicable regulatory jurisdiction. For those programs, costs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. Revenues recognized for incentive programs designed for recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the annual period in which they are earned. SPS recovers approved conservation program costs in base rate revenue or through a rider.

Emission Allowances — Emission allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these allowances are included in electric revenues.

RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. SPS reduces recoverable fuel costs for the cost of RECs and records that cost as a regulatory asset when the amount is recoverable in future rates.

Sales of RECs are recorded in electric revenues on a gross basis. Cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.

Segment Information — SPS has only one reportable segment. SPS is a wholly owned subsidiary of Xcel Energy Inc. and operates in the regulated electric utility industry providing wholesale and retail electric service in the states of Texas and New Mexico.


2. Accounting Pronouncements

Recently Adopted

Credit Losses — In 2016, the FASB issued Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326), which changes how entities account for losses on receivables and certain other assets. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards.

SPS implemented the guidance using a modified-retrospective approach, recognizing an immaterial cumulative effect charge (after tax) to retained earnings on Jan. 1, 2020. The Jan. 1, 2020 adoption of ASC Topic 326 did not have a significant impact on SPS’ financial statements.


3. Property, Plant and Equipment

Major classes of property, plant and equipment


(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
Property, plant and equipment, net
Electric plant	$	9,229	$	8,453
Plant to be retired (a)	316		—
CWIP	146		486
Total property, plant and equipment	9,691		8,939
Less accumulated depreciation	(2,088)		(2,307)
Property, plant and equipment, net	$	7,603	$	6,632

(a)Includes expected retirement of Tolk and conversion of Harrington to natural gas.

Table of Con tents


4. Regulatory Assets and Liabilities

Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric rates. SPS would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP.

Components of regulatory assets:


(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2020				Dec. 31, 2019
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations	9	Various	$	12	$	178	$	11	$	204
Excess deferred taxes — TCJA	7	Various	3		51		2		52
Recoverable deferred taxes on AFUDC		Plant lives	—		42		—		34
Net AROs (a)	1, 10	Various	—		33		—		27
Losses on reacquired debt		Term of related debt	1		20		1		21
Texas revenue surcharge		One to two years	54		17		2		—
Conservation programs (b)	1	One to two years	1		2		1		1
Other		Various	5		14		3		25
Total regulatory assets			$	76	$	357	$	20	$	364

(a)Includes amounts recorded for future recovery of AROs.

(b)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

Components of regulatory liabilities:


(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2020				Dec. 31, 2019
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Deferred income tax adjustments and TCJA refunds (a)	7	Various	$	6	$	513	$	7	$	535
Plant removal costs	1, 10	Various	—		177		—		175
Revenue subject to refund		One to two years	4		4		14		1
Gain from asset sales		Various	—		2		—		2
Deferred electric energy costs		Less than one year	35		—		82		—
Contract valuation adjustments (b)	1, 8	Less than one year	7		—		12		—
Other		Various	5		22		3		19
Total regulatory liabilities (c)			$	57	$	718	$	118	$	732

(a)Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.

(b)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements.

(c)Revenue subject to refund of $4 million for 2019 was included in other current liabilities and none for 2020.

At Dec. 31, 2020 and 2019, SPS’ regulatory assets not earning a return primarily included the unfunded portion of pension and retiree medical obligations and net AROs. In addition, SPS’ regulatory assets included $114 million and $57 million at Dec. 31, 2020 and 2019, respectively, of past expenditures not earning a return. Amounts are related to formula rates, losses on reacquired debt and certain rate case expenditures.


5. Borrowings and Other Financing Instruments

Short-Term Borrowings

SPS meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool.

Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc.

Money pool borrowings for SPS were as follows:


(Millions of Dollars, Except Interest Rates)	Three Months Ended Dec. 31, 2020			Year Ended Dec. 31
				2020			2019			2018
Borrowing limit	$	100		$	100		$	100		$	100
Amount outstanding at period end	—			—			—			—
Average amount outstanding	81			43			8			29
Maximum amount outstanding	100			100			100			100
Weighted average interest rate, computed on a daily basis	0.08		%	0.54		%	2.42		%	1.96		%
Weighted average interest rate at end of period	N/A			N/A			N/A			N/A

Table of Con tents

Commercial Paper — Commercial paper outstanding for SPS was as follows:


(Millions of Dollars, Except Interest Rates)	Three Months Ended Dec. 31, 2020			Year Ended Dec. 31
				2020			2019			2018
Borrowing limit	$	500		$	500		$	500		$	400
Amount outstanding at period end	250			250			—			42
Average amount outstanding	58			44			72			30
Maximum amount outstanding	250			250			316			144
Weighted average interest rate, computed on a daily basis	0.21		%	1.11		%	2.68		%	2.27		%
Weighted average interest rate at end of period	0.29			0.29			N/A			2.80

Letters of Credit — SPS may use letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. At both Dec. 31, 2020 and 2019, there were $2 million of letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, SPS must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

Amended Credit Agreement — In June 2019, SPS entered into an amended five-year credit agreement with a syndicate of banks. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with the exception of the following:

•Maturity is June 2024.

•Borrowing limit is $500 million.

The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

Features of SPS’ credit facility:


Debt-to-Total Capitalization Ratio (a)		Amount Facility May Be Increased (millions)	Additional Periods for Which a One-Year Extension May Be Requested (b)
2020	2019
48%	46%	$50	2

(a) The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.

(b) All extension requests are subject to majority bank group approval.

The credit facility has a cross-default provision that SPS would be in default on its borrowings under the facility if SPS or any of its future significant subsidiaries whose total assets exceed 15% of SPS’ total assets default on indebtedness in an aggregate principal amount exceeding $75 million.

If SPS does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2020, SPS was in compliance with all financial covenants.

SPS had the following committed credit facility available as of Dec. 31, 2020.


Credit Facility (a)	Drawn (b)	Available
$500	$252	$248

(a)This credit facility matures in June 2024.

(b)Includes letters of credit and outstanding commercial paper.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. SPS had no direct advances on the facility outstanding at Dec. 31, 2020 and 2019.

Long-Term Borrowings and Other Financing Instruments

Generally, all property of SPS is subject to the lien of its first mortgage indenture. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance.

Long-term debt obligations for SPS as of Dec. 31 (millions of dollars):


Financing Instrument	Interest Rate		Maturity Date	2020		2019
First mortgage bonds	3.30	%	June 15, 2024	$	150	$	150
First mortgage bonds	3.30		June 15, 2024	200		200
Unsecured senior notes	6.00		Oct. 1, 2033	100		100
Unsecured senior notes	6.00		Oct. 1, 2036	250		250
First mortgage bonds	4.50		Aug. 15, 2041	200		200
First mortgage bonds	4.50		Aug. 15, 2041	100		100
First mortgage bonds	4.50		Aug. 15, 2041	100		100
First mortgage bonds	3.40		Aug. 15, 2046	300		300
First mortgage bonds	3.70		Aug. 15, 2047	450		450
First mortgage bonds	4.40		Nov. 15, 2048	300		300
First mortgage bonds (b)	3.75		June 15, 2049	300		300
First mortgage bonds (a)	3.15		May 1, 2050	350		—
Unamortized discount				(10)		(7)
Unamortized debt issuance cost				(26)		(23)
Total long-term debt				$	2,764	$	2,420

(a)2020 financing.

(b)2019 financing.

Maturities of long-term debt:


(Millions of Dollars)
2021	$	—
2022	—
2023	—
2024	350
2025	—

Deferred Financing Costs — Deferred financing costs of approximately $26 million and $23 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2020 and 2019, respectively. SPS is amortizing these financing costs over the remaining maturity periods of the related debt.

Capital Stock — SPS has the following preferred stock:


Preferred Stock Authorized (Shares)	Par Value of Preferred Stock	Preferred Stock Outstanding (Shares) 2020 and 2019
10,000,000	1.00	—

Table of Con tents

Dividend Restrictions — SPS dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings. SPS is required to be current on particular interest payments before dividends can be paid.

SPS’ state regulatory commissions additionally impose dividend limitations, which are more restrictive than those imposed by the FERC.

Requirements and actuals as of Dec. 31, 2020:


Equity to Total Capitalization Ratio Required Range				Equity to Total Capitalization Ratio Actual (a)
Low		High		2020
45.0	%	55.0	%	54.4	%

(a) Excludes short-term debt.


Unrestricted Retained Earnings			Total Capitalization			Limit on Total Capitalization (a)
$	510	million	$	6	billion	N/A

(a) SPS may not pay a dividend that would cause it to lose its investment grade bond rating.


6. Revenues

Revenue is classified by the type of goods/services rendered and market/customer type. SPS’ operating revenues consisted of the following:


	Year Ended Dec. 31
(Millions of Dollars)	2020		2019		2018
Major revenue types
Revenue from contracts with customers:
Residential	$	359	$	352	$	364
C&I	739		800		828
Other	39		41		45
Total retail	1,137		1,193		1,237
Wholesale	345		361		426
Transmission	279		240		231
Other	4		3		13
Total revenue from contracts with customers	1,765		1,797		1,907
Alternative revenue and other	105		29		26
Total revenues	$	1,870	$	1,826	$	1,933


7. Income Taxes

Federal Tax Loss Carryback Claims — In 2020, Xcel Energy identified certain expenses related to tax years 2009 - 2011 that qualify for an extended carryback claim. SPS is not expected to accrue any income tax expense related to this adjustment.

Federal Audit — SPS is a member of Xcel Energy affiliated group that files a consolidated federal income tax return. Statue of limitations applicable to Xcel Energy’s consolidated federal tax returns expire as follows:


Tax Year(s)						Expiration
2014 - 2016						July 2021

Additionally, the statute of limitations related to the federal tax loss carryback claim referenced above has been extended. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.

In 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy filed a protest with the IRS. In April 2020, Xcel Energy and Appeals reached an agreement and no material adjustments were required.

In 2018, the IRS began an audit of tax years 2014 - 2016. In July 2020, Xcel Energy and the IRS reached an agreement and the related benefit was recognized.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2020, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2012. There are currently no state income tax audits in progress.

Unrecognized Tax Benefits — Unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain, but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment to the taxing authority to an earlier period.

Unrecognized tax benefits — permanent vs temporary:


(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
Unrecognized tax benefit — Permanent tax positions	$	3	$	3
Unrecognized tax benefit — Temporary tax positions	4		2
Total unrecognized tax benefit	$	7	$	5

Changes in unrecognized tax benefits:


(Millions of Dollars)	2020		2019		2018
Balance at Jan. 1	$	5	$	5	$	4
Additions based on tax positions related to the current year	1		—		1
Additions for tax positions of prior years	5		—		—
Reductions for tax positions of prior years	(4)		—		—
Balance at Dec. 31	$	7	$	5	$	5

Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:


(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
NOL and tax credit carryforwards	$	(6)	$	(4)

Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $2 million and $1 million at Dec. 31, 2020 and Dec. 31, 2019, respectively.

As the IRS and state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $5 million in the next 12 months.

Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.

Interest payable related to unrecognized tax benefits:


(Millions of Dollars)	2020		2019		2018
Receivable for interest related to unrecognized tax benefits at Jan. 1	$	1	$	1	$	1
Interest expense related to unrecognized tax benefits	(2)		—		—
(Payable) receivable for interest related to unrecognized tax benefits at Dec. 31	$	(1)	$	1	$	1

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2020, 2019 or 2018.

Table of Con tents

Other Income Tax Matters — NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:


(Millions of Dollars)	2020		2019
Federal tax credit carryforwards	$	83	$	30
State NOL carryforwards	1		1

Federal carryforward periods expire between 2031 and 2040 and state carryforward periods expire starting 2025.

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.

Effective income tax rate for years ended Dec. 31:


	2020		2019		2018
Federal statutory rate	21.0	%	21.0	%	21.0	%
State income tax on pretax income, net of federal tax effect	2.3		2.2		2.3
Increases (decreases) in tax from:
Wind PTCs	(18.3)		(7.9)		—
Plant regulatory differences (a)	(6.4)		(5.0)		(4.8)
Amortization of excess nonplant deferred taxes	(0.8)		(0.9)		(1.2)
Other tax credits, net NOL & tax credit allowances	(0.7)		(0.6)		(0.7)
Adjustments attributable to tax returns	(0.6)		(0.1)		(1.5)
Change in unrecognized tax benefits	0.3		0.2		0.1
Other, net	(0.3)		0.1		0.3
Effective income tax rate	(3.5)	%	9.0	%	15.5	%

(a)Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions.

Components of income tax expense for years ended Dec. 31:


(Millions of Dollars)	2020		2019		2018
Current federal tax (benefit) expense	$	(31)	$	(4)	$	12
Current state tax (benefit) expense	(1)		1		3
Current change in unrecognized tax expense	—		—		2
Deferred federal tax expense	13		22		20
Deferred state tax expense	8		6		4
Deferred change in unrecognized tax expense (benefit)	1		1		(2)
Total income tax (benefit) expense	$	(10)	$	26	$	39

Components of deferred income tax expense as of Dec. 31:


(Millions of Dollars)	2020		2019		2018
Deferred tax expense excluding items below	$	53	$	53	$	44
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(31)		(24)		(22)
Deferred tax expense	$	22	$	29	$	22

Components of the net deferred tax liability as of Dec. 31:


(Millions of Dollars)	2020		2019 (a)
Deferred tax liabilities:
Differences between book and tax bases of property	$	838	$	759
Operating lease assets	109		116
Regulatory assets	59		50
Pension expense	33		33
Other	2		—
Total deferred tax liabilities	$	1,041	$	958

Deferred tax assets:
Operating lease liabilities	$	109	$	116
Regulatory liabilities	104		111
Tax credit carryforward	83		30
Deferred fuel costs	9		18
Other employee benefits	7		6
Other	4		5
Total deferred tax assets	316		286
Net deferred tax liability	$	725	$	672

(a) Prior periods have been reclassified to conform to current year presentation.


8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

Accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance.

•Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

•Level 2 — Pricing inputs are other than quoted prices in active markets but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts or priced with models using highly observable inputs.

•Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.

Specific valuation methods include:

Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset value.

Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Table of Con tents

Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.

Electric commodity derivatives held by SPS include transmission congestion instruments, generally referred to as FTRs, purchased from SPP. FTRs purchased from an RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR.

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of important inputs to the value of FTRs between auction processes, including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3.

Non-trading monthly FTR settlements are expected to be recovered through fuel and purchased energy cost recovery mechanisms, and therefore changes in the fair value of the yet to be settled portions of FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of SPS, the numerous unobservable quantitative inputs pertinent to the value of FTRs are immaterial to the financial statements of SPS.

Derivative Instruments Fair Value Measurements

SPS enters into derivative instruments, including forward contracts, for trading purposes and to manage risk in connection with changes in interest rates and electric utility commodity prices.

Interest Rate Derivatives — SPS may enter into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes. As of Dec. 31, 2020, accumulated other comprehensive loss related to interest rate derivatives included immaterial net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

Wholesale and Commodity Trading Risk — SPS conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments, including derivatives. SPS is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in the activities governed by this policy.

Commodity Derivatives — SPS enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric utility operations. This could include the purchase or sale of energy or energy-related products and FTRs.

(Amounts in Millions) (a)

Dec. 31, 2020

Dec. 31, 2019

MWh of electricity

(a)Amounts are not reflective of net positions in the underlying commodities.

Consideration of Credit Risk and Concentrations — SPS continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the balance sheets.

SPS’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. At Dec. 31, 2020, two of the nine most significant counterparties for these activities, comprising $12 million or 36% of this credit exposure, had investment grade ratings from S&P, Moody’s or Fitch Ratings. Six of the nine most significant counterparties, comprising $22 million or 64% of this credit exposure, were not rated by external rating agencies, but based on SPS’ internal analysis, had credit quality consistent with investment grade. One of these significant counterparties, comprising an immaterial amount or less than 1% of this credit exposure, had credit quality less than investment grade, based on internal analysis. Nine of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.

Impact of Derivative Activities on Income and Accumulated Other Comprehensive Loss — Changes in the fair value of FTRs resulting in a pre-tax net loss of $7 million in Dec. 31, 2020 and $7 million in pre-tax net gains for both years ended Dec. 31, 2019 and 2018, respectively, were reclassified as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on expected recovery of FTR settlements through fuel and purchased energy cost recovery mechanisms.

FTR settlement losses were immaterial for the year ended Dec. 31, 2020. For the years ended Dec. 31, 2019 and 2018, $6 million and $4 million, respectively, of settlement gains were recognized and recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

SPS had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2020, 2019 and 2018.

Table of Con tents

Recurring Fair Value Measurements — SPS’ derivative assets and liabilities measured at fair value on a recurring basis were as follows:


	Dec. 31, 2020												Dec. 31, 2019
	Fair Value						Fair Value Total		Netting (a)		Total		Fair Value						Fair Value Total		Netting (a)		Total
(Millions of Dollars)	Level 1		Level 2		Level 3								Level 1		Level 2		Level 3
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	7	$	7	$	—	$	7	$	—	$	—	$	12	$	12	$	—	$	12
Total current derivative assets	$	—	$	—	$	7	$	7	$	—	7		$	—	$	—	$	12	$	12	$	—	12
PPAs (b)											3												3
Current derivative instruments											$	10											$	15
Noncurrent derivative assets
PPAs (b)											$	9											$	13
Noncurrent derivative instruments											$	9											$	13
Current derivative liabilities
Other derivative instruments:


PPAs (b)											$	4											$	4
Current derivative instruments											$	4											$	4
Noncurrent derivative liabilities
PPAs (b)											$	9											$	13
Noncurrent derivative instruments											$	9											$	13

(a)SPS nets derivative instruments and related collateral on its balance sheets when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2020 and 2019. At Dec. 31, 2020 and 2019, derivative assets and liabilities include no obligations to return cash collateral, respectively. At Dec. 31, 2020 and 2019, derivative assets and liabilities include no rights to reclaim cash collateral, respectively. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

(b)During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

Changes in Level 3 commodity derivatives for the years ended Dec. 31, 2020, 2019 and 2018:


	Year Ended Dec. 31
(Millions of Dollars)	2020		2019		2018
Balance at Jan. 1	$	12	$	14	$	13
Purchases	23		27		32
Settlements	(23)		(34)		(42)
Net transactions recorded during the period:
Net (losses) gains recognized as regulatory assets	(5)		5		11
Balance at Dec. 31	$	7	$	12	$	14

SPS recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for Dec. 31, 2020, 2019 and 2018.

Fair Value of Long-Term Debt

As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:


	2020				2019
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	2,764	$	3,381	$	2,420	$	2,706

Fair value of SPS’ long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of Dec. 31, 2020 and 2019, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.


9. Benefit Plans and Other Postretirement Benefits

Pension and Postretirement Health Care Benefits

Xcel Energy, which includes SPS, has several noncontributory, qualified, defined benefit pension plans that cover almost all employees. All newly hired or rehired employees participate under the Cash Balance formula, which is based on pay credits using a percentage of annual eligible pay and annual interest credits. The average annual interest crediting rates for these plans was 2.37, 3.12 and 3.75 percent in 2020, 2019, and 2018, respectively. Some employees may participate under legacy formulas such as the traditional final average pay or pension equity. Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs subject to the limitations of applicable employee benefit and tax laws.

In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The SERP is maintained for certain executives who participated in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions funded by Xcel Energy’s consolidated operating cash flows. Obligations of the SERP and nonqualified plan as of Dec. 31, 2020 and 2019 were $43 million and $39 million, respectively, of which $2 million was attributable to SPS in both years. In 2020 and 2019, Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $6 million and $4 million, respectively, of which immaterial amounts were attributable to SPS.

Table of Con tents

Xcel Energy, which includes SPS, bases the investment-return assumption on expected long-term performance for each of the asset classes in its pension and postretirement health care portfolios. For pension assets, Xcel Energy considers the historical returns achieved by its asset portfolio over the past 20 years or longer period, as well as long-term projected return levels. Xcel Energy and SPS continually review pension assumptions.

Pension cost determination assumes a forecasted mix of investment types over the long-term.

•Investment returns in 2020 were above the assumed level of 6.78%.

•Investment returns in 2019 were above the assumed level of 6.78%.

•Investment returns in 2018 were below the assumed level of 6.78%.

•In 2021, SPS’s expected investment-return assumption is 6.39%.

Pension plan and postretirement benefit assets are invested in a portfolio according to Xcel Energy’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by the assets in any year.

State agencies also have issued guidelines to the funding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for Texas and New Mexico amounts collected in rates. These assets are invested in a manner consistent with the investment strategy for the pension plan.

Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios.

Plan Assets

For each of the fair value hierarchy levels, SPS’ pension plan assets measured at fair value:


	Dec. 31, 2020 (a)										Dec. 31, 2019 (a)
(Millions of Dollars)	Level 1		Level 2		Level 3		Measured at NAV		Total		Level 1		Level 2		Level 3		Measured at NAV		Total
Cash equivalents	$	31	$	—	$	—	$	—	$	31	$	19	$	—	$	—	$	—	$	19
Commingled funds	211		—		—		160		371		203		—		—		145		348
Debt securities	—		110		1		—		111		—		98		1		—		99
Equity securities	11		—		—		—		11		12		—		—		—		12
Other	2		1		—		—		3		(17)		—		—		(3)		(20)
Total	$	255	$	111	$	1	$	160	$	527	$	217	$	98	$	1	$	142	$	458

(a)See Note 8 for further information on fair value measurement inputs and methods.

For each of the fair value hierarchy levels, SPS’ proportionate allocation of the total postretirement benefit plan assets that were measured at fair value:


	Dec. 31, 2020 (a)										Dec. 31, 2019 (a)
(Millions of Dollars)	Level 1		Level 2		Level 3		Measured at NAV		Total		Level 1		Level 2		Level 3		Measured at NAV		Total
Cash equivalents	$	3	$	—	$	—	$	—	$	3	$	2	$	—	$	—	$	—	$	2
Insurance contracts	—		5		—		—		5		—		5		—		—		5
Commingled funds	7		—		—		7		14		7		—		—		8		15
Debt securities	—		22		—		—		22		—		22		—		—		22

Total	$	10	$	27	$	—	$	7	$	44	$	9	$	27	$	—	$	8	$	44

(a)See Note 8 for further information on fair value measurement inputs and methods.

No assets were transferred in or out of Level 3 for 2020. Immaterial assets were transferred in or out of Level 3 for 2019.

Table of Con tents

Funded Status — Benefit obligations for both pension and postretirement plans increased from Dec. 31, 2019 to Dec. 31, 2020, due primarily to decreases in discount rates used in actuarial valuations. Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for SPS are as follows:


	Pension Benefits				Postretirement Benefits
(Millions of Dollars)	2020		2019		2020		2019
Change in Benefit Obligation:
Obligation at Jan. 1	$	519	$	478	$	44	$	42
Service cost	10		9		1		1
Interest cost	18		20		1		2
Plan amendments	—		—		—		—
Actuarial loss (gain)	45		44		(5)		—
Plan participants’ contributions	—		—		1		1
Benefit payments (a)	(30)		(32)		(4)		(2)
Obligation at Dec. 31	$	562	$	519	$	38	$	44
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	458	$	392	$	44	$	40
Actual return on plan assets	84		80		3		5
Employer contributions	15		18		—		—
Plan participants’ contributions	—		—		1		1
Benefit payments	(30)		(32)		(4)		(2)
Fair value of plan assets at Dec. 31	$	527	$	458	$	44	$	44
Funded status of plans at Dec. 31	$	(35)	$	(61)	$	6	$	—
Amounts recognized in the Balance Sheet at Dec. 31:
Noncurrent assets	—		—		6		—
Noncurrent liabilities	(35)		(61)		—		—
Net amounts recognized	$	(35)	$	(61)	$	6	$	—

(a)Includes approximately $7 million in 2019, of lump-sum benefit payments used in the determination of a settlement charge.


	Pension Benefits				Postretirement Benefits
Significant Assumptions Used to Measure Benefit Obligations:	2020		2019		2020		2019
Discount rate for year-end valuation	2.71	%	3.49	%	2.65	%	3.47	%
Expected average long-term increase in compensation level	3.75	%	3.75	%	N/A		N/A
Mortality table	Pri-2012		Pri-2012		Pri-2012		Pri-2012
Health care costs trend rate — initial: Pre-65	N/A		N/A		5.50	%	6.00	%
Health care costs trend rate — initial: Post-65	N/A		N/A		5.00	%	5.10	%
Ultimate trend assumption — initial: Pre-65	N/A		N/A		4.50	%	4.50	%
Ultimate trend assumption — initial: Post-65	N/A		N/A		4.50	%	4.50	%
Years until ultimate trend is reached	N/A		N/A		5		3

Accumulated benefit obligation for the pension plan was $519 million and $481 million as of Dec. 31, 2020 and 2019, respectively.

Table of Con tents

Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit), other than the service cost component, is included in other income in the statements of income.

Components of net periodic benefit cost (credit) and amounts recognized in other comprehensive income and regulatory assets and liabilities:


	Pension Benefits									Postretirement Benefits
(Millions of Dollars)	2020			2019			2018			2020			2019			2018
Service cost	$	10		$	9		$	10		$	1		$	1		$	1
Interest cost	18			20			18			1			2			2
Expected return on plan assets	(29)			(28)			(28)			(2)			(2)			(3)
Amortization of prior service credit	—			—			—			—			(1)			—
Amortization of net loss	12			11			14			—			—			—
Settlement charge (a)	—			2			3			—			—			—
Net periodic pension cost	11			14			17			—			—			—
Effects of regulation	2			1			(2)			—			—			—
Net benefit cost recognized for financial reporting	$	13		$	15		$	15		$	—		$	—		$	—
Significant Assumptions Used to Measure Costs:
Discount rate	3.49		%	4.31		%	3.63		%	3.47		%	4.32		%	3.62		%
Expected average long-term increase in compensation level	3.75			3.75			3.75			—			—			—
Expected average long-term rate of return on assets	6.78			6.78			6.78			4.50			5.30			5.80

(a)A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2019 and 2018, as a result of lump-sum distributions during each plan year, SPS recorded a total pension settlement charge of $2 million and $3 million, respectively. A total of $1 million of that amount was recorded in the income statement in 2019 and 2018, respectively. There were no settlement charges recorded to the qualified pension plans in 2020.


	Pension Benefits				Postretirement Benefits
(Millions of Dollars)	2020		2019		2020		2019
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	186	$	210	$	(18)	$	(12)
Prior service credit	(1)		(1)		(1)		(1)
Total	$	185	$	209	$	(19)	$	(13)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	11	$	11	$	—	$	—
Noncurrent regulatory assets	174		198		—		—
Current regulatory liabilities	—		—		(1)		(1)
Noncurrent regulatory liabilities	—		—		(18)		(12)
Total	$	185	$	209	$	(19)	$	(13)

Measurement date

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2020

Dec. 31, 2019

Cash Flows — Funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the requirements of income tax and other pension-related regulations. Required contributions were made in 2018 — 2021 to meet minimum funding requirements.

Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows:

•$125 million in January 2021, of which $14 million was attributable to SPS.

•$150 million in 2020, of which $14 million was attributable to SPS.

•$154 million in 2019, of which $18 million was attributable to SPS.

•$150 million in 2018, of which $8 million was attributable to SPS.

For future years, Xcel Energy and SPS anticipate contributions will be made as necessary.

The postretirement health care plans have no funding requirements other than fulfilling benefit payment obligations, when claims are presented and approved. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Xcel Energy’s voluntary postretirement funding contributions were as follows:

•$10 million during 2021.

•$11 million during 2020.

•$15 million during 2019.

•$11 million during 2018.

•Amounts attributable to SPS were immaterial.

Table of Con tents

Target asset allocations:


	Pension Benefits				Postretirement Benefits
	2020		2019		2020		2019
Domestic and international equity securities	35	%	37	%	15	%	15	%
Long-duration fixed income securities	35		30		—		—
Short-to-intermediate fixed income securities	13		14		72		72
Alternative investments	15		17		9		9
Cash	2		2		4		4
Total	100	%	100	%	100	%	100	%

The asset allocations above reflect target allocations approved in the calendar year to take effect in the subsequent year

Plan Amendments — In 2020, 2019, and 2018, there were no significant plan amendments made which affected the benefit obligation.

Projected Benefit Payments

SPS’ projected benefit payments:


(Millions of Dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
2021	$	32	$	3	$	—	$	3
2022	31		3		—		3
2023	31		3		—		3
2024	31		3		—		3
2025	31		3		—		3
2026-2030	152		12		—		12

Defined Contribution Plans

Xcel Energy, which includes SPS, maintains 401(k) and other defined contribution plans that cover most employees. The expense to these plans for SPS was approximately $3 million in 2020, 2019 and 2018.


10. Commitments and Contingencies

Legal

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, 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.

Rate Matters

SPP OATT Upgrade Costs — Under the SPP OATT, costs of transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade. SPP had not been charging its customers for these upgrades, even though the SPP OATT had allowed SPP to do so since 2008. In 2016, the FERC granted SPP’s request to recover previously unbilled charges and SPP subsequently billed SPS approximately $13 million.

In July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP the right to recover previously unbilled charges was remanded to the FERC. In February 2019, the FERC reversed its 2016 decision and ordered SPP to refund charges retroactively collected from its transmission customers, including SPS, related to periods before September 2015. In March 2020, SPP and Oklahoma Gas & Electric separately filed petitions for review of the FERC’s orders at the D.C. Circuit. SPS has intervened in both appeals in support of FERC. Any refunds received by SPS are expected to be given back to SPS customers through future rates.

In October 2017, SPS filed a separate related complaint asserting SPP assessed upgrade charges to SPS in violation of the SPP OATT. In March 2018, the FERC issued an order denying the SPS complaint. SPS filed a request for rehearing in April 2018. The FERC issued a tolling order granting a rehearing for further consideration in May 2018. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the amount through future SPS customer rates. In October 2020, SPS filed a petition for review of the FERC’s March 2018 order and May 2018 tolling order at the D.C. Circuit. This appeal is stayed pending the outcome of the separate appeal initiated in 2020 by Oklahoma Gas & Electric and SPP.

SPP Filing to Assign GridLiance Facilities to SPS Rate Zone — In August 2018, SPP filed a request with the FERC to amend its OATT to include costs of the GridLiance High Plains, LLC. facilities in the SPS rate zone. In a previous filing, the FERC determined that some of these facilities did not qualify as transmission facilities under the SPP OATT. SPP’s proposed tariff changes resulted in an increase in the annual transmission revenue requirement of $10 million per year, with $6 million allocated to SPS’ retail customers. The remaining $4 million would be paid by other wholesale loads in the SPS rate zone. On March 16, 2020, GridLiance also filed additional rate increases for 2020 which would raise their annual revenue requirement to $14 million, with approximately $9 million allocated to SPS’ retail customers. The hearing portion of this proceeding was concluded on Sept. 11, 2020.

The initial post-hearing brief was filed on Oct. 27, 2020 and the ALJ’s decision on this case is expected on May 3, 2021. The FERC will then rule on the judge’s decision and either sustain it, overturn it, or order further proceedings. SPS has incurred approximately $15 million in associated charges as of Dec. 31, 2020. In August 2020, FERC issued an order on a question certified by the hearing judge for the FERC’s review, in which FERC made certain findings in SPS’ favor regarding the legal standard that applies to the ongoing hearing proceeding. In November 2020, FERC denied GridLiance’s request for rehearing of this August 2020 order. In December 2020, GridLiance filed a petition for review at the D.C. Circuit of the August 2020 and November 2020 orders on the certified question.

Table of Con tents

Wind Operating Commitments — PUCT and NMPRC orders related to the Hale and Sagamore wind projects included certain operating and savings minimums. In general, annual generation must exceed a net capacity factor of 48%. If annual generation is below the guaranteed level, SPS would be obligated to refund an amount equal to foregone PTCs and fuel savings. Additionally, retail customer savings must exceed project costs included in base rates over the first ten years of operations. SPS would be required to refund excess costs, if any, after ten years of operations. As of Dec. 31, 2020, SPS does not expect refunds to be probable under either of these commitments.

Contract Termination — SPS and Lubbock Power & Light are parties to a 25-year, 170 MW partial requirements contract. In October 2020, Lubbock Power & Light initiated discussions with SPS concerning the interpretation of contractual terms related to early termination and default. If the parties are unable to reach resolution, the contract calls for the matter to proceed to arbitration. The amount of any damages depends on multiple factors and is currently unknown.

Environmental

New and changing federal and state environmental mandates can create financial liabilities for SPS, which are normally recovered through the regulated rate process.

Site Remediation

Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. SPS may sometimes pay all or a portion of the cost to remediate sites where past activities of SPS’ predecessors or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which SPS is alleged to have sent wastes to that site.

MGP, Landfill and Disposal Sites

SPS is currently remediating a former disposal site. SPS has recognized its best estimate of costs/liabilities that will result from final resolution of these issues, however, the outcome and timing is unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.

Environmental Requirements — Water and Waste

Federal CWA WOTUS Rule — In April 2020, the EPA and U.S. Army Corps of Engineers (“Agencies”) replaced the 2015 WOTUS rule and narrowed the definition of WOTUS (“2020 WOTUS Rule”). The new definition simplifies the process whether waters are subject to CWA jurisdiction and streamlines the permitting process. SPS does not anticipate that compliance costs will be material.

Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power plants that discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. In October 2020, the EPA published a final rule revising the regulations. SPS anticipates that compliance costs will not be material and will be fully recoverable through regulatory mechanisms.

Environmental Requirements — Air

Regional Haze Rules — The regional haze program requires SO2, nitrogen oxide and particulate matter emission controls at power plants to reduce visibility impairment in national parks and wilderness areas. The program includes BART and reasonable further progress. Texas’ first regional haze plan has undergone federal review.

All states are now subject to a second round of regional haze planning/rulemaking, focusing on additional reductions to meet reasonable progress requirements. Any additional impacts to SPS facilities are expected to be minimal.

BART Determination for Texas: The EPA has issued a revised final rule adopting a BART alternative Texas only SO2 trading program that applies to all Harrington and Tolk units. Under the trading program, SPS expects the allowance allocations to be sufficient for SO2 emissions. The anticipated costs of compliance are not expected to have a material impact; and SPS believes that compliance costs would be recoverable through regulatory mechanisms.

Several parties have challenged whether the final rule issued by the EPA should be considered to have met the requirements imposed in a Consent Decree entered by the United States District Court for the District of Columbia that established deadlines for the EPA to take final action on state regional haze plan submissions. The court has required status reports from the parties while the EPA works on the reconsideration rulemaking.

In December 2017, the National Parks Conservation Association, Sierra Club, and Environmental Defense Fund appealed the EPA’s 2017 final BART rule to the Fifth Circuit and filed a petition for administrative reconsideration. The court has held the litigation in abeyance while the EPA decided whether to reconsider the rule. In August 2018, the EPA started a reconsideration rulemaking. The EPA reaffirmed the rule in August 2020 with minor changes.

The 2020 EPA Action has been challenged. All pending actions could be consolidated, and may proceed in the Fifth Circuit or the D.C. Circuit, where a parallel challenge has been filed. The timing of final decisions is unclear.

Reasonable Progress Rule: In 2016, the EPA adopted a final rule establishing a federal implementation plan for reasonable further progress under the regional haze program for the state of Texas. The rule imposes SO2 emission limitations that would require the installation of dry scrubbers on Tolk Units 1 and 2, with compliance required by February 2021. Investment costs associated with dry scrubbers could be $600 million. SPS appealed the EPA’s decision and obtained a stay of the final rule.

In March 2017, the Fifth Circuit remanded the rule to the EPA for reconsideration, leaving the stay in effect. In a future rulemaking, the EPA will address whether SO2 emission reductions beyond those required in the BART alternative rule are needed at Tolk under the “reasonable progress” requirements. As states are now proceeding with the second regional haze planning period, the EPA may choose not to act on the remanded rule.

Implementation of the NAAQS for SO2 — The EPA has designated all areas near SPS’ generating plants as attaining the SO2 NAAQS with an exception. The EPA issued final designations, which found the area near the Harrington plant as “unclassifiable.” The area near the Harrington plant was monitored for the three years ending in 2019 and the monitoring showed the area to be exceeding the standard.

To address this issue, SPS negotiated an order with the TCEQ providing for the end of coal combustion and the conversion of the Harrington plant to a natural gas fueled facility by Jan. 1, 2025.

SPS believes compliance costs or the costs of alternative cost-effective generation will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial condition or cash flows.

Table of Con tents

AROs — AROs have been recorded for SPS’ assets.

SPS’ AROs were as follows:


	2020
(Millions of Dollars)	Jan. 1, 2020		Amounts Incurred (a)		Amounts Settled (b)		Accretion		Dec. 31, 2020 (c)
Electric
Steam and other production	$	51	$	—	$	(2)	$	3	$	52
Wind	16		33		—		1		50
Distribution	10		—		—		—		10
Total liability	$	77	$	33	$	(2)	$	4	$	112

(a)Amounts incurred related to the Sagamore wind farm placed in service in 2020.

(b)Amounts settled related mainly to asbestos abatement projects.

(c)No AROs were revised in 2020.


	2019
(Millions of Dollars)	Jan. 1, 2019		Amounts Incurred (a)		Amounts Settled (b)		Accretion		Cash Flow Revisions (c)		Dec. 31, 2019
Electric
Steam and other production	$	22	$	—	$	(2)	$	1	$	30	$	51
Wind	—		16		—		—		—		16
Distribution	9		—		—		1		—		10
Miscellaneous	1		—		—		—		(1)		—
Total liability	$	32	$	16	$	(2)	$	2	$	29	$	77

(a)Amounts incurred related to the Hale wind farm placed in service in 2019.

(b)Amounts settled related to asbestos abatement projects.

(c)In 2019, AROs were revised for changes in timing and estimates of cash flows. Changes in steam production AROs primarily related to the cost estimates to remediate ponds at production facilities.

Indeterminate AROs — Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of SPS’ facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2020. Therefore, an ARO has not been recorded for these facilities.

Leases

SPS evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. A contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine if the arrangement is a finance lease.

ROU assets represent SPS’ rights to use leased assets. The present value of future operating lease payments are recognized in current and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets.

Most of SPS’ leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the estimated incremental borrowing rate (weighted-average of 4.4%). SPS has elected the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from minimum lease payments for the purposes of lease accounting and disclosure. Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the balance sheet.

Operating lease ROU assets:


(Millions of Dollars)	Dec. 31, 2020		Dec. 31, 2019
PPAs	$	500	$	500
Other	50		48
Gross operating lease ROU assets	550		548
Accumulated amortization	(58)		(26)
Net operating lease ROU assets	$	492	$	522

Components of lease expense:


(Millions of Dollars)	2020		2019		2018
Operating leases
PPA capacity payments	$	48	$	48	$	51
Other operating leases (a)	3		5		8
Total operating lease expense (b)	$	51	$	53	$	59

(a)Includes short-term lease expense of $1 million, $2 million and $1 million for 2020, 2019 and 2018, respectively.

(b)PPA capacity payments are included in electric fuel and purchased power on the statements of income. Expense for other operating leases is included in O&M expense.

Commitments under operating leases as of Dec. 31, 2020:


(Millions of Dollars)	PPA (a) (b) Operating Leases		Other Operating Leases		Total Operating Leases
2021	$	46	$	3	$	49
2022	46		3		49
2023	46		3		49
2024	46		3		49
2025	46		3		49
Thereafter	359		43		402
Total minimum obligation	589		58		647
Interest component of obligation	(139)		(17)		(156)
Present value of minimum obligation	450		41		491
Less current portion					(28)
Noncurrent operating and finance lease liabilities					$	463

Weighted-average remaining lease term in years					13.0

(a)Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.

(b)PPA operating leases contractually expire at various dates through 2033.

PPAs and Fuel Contracts

Non-Lease PPAs — SPS has entered into PPAs with other utilities and energy suppliers with various expiration dates through 2024 for purchased power to meet system load and energy requirements and operating reserve obligations.

In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Capacity payments are contingent on the IPP meeting contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on financial results are mitigated through purchased energy cost recovery mechanisms.

Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts, were payments for capacity of $12 million, $20 million and $58 million in 2020, 2019 and 2018, respectively.

Table of Con tents

At Dec. 31, 2020, the estimated future payments for capacity that SPS is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:


(Millions of Dollars)	Capacity
2021	$	12
2022	12
2023	13
2024	6
2025	—
Thereafter	—
Total	$	43

Fuel Contracts — SPS has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal and natural gas requirements. These contracts expire between 2021 and 2033. SPS is required to pay additional amounts depending on actual quantities shipped under these agreements.

Estimated minimum purchases under these contracts as of Dec. 31, 2020:


(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2021	$	80	$	33	$	31
2022	35		—		31
2023	—		—		29
2024	—		—		16
2025	—		—		12
Thereafter	—		—		20
Total	$	115	$	33	$	139

VIEs

PPAs — Under certain PPAs, SPS purchases power from IPPs for which SPS is required to reimburse fuel costs, or to participate in tolling arrangements under which SPS procures the natural gas required to produce the energy that it purchases. SPS has determined that certain IPPs are VIEs. SPS is not subject to risk of loss from the operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity.

In addition, certain solar PPAs provide an option to purchase emission allowances or sharing provisions related to production credits generated by the solar facility under contract. These specific PPAs create a variable interest in the IPP.

SPS evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities. SPS concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.

SPS had approximately 1,197 MW of capacity under long-term PPAs at both Dec. 31, 2020 and 2019 with entities that have been determined to be VIEs. These agreements have expiration dates through 2041.

Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk plant from TUCO Inc. under contracts that will expire in December 2022. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing, and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.

SPS has not provided any significant financial support to TUCO, other than contractual payments for delivered coal. However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of fuel procurement costs. SPS has determined that TUCO is a VIE. SPS has concluded that it is not the primary beneficiary of TUCO, because SPS does not have the power to direct the activities that most significantly impact TUCO’s economic performance.


11. Related Party Transactions

Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including SPS. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. SPS uses the service provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned.

Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS have established a utility money pool arrangement.

See Note 5 for further information.

Significant affiliate transactions among the companies and related parties for the years ended Dec. 31:


(Millions of Dollars)	2020		2019		2018
Operating expenses:

Other operating expenses — paid to Xcel Energy Services Inc.	$	200	$	192	$	195
Interest expense	—		—		1

Accounts receivable and payable with affiliates at Dec. 31 were:


	2020				2019
(Millions of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	3	$	—	$	4	$	—
PSCo	6		—		—		—
Other subsidiaries of Xcel Energy Inc.	—		17		—		20
	$	9	$	17	$	4	$	20


12. Summarized Quarterly Financial Data (Unaudited)


	Quarter Ended
(Millions of Dollars)	March 31, 2020		June 30, 2020		Sept. 30, 2020		Dec. 31, 2020
Operating revenues	$	395	$	423	$	615	$	437
Operating income	53		80		163		63
Net income	43		72		127		53


	Quarter Ended
(Millions of Dollars)	March 31, 2019		June 30, 2019		Sept. 30, 2019		Dec. 31, 2019
Operating revenues	$	454	$	411	$	533	$	428
Operating income	75		82		135		55
Net income	54		59		105		45


ITEM 9 — CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Table of Con tents


ITEM 9A — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

SPS maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the CEO and CFO, allowing timely decisions regarding required disclosure. As of Dec. 31, 2020, based on an evaluation carried out under the supervision and with the participation of SPS’ management, including the CEO and CFO, of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that SPS’ disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No changes in SPS’ internal control over financial reporting occurred during SPS’ most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, SPS’ internal control over financial reporting. SPS maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. SPS has evaluated and documented its controls in process activities, general computer activities, and on an entity-wide level.

During the year and in preparation for issuing its report for the year ended Dec. 31, 2020 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, SPS conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, SPS did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board, as approved by the SEC and as indicated in SPS’ Management Report on Internal Controls over Financial Reporting, which is contained in Item 8 herein.

This annual report does not include an attestation report of SPS’ independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by SPS’ independent registered public accounting firm pursuant to the rules of the SEC that permit SPS to provide only management’s report in this annual report.


ITEM 9B — OTHER INFORMATION

None.

PART III

Items 10, 11, 12 and 13 of Part III of Form 10-K have been omitted from this report for SPS in accordance with conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly-owned subsidiaries.


ITEM 10 — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE


ITEM 11 — EXECUTIVE COMPENSATION


ITEM 12 — SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS


ITEM 13 — CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required under this Item is contained in Xcel Energy Inc.’s definitive Proxy Statement for its 2021 Annual Meeting of Shareholders, which is incorporated by reference.


ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm – Audit and Non-Audit Fees” in Xcel Energy Inc.’s Proxy Statement for its 2021 Annual Meeting of Shareholders which 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.

PART IV


ITEM 15 — EXHIBIT AND FINANCIAL STATEMENT SCHEDULES


1			Financial Statements
			Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2020.
			Report of Independent Registered Public Accounting Firm — Financial Statements
			Statements of Income — For each of the three years ended Dec. 31, 2020, 2019 and 2018.
			Statements of Comprehensive Income — For each of the three years ended Dec. 31, 2020, 2019 and 2018.
			Statements of Cash Flows — For each of the three years ended Dec. 31, 2020, 2019 and 2018.
			Balance Sheets — As of Dec. 31, 2020 and 2019.
			Statements of Common Stockholder’s Equity — For each of the three years ended Dec. 31, 2020, 2019 and 2018.

2			Schedule II — Valuation and Qualifying Accounts and Reserves for each of the years ended Dec. 31, 2020, 2019 and 2018.

3			Exhibits
*			Indicates incorporation by reference
+			Executive Compensation Agreements and Benefit Plans Covering Executive Officers and Directors

Table of Con tents


Exhibit Number	Description	Report or Registration Statement	Exhibit Reference
3.01*	Amended and Restated Articles of Incorporation dated Sept. 30, 1997	SPS Form 10-Q for the quarter ended Sept. 30, 2017	3.01
3.02*	By-Laws of SPS as Amended and Restated on Jan. 25, 2019	SPS Form 10-K for the year ended Dec. 31, 2018	3.02
4.01*	Indenture dated Feb. 1, 1999 between SPS and the Chase Manhattan Bank	SPS Form 8-K dated Feb. 25, 1999	99.2
4.02*	Supplemental Indenture dated Oct. 1, 2003 between SPS and JPMorgan Chase Bank, as successor Trustee, creating $100 million principal amount of 6% Series C and Series D Notes due 2033	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2003	4.04
4.03*	Supplemental Indenture dated Oct. 1, 2006 between SPS and the Bank of New York, as successor Trustee, creating $200 million principal amount of 5.6% Series E Notes due 2016 and $250 million principal amount of 6% Series F Notes due 2036	SPS Form 8-K dated Oct. 3, 2006	4.01
4.04*	Indenture dated as of Aug. 1, 2011 between SPS and U.S. Bank National Association, as Trustee	SPS Form 8-K dated Aug. 10, 2011	4.01
4.05*	Supplemental Indenture dated as of Aug. 3, 2011 between SPS and U.S. Bank National Association, as Trustee, creating $200 million principal amount of 4.50% First Mortgage Bonds, Series due 2041	SPS Form 8-K dated Aug. 10, 2011	4.02
4.06*	Supplemental Indenture dated as of June 1, 2014 between SPS and U.S. Bank National Association, as Trustee, creating $150 million principal amount of 3.30% First Mortgage Bonds, Series due 2024	SPS Form 8-K dated June 9, 2014	4.02
4.07*	Supplemental Indenture dated as of Aug. 1, 2016 between SPS and U.S. Bank National Association, as Trustee, creating $300 million principal amount of 3.40% First Mortgage Bonds, Series due 2046	SPS Form 8-K dated Aug. 12, 2016	4.02
4.08*	Supplemental Indenture dated as of Aug. 1, 2017 between SPS and U.S. Bank National Association, as Trustee, creating $450 million principal amount of 3.70% First Mortgage Bonds, Series due 2047	SPS Form 8-K dated Aug. 9, 2017	4.02
4.09*	Supplemental Indenture dated as of Oct. 1, 2018 between SPS and U.S. Bank National Association, as Trustee, creating $300 million principal amount of 4.40% First Mortgage Bonds, Series due 2048	SPS Form 8-K dated Nov. 5, 2018	4.02
4.10*	Supplemental Indenture dated as of June 1, 2019 between SPS and U.S. Bank National Association, as Trustee, creating $300 million principal amount of 3.75% First Mortgage Bonds, Series due 2049	SPS Form 8-K dated June 18, 2019	4.02
4.11*	Supplemental Indenture No. 8, dated as of May 1, 2020 between SPS and U.S. Bank National Association, as Trustee, creating $350 million principal amount of 3.15% First Mortgage Bonds, Series due 2050	SPS Form 8-K dated May 18, 2020	4.02
10.01*+	Xcel Energy Inc. Nonqualified Pension Plan (2009 Restatement)	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	10.02
10.02*+	Xcel Energy Senior Executive Severance and Change-in-Control Policy (2009 Restatement)	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	10.05
10.03*+	Second Amendment to Exhibit 10.02 dated Oct. 26, 2011	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011	10.18
10.04*+	Fifth Amendment Exhibit 10.02 dated May 3, 2016	Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2016	10.01
10.05*+	Seventh Amendment to Exhibit 10.02 dated May 7, 2018	Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018	10.01
10.06*+	Eighth Amendment to Exhibit 10.02 dated March 31, 2020	Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2020	10.02
10.07*+	Ninth Amendment to Exhibit 10.02 dated May 22, 2020	Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2020	10.01
10.08*+	Xcel Energy Inc. Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	10.17
10.09*+	Xcel Energy Inc. Executive Annual Incentive Plan (as amended and restated effective Feb. 17, 2010)	Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010	Appendix A
10.10*+	First Amendment to Exhibit 10.09 dated Feb. 20, 2013	Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013	10.01
10.11*+	Xcel Energy Inc. Executive Annual Incentive Award Plan Form of Restricted Stock Agreement	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009	10.08
10.12*+	Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement)	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	10.07
10.13*+	First Amendment to Exhibit 10.12 effective Nov. 29, 2011	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011	10.17
10.14*+	Second Amendment to Exhibit 10.12 dated May 21, 2013	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013	10.22
10.15*+	Third Amendment to Exhibit 10.12 dated Sept. 30, 2016	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016	10.01
10.16*+	Fourth Amendment to Exhibit 10.12 dated Oct. 23, 2017	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017	10.1
10.17*+	Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	10.34
10.18*+	Form of Terms and Conditions under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan for Awards of Restricted Stock Units and/or Performance Share Units	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	10.35
10.19*+	Form of Award Agreement for Restricted Stock Units and/or Performance Share Units under the Xcel Energy Inc. 2015 Omnibus Incentive Plan Award Agreement for awards since 2020	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019	10.32
10.20*+	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy Inc. as amended and restated effective Feb. 23, 2011	Xcel Energy Inc. Definitive Proxy Statement dated April 5, 2011	Appendix A
10.21*+	Stock Equivalent Program for Non-Employee Directors of Xcel Energy Inc. under the Xcel Energy Inc. 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 8-K dated May 20, 2015	10.02

Table of Con tents


10.22*+	Summary of Non-Employee Director Compensation, effective as of Sept. 1, 2019	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2020	10.22
10.23*+	Stock Program for Non-Employee Directors of Xcel Energy Inc. as Amended and Restated on Dec. 12, 2017 under the 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	10.36
10.24*+	Form of Services Agreement between Xcel Energy Services Inc. and utility companies	Xcel Energy Inc. Form U5B dated Nov. 16, 2000	H-1
10.25*	Third Amended and Restated Credit Agreement, dated as of June 7, 2019 among SPS, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, Wells Fargo Bank, National Association, MUFG Bank, Ltd., and Citibank, N.A., as Documentation Agents	Xcel Energy Inc. Form 8-K dated June 7, 2019	99.04
23.01	Consent of Independent Registered Public Accounting Firm.
31.01	Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH	Inline XBRL Schema
101.CAL	Inline XBRL Calculation
101.DEF	Inline XBRL Definition
101.LAB	Inline XBRL Label
101.PRE	Inline XBRL Presentation
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

SCHEDULE II

Southwestern Public Service Co. Valuation and Qualifying Accounts Years Ended Dec. 31


	Allowance for bad debts
(Millions of Dollars)	2020		2019		2018
Balance at Jan. 1	$	5	$	6	$	6
Additions charged to costs and expenses	6		6		5
Additions charged to other accounts (a)	2		2		1
Deductions from reserves (b)	(5)		(9)		(6)
Balance at Dec. 31	$	8	$	5	$	6

(a)Recovery of amounts previously written-off.

(b)Deductions related primarily to bad debt write-offs.


ITEM 16 — FORM 10-K SUMMARY

None.

Table of Con tents

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned thereunto duly authorized.


						SOUTHWESTERN PUBLIC SERVICE COMPANY

Feb. 17, 2021						/s/ BRIAN J. VAN ABEL
						Brian J. Van Abel
						Executive Vice President, Chief Financial Officer and Director

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the date indicated above.


/s/ BEN FOWKE						/s/ DAVID T. HUDSON
Ben Fowke						David T. Hudson
Chairman, Chief Executive Officer and Director						President and Director
(Principal Executive Officer)

/s/ BRIAN J. VAN ABEL						/s/ JEFFREY S. SAVAGE
Brian J. Van Abel						Jeffrey S. Savage
Executive Vice President, Chief Financial Officer and Director						Senior Vice President, Controller
(Principal Financial Officer)						(Principal Accounting Officer)

/s/ ROBERT C. FRENZEL
Robert C. Frenzel
Executive Vice President, Chief Operating Officer and Director

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT

SPS has not sent, and does not expect to send, an annual report or proxy statement to its security holder.