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XEL Southwestern Public Service

Filed: 21 Feb 20, 4:03pm
 

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, 2019
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 Mexico75-0575400
(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 N/A N/A
Securities registered pursuant to Section 12(g) of the Act:  None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.   Yes  No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.   Yes  No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes    No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).   Yes   No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated Filer  Accelerated Filer  Non-accelerated Filer Smaller Reporting Company Emerging Growth Company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).   Yes    No
As of Feb. 21, 2020, 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 2020 Annual Meeting of Shareholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 6, 2020. 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

This Form 10-K is filed by SPS. SPS is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available on various filings with the SEC. This report should be read in its entirety.

2


PART I
ITEM l — BUSINESS
Definitions of Abbreviations
Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
NSP-MinnesotaNorthern States Power Company, a Minnesota corporation
NSP-WisconsinNorthern States Power Company, a Wisconsin corporation
PSCoPublic Service Company of Colorado
SPSSouthwestern Public Service Company
Utility subsidiariesNSP-Minnesota, NSP-Wisconsin, PSCo and SPS
Xcel EnergyXcel Energy Inc. and its subsidiaries
Federal and State Regulatory Agencies
D.C. CircuitUnited States Court of Appeals for the District of Columbia Circuit
EPAUnited States Environmental Protection Agency
FERCFederal Energy Regulatory Commission
IRSInternal Revenue Service
NERCNorth American Electric Reliability Corporation
NMPRCNew Mexico Public Regulation Commission
NPRMNotice of Proposed Rulemaking
PHMSAPipeline and Hazardous Materials Safety Administration
PUCTPublic Utility Commission of Texas
SECSecurities and Exchange Commission
TCEQTexas Commission on Environmental Quality
Electric and Resource Adjustment Clauses
DCRFDistribution cost recovery factor
DSMDemand side management
EEEnergy efficiency
EECRFEnergy efficiency cost recovery factor
FPPCACFuel and purchased power cost adjustment clause
PCRFPower cost recovery factor
RPSRenewable portfolio standards
TCRFTransmission cost recovery factor (recovers transmission infrastructure improvement costs and changes in wholesale transmission charges)
Other
ADITAccumulated deferred income taxes
AFUDCAllowance for funds used during construction
ALJAdministrative Law Judge
AROAsset retirement obligation
ASCFASB Accounting Standards Codification
ASUFASB Accounting Standards Update
BARTBest available retrofit technology
CEOChief executive officer
CFOChief financial officer
C&ICommercial and Industrial
CorpsU.S. Army Corps of Engineers
CWIPConstruction work in progress
DSMDemand side management
ELGEffluent limitations guidelines
ETREffective tax rate
FASBFinancial Accounting Standards Board
FTRFinancial transmission right
GAAPGenerally accepted accounting principles
GHGGreenhouse gas
IMIntegrated Marketplace
IPPIndependent power producing entity
IRPIntegrated Resource Plan
 
ITCInvestment tax credit
MGPManufactured gas plant
Moody’sMoody’s Investor Services
NAAQSNational Ambient Air Quality Standard
Native loadCustomer demand of retail and wholesale customers whereby a utility has an obligation to serve under statute or long-term contract.
NAVNet asset value
NOLNet operating loss
O&MOperating and maintenance
OATTOpen Access Transmission Tariff
PPAPurchased power agreement
PRPPotentially responsible party
PTCProduction tax credit
RECRenewable energy credit
ROEReturn on equity
ROFRRight-of-first-refusal
ROURight-of-use
RTORegional Transmission Organization
SERPSupplemental executive retirement plan
SO2
Sulfur dioxide
SPPSouthwest Power Pool, Inc.
Standard & Poor’sStandard & Poor’s Ratings Services
TCJA2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act
VIEVariable interest entity
Measurements
KVKilovolts
KWhKilowatt hours
MMBtuMillion British thermal units
MWMegawatts
MWhMegawatt hours
ppbParts per billion


3


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, assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2019 (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: 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 and subsidiaries’ ability to recover costs from customers; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of SPS to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; our subsidiaries’ ability to make dividend payments; tax laws; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; and costs of potential regulatory penalties.
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.
Company Overview
 
   
spsstatea09.jpg
  
     
Electric customers0.4 million  SPS was incorporated in 1921 under the laws of New Mexico. SPS conducts business in Texas and New Mexico and generates, purchases, transmits, distributes and sells electricity.
Total assets$7.9 billion  
Rate base$4.9 billion  
ROE9.71%  
Electric generating capacity4,804 MW  
Electric transmission lines (conductor miles)

38,418 miles  
Electric distribution lines (conductor miles)

21,810 miles  
     
     
Electric Operations
SPS had electric sales volume of 30,894 (millions of KWh), 395,828 customers and electric revenues of $1,825.8 (millions of dollars) for 2019.
 
chart-ec76fb91dfe685925d8a01.jpgchart-16867990876570a4703a01.jpgchart-7f45e10a623d65563cfa01.jpg
 

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Sales/Revenue Statistics
  2019 2018
KWH sales per retail customer 53,123
 52,074
Revenue per retail customer $3,147
 $3,124
Residential revenue per KWh 
10.04¢ 
9.92¢
Large C&I revenue per KWh 
4.01¢ 
4.08¢
Small C&I revenue per KWh 
7.17¢ 
7.22¢
Total retail revenue per KWh 
5.92¢ 
6.00¢
Owned and Purchased Energy Generation — 2019
chart-6cdca55b7d6d92087f7a01.jpg
Electric Energy Sources
Total electric generation by source (including energy market purchases) for the year ended Dec. 31, 2019:
 
chart-b86560abe2fa4e7cc7aa01.jpg
*Distributed generation from the Solar*Rewards® program is not included (approximately 12.9 million KWh for 2019).
 
Renewable Energy Sources
SPS’ renewable energy portfolio includes wind and solar power from both owned generating facilities and PPAs. Renewable percentages will vary year over year based on system additions, weather, system demand and transmission constraints.
See Item 2 — Properties for further information.
 
Renewable energy as a percentage of total energy for 2019:
chart-03ce4be280626248555a01.jpg
(a) 
Includes biomass and hydroelectric.
Wind Energy Sources
Owned — Owned and operated wind farms with corresponding capacity:
2019 2018
Wind Farms Capacity Wind Farms Capacity
1 478 MW  
PPAs — Number of PPAs with range:
2019 2018
PPAs Range PPAs Range
18 0.7 MW - 250.0 MW 18 0.7 MW - 250.0 MW
Capacity — Wind capacity:
2019 2018
2,045 MW 1,565 MW
Average Cost (PPAs) — Average cost per MWh of wind energy under existing PPAs:
2019 2018
$25 $26
Wind Energy Development
SPS placed approximately 460 MW of wind into service during 2019:
Project Capacity
Hale 460 MW
SPS currently has approximately 522 MW of wind under development or construction with an estimated completion date of 2020:
Project Capacity Estimated Completion
Sagamore 522 MW 2020
Solar Energy Sources
Solar energy PPAs:
Type Capacity
Distributed Generation 10 MW
Utility-Scale 191 MW

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Fossil Fuel Energy Sources
SPS’ fossil fuel energy portfolio includes coal and natural gas power from both owned generating facilities and PPAs.
See Item 2 — Properties for further information.
Coal Energy Sources
SPS has two coal plants with approximately 2,100 MW of total 2019 net summer dependable capacity.
SPS plans to continue to evaluate its coal fleet for other potential early coal plant retirements as part of state resource plans or other regulatory proceedings.
Coal Fuel Cost
Delivered cost per MMBtu of coal consumed for owned electric generation and percentage of total fuel requirements:
  Coal
  Cost Percent
2019 $2.19
 45%
2018 2.04
 56
Natural Gas Energy Sources
SPS has eight natural gas plants with approximately 2,300 MW of total 2019 net summer dependable capacity.
Natural gas supplies, transportation and storage services for power plants are procured to provide an adequate supply of fuel. Remaining requirements are procured through a liquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to natural gas indices. Natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes or payments in lieu of delivery.
Natural Gas Cost
Delivered cost per MMBtu of natural gas consumed for owned electric generation and percentage of total fuel requirements:
  Natural Gas
  Cost Percent
2019 $1.14
 55%
2018 2.24
 44
Capacity and Demand
Uninterrupted system peak demand and occurrence date:
System Peak Demand (in MW)
2019 2018
4,261
 Aug. 5 4,648
 July 19
Transmission
Transmission lines deliver electricity over long distances from power sources to transmission substations closer to homes and businesses. A strong transmission system ensures continued reliable and affordable service, ability to meet state and regional energy policy goals, and support a diverse generation mix, including renewable energy. SPS owns more than 38,400 conductor miles of transmission lines across its service territory.
 
During 2019, SPS completed the following transmission projects:
Project Miles Size
TUCO-Yoakum-Hobbs 64
 345 KV
NEF-Cardinal 15
 115 KV
Potash Junction-Livingston Ridge 15
 115 KV
Mustang-Shell 9
 115 KV
North Loving-South Loving 3
 115 KV
Cunningham-Monument Tap 7
 115 KV
Upcoming transmission projects:
Project Miles Size Completion Date
TUCO-Yoakum-Hobbs 106
 345 KV 2020
Eddy-Kiowa 34
 345 KV 2020

Public Utility Regulation
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Regulatory Body Additional Information on Regulatory Authority
PUCT 
Retail electric operations, rates, services, construction of transmission or generation and other aspects of electric operations.
Texas municipalities have original jurisdiction over rates in those communities. The municipalities’ rate setting decisions are subject to PUCT review.
NMPRC Retail electric operations, rates services, construction of transmission or generation and other aspects of electric operations.
FERC Wholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce.
SPP RTO and SPP IM Wholesale Market SPS is a transmission-owning member of the SPP RTO and operates within the SPP RTO and SPP IM wholesale market. SPS is authorized to make wholesale electric sales at market-based prices.
Recovery Mechanisms
Mechanism Additional Information
DCRF Recovers distribution costs not included in rates in Texas.
EECRF Recovers costs for energy efficiency programs in Texas.
EE Rider Recovers costs for energy efficiency programs in New Mexico.
FPPCAC Adjusts monthly to recover fuel and purchased power costs in New Mexico.
PCRF Allows recovery of purchased power costs not included in Texas rates.
RPS Recovers deferred costs for renewable energy programs in New Mexico.
TCRF Recovers transmission infrastructure improvement costs and changes in wholesale transmission charges not included in Texas base rates.
Fixed Fuel and Purchased Recovery Factor Provides for recovery of energy expenses. Regulations require refunding or surcharging over- or under- recovery amounts, including interest, when they exceed 4% of the utility’s annual fuel and purchased energy costs on a rolling 12-month basis, if this condition is expected to continue.
Wholesale Fuel and Purchased Energy Cost Adjustment SPS recovers production, fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased energy cost adjustment clause accepted by the FERC. Wholesale customers also pay the jurisdictional allocation of production costs.







6


Resource Plan
In December 2018, the NMPRC issued a final order accepting SPS’ IRP.
SPS is forecasting a surplus capacity of 382 MW in 2028, but a capacity deficit of approximately 2,896 MW in 2038. SPS’ optimal resource plan for the planning period incorporates the addition of wind, simple cycle combustion turbine generation, combined cycle energy and entering PPAs. Various factors may impact this IRP, which could potentially require updates to the action plan and will be the subject of future IRPs, including:
New and revised environmental regulations;
Impacts of variability due to participation in the SPP;
Customer expectations;
Technological advances;
Groundwater aquifer depletion at SPS’ Tolk Station;
Aging generation fleet;
Load growth and gas price variability;
Changes to tax credits and incentives; and
Changes to renewable portfolio standard acquisitions.
SPS is required to file an IRP in New Mexico every three years and will file its next IRP in July 2021.
Purchased Power Arrangements and Transmission Service Providers
SPS expects to use electric generating stations, power purchases, DSM and new generation options to meet its system capacity requirements.
Purchased Power — SPS purchases power from other utilities and IPPs. Long-term purchased power contracts typically require periodic capacity and energy charges. SPS also makes short-term purchases to meet system load and energy requirements to replace owned generation, meet operating reserve obligations or obtain energy at a lower cost.
Purchased Transmission Services — SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers.
Natural Gas
SPS does not provide 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.
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 systems of Xcel Energy Inc.’s utility subsidiaries on a comparable basis to serve their native load.
FERC Order No. 1000 established competition for construction and operation of certain new electric transmission facilities. State utilities commissions have also created resource planning programs that promote competition for electricity generation resources used to provide service to retail customers.
SPS has franchise agreements with cities subject to periodic renewal; however, a city could seek alternative means to access electric power, such as municipalization. No municipalization activities are occurring presently.
While facing these challenges, SPS believes its rates and services are competitive with alternatives currently available.
Environmental
Environmental Regulation
Our facilities are regulated by federal and state environmental agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. SPS has received necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems.
Our facilities have been designed and constructed to operate in compliance with applicable environmental standards and related monitoring and reporting requirements. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or what effect future laws or regulations may have.
We may be required to incur capital expenditures in the future for remediation of MGP and other sites if it is determined that prior compliance efforts are not sufficient.
There are significant present and 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.


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If future environmental regulations do not take into consideration investments already made or if additional initiatives or emission reductions are required, substantial costs may be incurred.
In July 2019, the EPA adopted the Affordable Clean Energy rule, which requires states to develop plans for GHG reductions from coal-fired power plants. The state plans, due to the EPA in July 2022, will evaluate and potentially require heat rate improvements at existing coal-fired plants. It is not yet known how these state plans will affect SPS’ existing coal plants, but they could require substantial additional investment, even in plants slated for retirement. SPS believes, based on prior state commission practice, the cost of these initiatives or replacement generation would be recoverable through rates.
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, 2019, SPS had 1,158 full-time employees and no part-time employees, of which 779 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
The Board of Directors is responsible for the oversight of material risk and maintaining an effective risk monitoring process. Management and the Board of Directors have responsibility for overseeing the identification and mitigation of key risks.
At a threshold level, SPS maintains a robust compliance program through promoting a culture of compliance beginning with the tone at the top. The risk mitigation process includes adherence to our code of conduct and compliance policies, operation of formal risk management structures and overall business management. SPS further mitigates inherent risks through formal risk committees and corporate functions such as internal audit, and internal controls over financial reporting and legal.
Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Identification and risk analysis occurs formally through risk assessment conducted by senior management, the financial disclosure process, hazard risk procedures, internal audit and compliance with financial and operational controls.
Management also identifies and analyzes risk through the business planning process, development of goals and establishment of key performance indicators, including identification of barriers to implementing our strategy. The business planning process also identifies likelihood and mitigating factors to prevent the assumption of inappropriate risk to meet goals.
Management communicates regularly with the Board of Directors and its sole stockholder regarding risk. Senior management presents and communicates a periodic risk assessment to the Board of Directors, providing information on the risks that management believes are material, including financial impact, timing, likelihood and mitigating factors. The Board of Directors regularly reviews management’s key risk assessments, which includes areas of existing and future financial, operational and security risks.
 
Overall, the oversight, management and mitigation of risk is an integral and continuous part of the Board of Directors’ governance of SPS. Processes are in place to ensure appropriate risk oversight, as well as identification and consideration of new risks.
Risks Associated with Our Business
Operational Risks
Our electric transmission and distribution and gas operations involve numerous risks that may result in accidents and other operating risks and costs.
Our natural gas transmission activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses. 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.
Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the Department of Transportation’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with the PHMSA regulations and systematically monitor and renew infrastructure over time, however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations.
Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services.
Our utility operations are subject to long-term planning and project risks.
Most electric utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of when they are brought in-service subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. Our long-term resource plan is dependent on our ability to obtain required approvals, develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.
In addition, the long-term nature of both our planning and our asset lives are subject to risk. The electric utility sector is undergoing a period of significant change. For example, increases in energy efficiency, wider adoption of lower cost renewable generation, distributed generation and shifts away from coal generation to decrease carbon emissions and increasing use of natural gas in electric generation driven by lower natural gas prices. Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, as well as stranded costs if SPS is not able to fully recover costs and investments.

8


Changing customer expectations and technologies are requiring significant investments in advanced grid infrastructure, which increases exposure to technology obsolescence.
Evolving stakeholder preference for lower emission generation sources may pressure our investments in natural gas generation and delivery. The magnitude and timing of resource additions and changes in customer demand may not coincide while customer preference for resource generation may change, which introduces further uncertainty into long-term planning. Additionally, multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets.
We are subject to longer-term availability of inputs such as coal, natural gas, uranium and water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.
We are subject to commodity risks and other risks associated with energy markets and energy production.
In the event fuel costs increase, customer demand could decline and bad debt expense may rise, which may have a material impact on our results of operations. Despite existing fuel recovery mechanisms, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows.
A significant disruption in supply could cause us to seek alternative supply services at potentially higher costs and supply shortages may not be fully resolved, which could cause disruptions in our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments could negatively impact our cash flows and results of operations.
We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result, we are subject to market supply and commodity price risk.
Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability.
Failure to attract and retain a qualified workforce could have an adverse effect on operations.
Certain 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. Competition for skilled employees is high in the areas of business operations. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. We have seen a tightening of supply for engineers and skilled laborers in certain markets and are implementing plans to retain these employees. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.
 
Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.
We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance standards, progress payments, insurance requirements and security for performance. Poor vendor performance could impact ongoing operations, restoration operations, our reputation and could introduce financial risk or risks of fines.
We are a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.
All of the members of our Board of Directors, as well as many of our executive officers, are officers of Xcel Energy Inc. Our Board or Directors makes determinations with respect to a number of significant corporate events, including the payment of our dividends.
We have historically paid quarterly dividends to Xcel Energy Inc. In 2019, 2018 and 2017 we paid $332.7 million, $131.0 million and $108.8 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs. This could adversely affect our liquidity. The most restrictive dividend limitation for SPS is imposed by its state regulatory commissions. State regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy Inc., by requiring a minimum equity-to-total capitalization ratio.
See Note 5 to the financial statements for further information.
Financial Risks
Our profitability depends on our ability to recover costs from our customers and changes in regulation may impair our ability to recover costs from our customers.
We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.
The profitability of our operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on our capital investment. Our rates are generally regulated and based on an analysis of our costs incurred in a test year. We are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates we are allowed to charge may or may not match our costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.
There can also be no assurance that our regulatory commissions will judge all our costs to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery. Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair our ability to recover costs historically collected from customers, or we could exceed caps on capital costs (e.g., wind projects) required by commissions and result in less than full recovery.
Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.

9


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 ratings will remain in effect, or that a rating will not be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, significantly lower returns on equity, changes to equity ratios and impacts of tax policy may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies. Any downgrade could lead to higher borrowing costs and could impact our ability to access capital markets. Also, we may enter into contracts that require posting of collateral or settlement of applicable contracts if credit ratings fall below investment grade.
We are subject to capital market and interest rate risks.
Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Capital markets are global and impacted by issues and events throughout the world. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital market disruption and financial market distress could prevent us from issuing short-term commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results.
We are subject to credit risks.
Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and local economies in the geographic areas we serve, including local unemployment rates.
Credit risk also includes the risk that various counterparties that owe us money or product will become insolvent and may breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and incur losses.
We may at times have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, such as 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 in the form of letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract.
 
As we are a subsidiary of Xcel Energy Inc. we may be negatively affected by events impacting the credit or liquidity of Xcel Energy Inc. and its affiliates.
If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s debt securities below investment grade, it would increase Xcel Energy Inc.’s cost of capital and restrict its access to the capital markets. This could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.
As of Dec. 31, 2019, Xcel Energy Inc. and its utility subsidiaries had approximately $17.4 billion of long-term debt and $1.3 billion of short-term debt and current maturities. Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.
Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees. As of Dec. 31, 2019, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $2.0 million and immaterial exposure. Xcel Energy also had additional guarantees of $60.4 million at Dec. 31, 2019 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time. If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.
Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.
We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. Estimates and assumptions may change. In addition, the Pension Protection Act changed the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and related contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year due to high numbers of retirements or employees leaving would trigger settlement accounting and could require SPS to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future liabilities 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.

10


Federal tax law may significantly impact our business.
SPS collects through regulated rates estimated federal, state and local tax payments. 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. There could be timing delays before regulated rates provide for realization of tax changes in revenues. In addition, certain IRS tax policies such as tax normalization may impact our ability to economically deliver certain types of resources relative to market prices.
Macroeconomic Risks
Economic conditions impact our business.
Our operations are affected by local, national and worldwide economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay their bills which could lead to additional bad debt expense.
Additionally, SPS faces competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies. We operate in a capital intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates.
Operations could be impacted by war, terrorism or other events.
Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows.
The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have already incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.
A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, our brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility.
We also face the risks of possible loss of business due to significant events such as severe storm, severe temperature extremes, wildfires, widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a disruption of work force within our operating systems (or on a neighboring system).
The recent coronavirus outbreak in China is an example of how major catastrophic events throughout the world may disrupt our business. While we are a domestic company, the Company participates in a global supply chain, which includes materials and components that are sourced from China. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to reliably serve our customers.
 
Disruption due to events such as those noted above could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material impact on our results of operations, financial condition or cash flows.
SPS participates in biennial grid security and emergency response exercises (GridEx). These efforts, led by the NERC, test and further develop the coordination, threat sharing and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid.
A cyber incident or security breach could have a material effect on our business.
We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors and other individuals.
Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error. Our industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States and individuals. Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability.
Our generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers’ operations, could also negatively impact our business.
Our supply chain for procurement of digital equipment 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.


11


Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.
Our electric utility business is seasonal and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations, or cash flows.
Public Policy Risks
We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.
Legislative and regulatory responses related to climate change and new interpretations of existing laws create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. Such regulations could impose substantial costs on our system.
We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.
Although the United States has not adopted any international or federal GHG emission reduction targets, many states and localities may continue to pursue climate policies in the absence of federal mandates. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation or retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. While those actions likely would have put Xcel Energy in a good position to meet federal or international standards being discussed, the lack of federal action does not adversely impact these state-endorsed actions and plans.
If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.
Increased risks of regulatory penalties could negatively impact our business.
The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. The FERC can impose penalties of up to $1.3 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties. In the event of serious incidents, these agencies have become more active in pursuing penalties. Some states additionally have the authority to impose substantial penalties. If a serious reliability, cyber or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows.
 
Environmental Risks
We are subject to environmental laws and regulations, with which compliance could be difficult and costly.
We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements. Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Environmental regulations may also lead to shutdown of existing facilities. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate (i.e., clean-up) sites where our past activities, or the activities of other parties, caused environmental contamination.
We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or the O&M costs incurred to comply with the requirements.
In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.
We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.
Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events.
Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues.
Climate change may impact a region’s economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers, which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.
Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers.

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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 units and increase the price paid 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 189
 
Harrington-Amarillo, TX, 3 Units Coal 1976 - 1980 1,018
 
Jones-Lubbock, TX, 2 Units Natural Gas 1971 - 1974 486
 
Maddox-Hobbs, NM, 1 Unit Natural Gas 1967 112
 
Nichols-Amarillo, TX, 3 Units Natural Gas 1960 - 1968 457
 
Plant X-Earth, TX, 4 Units Natural Gas 1952 - 1964 411
 
Tolk-Muleshoe, TX, 2 Units Coal 1982 - 1985 1,067
 
Combustion Turbine:       
Cunningham-Hobbs, NM, 2 Units Natural Gas 1997 209
 
Jones-Lubbock, TX, 2 Units Natural Gas 2011 - 2013 334
 
Maddox-Hobbs, NM, 1 Unit Natural Gas 1963 - 1976 61
 
Wind:       
Hale-Plainview, TX, 239 Units (b)
 Wind 2019 460
 
    Total 4,804
 
(a) 
Summer 2019 net dependable capacity.
(b) 
Values disclosed are the maximum generation levels for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2019:
Conductor Miles 
345 KV9,566
230 KV9,784
115 KV14,662
Less than 115 KV26,216
SPS had 452 electric utility transmission and distribution substations at Dec. 31, 2019.




 
Natural gas utility mains at Dec. 31, 2019:
Miles 
Transmission20
Distribution
ITEM 3 — LEGAL PROCEEDINGS
SPS is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on SPS’ financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.
See Note 10 to the financial statements, Item 1 and Item 7 for further information.
ITEM 4 — MINE SAFTEY DISCLOSURES
None.
PART II
ITEM 5 — MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASE 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 2019 and 2018 were as follows:
(Millions of Dollars) 2019 2018
First quarter $57.5
 $33.3
Second quarter 83.4
 30.7
Third quarter 114.6
 40.0
Fourth quarter 78.3
 45.4
ITEM 6 — SELECTED FINANCIAL DATA
This is 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).

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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, 2019 and Dec. 31, 2018, there were no adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings.
Results of Operations
2019 Comparison with 2018
SPS’ net income was approximately $263.1 million for 2019, compared with net income of $213.3 million for 2018. The increase was primarily due to higher electric margins attributable to purchased capacity costs, regulatory rate outcomes, demand revenue, higher AFUDC related to the Hale wind farm and lower income taxes, partially offset by increased interest and depreciation expense.
Electric Margin
Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Changes in fuel or purchased power costs can impact earnings as the fuel and purchased power cost recovery mechanisms of the Texas and New Mexico jurisdictions may not allow for complete recovery of all expenses. Electric revenues and margin for 2018 are before and after the impact of the TCJA:
 
(Millions of Dollars) 2019 2018
Electric revenues before TCJA impact $1,825.8
 $1,988.1
Electric fuel and purchased power before TCJA impact (875.4) (1,050.1)
Electric margin before TCJA impact $950.4
 $938.0
TCJA impact (offset as a reduction in income tax) 
 (48.3)
Electric margin $950.4
 $889.7
The following tables summarize the components of the changes in electric margin for the year ended Dec. 31, 2019:
(Millions of Dollars) 2019 vs. 2018
Purchase capacity costs $40.7
Regulatory rate outcomes 24.7
Demand revenue 24.7
Wholesale transmission revenue 13.7
Sales growth 5.9
Non-fuel riders 4.3
Firm wholesale (26.2)
PTC sharing (16.0)
Estimated weather impact (5.2)
Other (net) (5.9)
Total increase in electric margin $60.7
Non-Fuel Operating Expense and Other Items
Depreciation and Amortization — Depreciation and amortization expense increased $20.3 million, or 9.7%, for 2019 compared with the prior year. The increase was primarily due to the Hale wind farm being placed into service and increased capital investments.
AFUDC, Equity and Debt — AFUDC increased by $11.1 million, or 39.6% for 2019 compared with the prior year. The increase was primarily due to the Hale and Sagamore wind farms.
Interest Charges — Interest charges increased 14.8 million, or 17.5% for 2019 compared with the prior year. The increase was primarily due to higher debt levels to fund capital investments.
Income Taxes — Income tax expense decreased $13.3 million for 2019 compared with the prior year. The decrease was primarily driven by wind PTCs; partially offset by higher pretax income. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income. The ETR was 8.9% for 2019 compared with 15.4% for 2018. The lower ETR in 2019 was primarily due to the items referenced above.
2018 Comparison with 2017
A discussion of changes in SPS’ results of operations and liquidity and capital resources from the year ended Dec. 31, 2017 to Dec. 31, 2018 can be found in Part II, “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year 2018, which was filed with the SEC on Feb. 22, 2019. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.







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Regulation
FERC and State Regulation The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, asset transactions and mergers, accounting practices and certain other activities of SPS, including enforcement of NERC mandatory electric reliability standards. State and local agencies have jurisdiction over many of SPS’ activities, including regulation of retail rates and environmental matters.
 
Xcel Energy, which includes SPS, attempts to mitigate the risk of regulatory penalties through formal training on prohibited practices and a compliance function that reviews interaction with the markets under FERC and Commodity Futures Trading Commission jurisdictions.

Pending Regulatory Proceedings
Mechanism Utility Service Amount Requested (in millions) 
Filing
Date
 Approval Additional Information
SPS (NMPRC)
Rate Case Electric $51 July 2019 Pending 
In July 2019, SPS filed an electric rate case with the NMPRC seeking an increase in retail electric base rates of approximately $51 million. The rate request is based on an ROE of 10.35%, an equity ratio of 54.77%, a rate base of approximately $1.3 billion and a historic test year with rate base additions through Aug. 31, 2019. In December 2019, SPS revised its base rate increase request to approximately $47 million, based on an ROE of 10.10% and updated information. The request also included an increase of $14.6 million for accelerated depreciation including the early retirement of the Tolk Coal Plant in 2032.
On Jan. 13, 2020, SPS and various parties filed an uncontested comprehensive stipulation. The stipulation includes a base rate revenue increase of $31 million, based on an ROE of 9.45% and an equity ratio of 54.77%. The stipulation also includes an acceleration of depreciation on the Tolk Coal Plant to reflect early retirement in 2037, which results in a total increase in depreciation expense of $8 million. The Signatories will not oppose the full application of depreciation rates associated with the 2032 retirement date in SPS’ next base rate case. SPS anticipates final rates will go into effect in the second or third quarter of 2020.



Texas Electric Rate Case
In August 2019, SPS filed an electric rate case with the PUCT seeking an increase in retail electric base rates of approximately $141 million. The filing requests an ROE of 10.35%, a 54.65% equity ratio, a rate base of approximately $2.6 billion and is built on a 12 month period that ended June 30, 2019. In September 2019, SPS filed an update to the electric rate case and revised its requested increase to $136.5 million.
On Feb. 10, 2020, the Alliance of Xcel Municipalities (AXM), Texas Industrial Energy Consumers (TIEC), Office of Public Utility Counsel (OPUC) and the Department of Energy (DOE), filed testimony along with several other parties.
On Feb. 18, 2020, the PUCT Staff filed testimony that included certain adjustments and various ring-fencing measures.
Proposed modifications to SPS’ request:
(Millions of Dollars) Staff AXM OPUC TIEC DOE
SPS Direct Testimony $136.5
 $136.5
 $136.5
 $136.5
 $136.5
           
Recommended base rate adjustments:        
ROE (22.1) (24.2) (15.2) (20.5) (23.8)
Capital structure (6.9) (10.4) 
 (6.9) (3.1)
Tolk/Harrington O&M disallowance 
 (6.6) 
 
 
Distribution and Transmission Capital Disallowances (a)
 (6.5) 
 
 
 
Depreciation expense (7.5) (14.5) (8.3) (20.4) 
Excess ADIT unprotected plant 
 
 (6.9) 
 
Income Tax Expense Differences (11.6) 
 
 
 
Other, net (6.8) (6.1) (0.4) (0.6) 
Total Adjustments (61.4) (61.8) (30.8) (48.4) (26.9)
Total proposed revenue change $75.1
 $74.7
 $105.7
 $88.1
 $109.6

 
Recommended Position Staff AXM 
OPUC (b)
 TIEC DOE
ROE 9.1% 9.0% % 9.2% 9.0%
Equity Ratio 51.00% 50.00% % 51.00% 53.00%
(a) 
Staff recommends exclusion of approximately $134 million in transmission, distribution, and general plant in service in this rate case resulting in an approximate $7 million decrease to the revenue requirement.
(b) 
OPUC did not provide a recommendation for an ROE or equity ratio. For illustrative purposes an ROE of 9.5% was used.
The next steps in the procedural schedule are expected to be as follows:
Rebuttal testimony — March 11, 2020; and
Public hearing begins — March 30, 2020.
A PUCT decision and implementation of final rates is anticipated in the third quarter of 2020.
Texas State ROFR
In May 2019, the Governor signed into law Senate Bill 1938, which grants incumbent utilities a ROFR to build transmission infrastructure when it directly interconnects to the utility’s existing facility. In June 2019, a complaint was filed in the United States District Court for the Western District of Texas claiming the new ROFR law to be unconstitutional. The Texas Attorney General has made a motion to dismiss the federal court complaint. A ruling on the dismissal motion is expected in the first quarter of 2020.
See Rate Matters within Note 10 to the financial statements for further information.






15


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 some credit and non-performance risk.
Distress in the financial markets may impact counterparty risk, the fair value of the securities in the pension fund, and SPS’ ability to earn a return on short-term investments.
Commodity Price Risk — SPS is exposed to commodity price risk in its electric operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products. Commodity price risk is also managed through the use of financial derivative instruments.
SPS’ risk management policy allows it to manage commodity price risk per commission approved hedge plans.
Wholesale and Commodity Trading Risk — SPS conducts wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments, including derivatives. SPS’ risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee.
Interest Rate Risk — SPS is subject to interest rate risk. SPS’ risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.
A 100-basis-point change in the benchmark rate on SPS’ variable rate debt would have no impact on annual pretax interest expense in 2019 and $0.4 million in 2018, respectively.
See Note 8 to the financial statements for further information.
Credit Risk — SPS is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. SPS maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.
At Dec. 31, 2019, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $1.2 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $1.2 million. At Dec. 31, 2018, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $1.5 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $1.5 million.
 
SPS conducts credit reviews for all counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase SPS’ credit risk.
Fair Value Measurements
SPS uses derivative contracts such as futures, forwards, interest rate swaps, options and FTRs to manage commodity price and interest rate risk. Derivative contracts, with the exception of those designated as normal purchase-normal sale contracts, are reported at fair value. SPS’ investments held in rabbi trusts, pension and other postretirement funds are also subject to fair value accounting.
Commodity Derivatives — SPS continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions. Given the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, 2019.
Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are recorded as other comprehensive income or deferred as regulatory assets and liabilities. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. The impact of discounting commodity derivative liabilities for credit risk was immaterial at Dec. 31, 2019.
ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See 15-1 for an index of financial statements included herein.
See Note 13 to the financial statements for further information.


16


Management Report on Internal Controls Over Financial Reporting
The management of SPS is responsible for establishing and maintaining adequate internal control over financial reporting. SPS’ internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s and SPS’ management and board of directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
SPS management assessed the effectiveness of SPS’ internal control over financial reporting as of Dec. 31, 2019. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2019, SPS’ internal control over financial reporting is effective at the reasonable assurance level based on those criteria.
/s/ BEN FOWKE /s/ ROBERT C. FRENZEL
Ben Fowke Robert C. Frenzel
Chairman, Chief Executive Officer and Director Executive Vice President, Chief Financial Officer and Director
Feb. 21, 2020 Feb. 21, 2020


17


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, 2019 and 2018, the related statements of income, comprehensive income, cash flows and common stockholder's equity, for each of the three years in the period ended December 31, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, 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.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 21, 2020
 
We have served as the Company’s auditor since 2002.


18


SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF INCOME
(amounts in millions)
  Year Ended Dec. 31
  2019 2018 2017
       
Operating revenues $1,825.8
 $1,933.2
 $1,918.0
       
Operating expenses      
Electric fuel and purchased power 875.4
 1,043.5
 1,055.3
Operating and maintenance expenses 285.3
 282.7
 285.4
Demand side management program expenses 16.6
 17.7
 15.5
Depreciation and amortization 229.9
 209.6
 193.9
Taxes (other than income taxes) 71.9
 68.0
 67.0
Total operating expenses 1,479.1
 1,621.5
 1,617.1
       
Operating income 346.7
 311.7
 300.9
       
Other income (expense), net 2.2
 (3.0) (1.8)
Allowance for funds used during construction — equity 26.8
 19.1
 9.3
       
Interest charges and financing costs      
Interest charges — includes other financing costs of
$3.4, $2.9 and $2.5, respectively
 99.3
 84.5
 86.2
Allowance for funds used during construction — debt (12.3) (8.9) (5.4)
Total interest charges and financing costs 87.0
 75.6
 80.8
       
Income before income taxes 288.7
 252.2
 227.6
Income taxes 25.6
 38.9
 68.4
Net income $263.1
 $213.3
 $159.2
See Notes to Financial Statements


19


SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF COMPREHENSIVE INCOME
(amounts in millions)
 Year Ended Dec. 31
 2019 2018 2017
Net income$263.1
 $213.3
 $159.2
      
Other comprehensive income     
      
Defined pension and other postretirement benefits:     
Net pension and retiree medical loss arising during the period, net of tax of $(0.1), $0 and $0, respectively(0.2) 
 
Reclassification of loss to net income, net of tax of $00.2
 
 0.1
Derivative instruments:     
Reclassification of loss to net income, net of tax of $0
 0.1
 
      
Other comprehensive income
 0.1
 0.1
Comprehensive income$263.1
 $213.4
 $159.3
See Notes to Financial Statements


20


SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF CASH FLOWS
(amounts in millions)

Year Ended Dec. 31
 2019 2018 2017
Operating activities     
Net income$263.1
 $213.3
 $159.2
Adjustments to reconcile net income to cash provided by operating activities:     
Depreciation and amortization232.2
 210.0
 193.9
Demand side management program amortization
 1.7
 1.7
Deferred income taxes29.0
 22.1
 126.5
Allowance for equity funds used during construction(26.8) (19.1) (9.3)
Provision for bad debts5.7
 4.9
 5.1
Net derivative losses
 0.1
 0.1
Changes in operating assets and liabilities:     
Accounts receivable(9.0) (19.5) (10.4)
Accrued unbilled revenues(0.6) 15.3
 (10.4)
Inventories(20.5) (16.0) (1.9)
Prepayments and other2.8
 0.5
 4.3
Accounts payable(8.5) (6.6) 11.8
Net regulatory assets and liabilities13.8
 38.2
 38.1
Other current liabilities5.8
 11.6
 3.4
Pension and other employee benefit obligations(17.7) (16.0) (21.7)
Other, net3.5
 5.8
 (19.9)
Net cash provided by operating activities472.8
 446.3
 470.5
      
Investing activities     
Utility capital/construction expenditures(844.4) (1,020.9) (550.6)
Investments in utility money pool arrangement(133.0) (285.0) (142.0)
Receipts from utility money pool arrangement133.0
 350.0
 77.0
Other
 
 (0.5)
Net cash used in investing activities(844.4) (955.9) (616.1)
      
Financing activities     
(Repayments of) proceeds from short-term borrowings, net(42.0) 42.0
 (50.0)
Proceeds from issuance of long-term debt292.2
 295.0
 442.3
Repayment of long-term debt, including reacquisition premiums
 
 (271.6)
Borrowings under utility money pool arrangement296.0
 595.0
 335.0
Repayments under utility money pool arrangement(296.0) (595.0) (335.0)
Capital contributions from parent426.3
 336.8
 143.7
Dividends paid to parent(332.7) (131.0) (108.8)
Net cash provided by financing activities343.8
 542.8
 155.6
      
Net change in cash, cash equivalents and restricted cash(27.8) 33.2
 10.0
Cash, cash equivalents and restricted cash at beginning of year44.0
 10.8
 0.8
Cash, cash equivalents and restricted cash at end of year$16.2
 $44.0
 $10.8
  
  
  
Supplemental disclosure of cash flow information:     
Cash paid for interest (net of amounts capitalized)$(83.6) $(71.2) $(76.0)
Cash received (paid) for income taxes, net11.9
 (10.6) 41.5
Supplemental disclosure of non-cash investing transactions:     
Property, plant and equipment additions in accounts payable$94.5
 $71.5
 $85.1
Inventory transfer additions in property, plant and equipment23.3
 22.5
 13.7
Operating lease right-of-use assets548.3
 
 
Allowance for equity funds used during construction26.8
 19.1
 9.3
See Notes to Financial Statements

21


SOUTHWESTERN PUBLIC SERVICE CO.
BALANCE SHEETS
(amounts in millions, except share and per share data)
  Dec. 31
  2019 2018
Assets    
Current assets    
Cash and cash equivalents $16.2
 $44.0
   Accounts receivable, net 92.7
 90.7
Accounts receivable from affiliates 4.2
 10.5
Investments in money pool arrangements 
 
Accrued unbilled revenues 115.1
 114.5
Inventories 31.0
 33.9
Regulatory assets 20.0
 26.0
Derivative instruments 15.0
 17.8
Prepaid taxes 0.8
 14.2
Prepayments and other 21.4
 10.7
Total current assets 316.4
 362.3
     
Property, plant and equipment, net 6,631.6
 5,946.4
     
Other assets    
Regulatory assets 364.0
 366.2
Derivative instruments 12.6
 15.8
Operating lease right-of-use assets 522.4
 
Other 3.9
 5.1
Total other assets 902.9
 387.1
Total assets $7,850.9
 $6,695.8
     
Liabilities and Equity    
Current liabilities    
Short-term debt $
 $42.0
Accounts payable 168.1
 191.8
Accounts payable to affiliates 20.4
 19.9
Regulatory liabilities 118.1
 85.8
Taxes accrued 40.4
 41.6
Accrued interest 26.2
 25.8
Dividends payable 46.3
 45.2
Derivative instruments 3.7
 3.6
Operating lease liabilities 26.9
 
Other 30.7
 28.3
Total current liabilities 480.8
 484.0
     
Deferred credits and other liabilities    
Deferred income taxes 671.8
 619.1
Regulatory liabilities 732.3
 780.9
Asset retirement obligations 77.3
 32.4
Derivative instruments 12.8
 16.4
Pension and employee benefit obligations 67.0
 92.4
Operating lease liabilities 495.3
 
Other 9.4
 7.9
Total deferred credits and other liabilities 2,065.9
 1,549.1
     
Commitments and contingencies 


 


Capitalization    
Long-term debt 2,419.7
 2,126.1
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2019 and 2018, respectively 
 
Additional paid in capital 2,350.9
 1,932.3
Retained earnings 535.0
 605.7
Accumulated other comprehensive loss (1.4) (1.4)
Total common stockholder’s equity 2,884.5
 2,536.6
Total liabilities and equity $7,850.9
 $6,695.8
See Notes to Financial Statements

22


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, 2016100
 $
 $1,446.2
 $486.7
 $(1.3) $1,931.6
            
Net income      159.2
   159.2
Other comprehensive loss        0.1
 0.1
Common dividends declared to parent      (104.6)   (104.6)
Contribution of capital by parent    144.0
     144.0
Adoption of ASU No. 2018-02      0.3
 (0.3) 
Balance at Dec. 31, 2017100
 $
 $1,590.2
 $541.6
 $(1.5) $2,130.3
            
Net income      213.3
   213.3
Other comprehensive loss        0.1
 0.1
Common dividends declared to parent      (149.2)   (149.2)
Contribution of capital by parent    342.1
     342.1
Balance at Dec. 31, 2018100
 $
 $1,932.3
 $605.7
 $(1.4) $2,536.6
            
Net income      263.1
   263.1
Other comprehensive income        
 
Common dividends declared to parent      (333.8)   (333.8)
Contribution of capital by parent    418.6
     418.6
Balance at Dec. 31, 2019100
 $
 $2,350.9
 $535.0
 $(1.4) $2,884.5
See Notes to Financial Statements


23


Notes to Financial Statements
1. Summary of Significant Accounting Policies
General — SPS is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity.
SPS’ financial statements are presented in accordance with GAAP. All of SPS’ underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions. Certain amounts in the 2018 and 2017 financial statements or notes have been reclassified to conform to the 2019 presentation for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.
SPS has evaluated events occurring after Dec. 31, 2019 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; and
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 its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, which will be refundable to utility customers over the remaining life of the related assets. A tax rate increase would result in the establishment of a similar regulatory asset.
Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of regulatory assets and liabilities related to income taxes. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized.
SPS follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. SPS recognizes a tax position in its financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax expense.
SPS reports interest and penalties related to income taxes within the other income and interest charges in the statements of income.
Xcel Energy Inc. and its subsidiaries, including SPS, files 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.

24


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. Depreciation expense, expressed as a percentage of average depreciable property, was 2.9% in 2019, 2.9% in 2018 and 2.8% in 2017.
See Note 3 for further information.
AROs — SPS accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. SPS also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.
See Note 10 for further information.
Benefit Plans and Other Postretirement Benefits — SPS maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates.
Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.
See Note 9 for further information.
Environmental Costs — Environmental costs are recorded when it is probable SPS is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant.
Estimated remediation costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for SPS’ expected share of the cost.
Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.
See Note 10 for further information.
Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. SPS recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs on a systematic basis 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 sales to both native load and other end use customers on a gross basis in electric revenues and cost of sales. Revenues and charges for short-term wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other revenues and charges related to participating and transacting in RTOs 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, 2019 and 2018, the allowance for bad debts was $5.3 million and $5.6 million, respectively.
Inventory — Inventory is recorded at average cost and consisted of the following:
(Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018
Inventories    
Materials and supplies $24.7
 $25.7
Fuel 6.3
 8.2
Total inventories $31.0
 $33.9

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.

25


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 Issued
Credit Losses In 2016, the FASB issued Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326), which changes how entities account for losses on receivables and certain other assets. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards. ASC Topic 326 is effective for interim and annual periods beginning on or after Dec. 15, 2019, and will be applied using a modified-retrospective approach, with a cumulative-effect adjustment to retained earnings as of Jan. 1, 2020. SPS expects the impact of adoption of the new standard to include first-time recognition of expected credit losses (i.e., bad debt expense) on unbilled revenues, with the initial allowance established at Jan. 1, 2020 charged to retained earnings. Recognition of this allowance and other impacts of adoption are expected to be immaterial to the financial statements.
Recently Adopted
Leases In 2016, the FASB issued Leases, Topic 842 (ASC Topic 842), which provides new accounting and disclosure guidance for leasing activities, most significantly requiring that operating leases be recognized on the balance sheet. SPS adopted the guidance on Jan. 1, 2019 utilizing the package of transition practical expedients provided by the new standard, including carrying forward prior conclusions on whether agreements existing before the adoption date contain leases and whether existing leases are operating or finance leases; ASC Topic 842 refers to capital leases as finance leases.
Specifically for land easement contracts, SPS has elected the practical expedient provided by ASU No. 2018-01 Leases: Land Easement Practical Expedient for Transition to Topic 842, and as a result, only those easement contracts entered on or after Jan. 1, 2019 will be evaluated to determine if lease treatment is appropriate.
SPS also utilized the transition practical expedient offered by ASU No. 2018-11 Leases: Targeted Improvements to implement the standard on a prospective basis. As a result, reporting periods in the financial statements beginning Jan. 1, 2019 reflect the implementation of ASC Topic 842, while prior periods continue to be reported in accordance with Leases, Topic 840 (ASC Topic 840). Other than first-time recognition of operating leases on its balance sheet, the implementation of ASC Topic 842 did not have a significant impact on SPS’ financial statements. Adoption resulted in recognition of approximately $0.5 billion of operating lease ROU assets and current/noncurrent operating lease liabilities.
See Note 10 for leasing disclosures.

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3. Property, Plant and Equipment

Major classes of property, plant and equipment
(Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018
Property, plant and equipment    
Electric plant $8,453.0
 $7,227.7
CWIP 485.4
 847.3
Total property, plant and equipment 8,938.4
 8,075.0
Less accumulated depreciation (2,306.8) (2,128.6)
Property, plant and equipment, net $6,631.6
 $5,946.4

4. Regulatory Assets and Liabilities
Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric rates. SPS would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP.
Components of regulatory assets:
(Millions of Dollars) See
Note(s)
 Remaining
Amortization Period
 Dec. 31, 2019 Dec. 31, 2018
Regulatory Assets     Current Noncurrent Current Noncurrent
Pension and retiree medical obligations9 Various $11.1
 $203.5
 $12.6
 $222.1
Excess deferred taxes — TCJA 7 Various 1.7
 52.0
 
 55.9
Recoverable deferred taxes on AFUDC recorded in plant 
   Plant lives 
 34.1
 
 27.9
Net AROs (a)
 1, 10 Plant lives 
 26.9
 
 25.7
Losses on reacquired debt   Term of related debt 0.8
 21.0
 0.8
 21.9
Conservation programs (b)
 1 One to two years 0.6
 1.1
 0.7
 0.6
Other   Various 5.8
 25.4
 11.9
 12.1
Total regulatory assets     $20.0
 $364.0
 $26.0
 $366.2

(a) 
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, 2019 Dec. 31, 2018
Regulatory Liabilities     Current Noncurrent Current Noncurrent
Deferred income tax adjustments and TCJA refunds (a)
 7
 Various $6.9
 $534.9
 $2.2
 $569.8
Plant removal costs 1, 10
 Plant lives 
 174.5
 
 187.7
Revenue subject to refund   One to two years 14.6
 1.1
 11.3
 8.1
Gain from asset sales   Various 
 2.4
 
 2.4
Deferred electric energy costs   Less than one year 81.6
 
 56.5
 
Contract valuation adjustments (b)
 1, 8
 Less than one year 11.7
 
 14.7
 
Other   Various 3.3
 19.4
 1.1
 12.9
Total regulatory liabilities (c)
     $118.1
 $732.3
 $85.8
 $780.9
(a) 
Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.
(b) 
Includes the fair value of certain long-term PPAs used to meet energy capacity requirements.
(c) 
Revenue subject to refund of $3.9 million for 2019 and none for 2018 is included in other current liabilities.
At Dec. 31, 2019 and 2018, SPS’ regulatory assets not earning a return primarily included the unfunded portion of pension and retiree medical obligations and net AROs. In addition, SPS’ regulatory assets included $56.5 million and $50.5 million at Dec. 31, 2019 and 2018, respectively, of past expenditures not earning a return. Amounts primarily 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.

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Money pool borrowings for SPS were as follows:
(Millions of Dollars, Except Interest Rates) Three Months Ended Dec. 31, 2019 Year Ended Dec. 31
  2019 2018 2017
Borrowing limit $100
 $100
 $100
 $100
Amount outstanding at period end 
 
 
 
Average amount outstanding 1
 8
 29
 13
Maximum amount outstanding 12
 100
 100
 100
Weighted average interest rate, computed on a daily basis 1.63% 2.42% 1.96% 1.12%
Weighted average interest rate at end of period N/A
 N/A
 N/A
 N/A

Commercial Paper — Commercial paper outstanding for SPS was as follows:
(Millions of Dollars, Except Interest Rates) Three Months Ended Dec. 31, 2019 Year Ended Dec. 31
  2019 2018 2017
Borrowing limit $500
 $500
 $400
 $400
Amount outstanding at period end 
 
 42
 
Average amount outstanding 
 72
 30
 69
Maximum amount outstanding 
 316
 144
 176
Weighted average interest rate, computed on a daily basis N/A
 2.68% 2.27% 1.13%
Weighted average interest rate at end of period N/A
 N/A
 2.80
 NA

Letters of Credit — SPS may use letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2019 and 2018, there were $2 million of letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.
Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, SPS must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
Amended Credit Agreement In June 2019, SPS entered into an amended five-year credit agreement with a syndicate of banks. The amended credit agreements have substantially the same terms and conditions as the prior credit agreements with the exception of the following:
Maturity extended from June 2021 to June 2024; and
Borrowing limit increased from $400 million to $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)
2019 2018    
46% 46% $50 2
(a) 
The SPS credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.
 
(b) 
All extension requests are subject to majority bank group approval.
The credit facility has a cross-default provision that SPS will be in default on its borrowings under the facility if SPS or any of its future significant subsidiaries whose total assets exceed 15% of SPS’ total assets default on indebtedness in an aggregate principal amount exceeding $75 million.
If SPS does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2019, SPS was in compliance with all financial covenants.
SPS had the following committed credit facilities available as of Dec. 31, 2019.
Credit Facility (a)
 
Drawn (b)
 Available
$500 $2 $498
(a)
This credit facility matures in June 2024.
(b)
Includes letters of credit and outstanding commercial paper.
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. SPS had 0 direct advances on the facility outstanding at Dec. 31, 2019 and 2018.
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 2019 2018
First mortgage bonds 3.30% June 15, 2024 $150
 $150
First mortgage bonds 3.30
 June 15, 2024 200
 200
Unsecured senior notes 6.00
 Oct. 1, 2033 100
 100
Unsecured senior notes 6.00
 Oct. 1, 2036 250
 250
First mortgage bonds 4.50
 Aug. 15, 2041 200
 200
First mortgage bonds 4.50
 Aug. 15, 2041 100
 100
First mortgage bonds 4.50
 Aug. 15, 2041 100
 100
First mortgage bonds 3.40
 Aug. 15, 2046 300
 300
First mortgage bonds 3.70
 Aug. 15, 2047 450
 450
First mortgage bonds (b)
 4.40
 Nov. 15, 2048 300
 300
First mortgage bonds (a)
 3.75
 June 15, 2049 300
 
Unamortized discount     (7) (4)
Unamortized debt issuance cost     (23) (20)
Total long-term debt     $2,420
 $2,126

(a) 
2019 financing
(b) 
2018 financing
Maturities of long-term debt:
(Millions of Dollars)  
2020 $
2021 
2022 
2023 
2024 350


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Deferred Financing Costs — Deferred financing costs of approximately $23 million and $20 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2019 and 2018, 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) 
2019 and 2018
10,000,000
 1.00
 

Dividend Restrictions SPS dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings. SPS is required to be current on particular interest payments before dividends can be paid.
SPS’ state regulatory commissions additionally impose dividend limitations, which are more restrictive than those imposed by the FERC.
Requirements and actuals as of Dec. 31, 2019:
Equity to Total Capitalization Ratio - Required Range 
Equity to Total Capitalization Ratio - Actual (a)
Low High 2019
45.0% 55.0% 54.4%
(a) 
Excludes short-term debt.
Unrestricted Retained Earnings Total Capitalization 
Limit on Total Capitalization (a)
$535.0 million $5.3 billion N/A
(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:
(Millions of Dollars) Year Ended Dec. 31, 2019
Major product lines  
Revenue from contracts with customers:  
Residential $351.9
C&I 800.3
Other 41.1
Total retail 1,193.3
Wholesale 361.0
Transmission 239.6
Other 3.3
Total revenue from contracts with customers 1,797.2
Alternative revenue and other 28.6
Total revenues $1,825.8
 
(Millions of Dollars) Year Ended Dec. 31, 2018
Major product lines  
Revenue from contracts with customers:  
Residential $363.7
C&I 828.3
Other 44.7
Total retail 1,236.7
Wholesale 426.0
Transmission 231.1
Other 12.8
Total revenue from contracts with customers 1,906.6
Alternative revenue and other 26.6
Total revenues $1,933.2

7. Income Taxes
Federal Tax Reform In 2017, the TCJA was signed into law. The key provisions impacting Xcel Energy (which includes SPS), generally beginning in 2018, included:
Corporate federal tax rate reduction from 35% to 21%;
Normalization of resulting plant-related excess deferred taxes;
Elimination of the corporate alternative minimum tax;
Continued interest expense deductibility and discontinued bonus depreciation for regulated public utilities;
Limitations on certain executive compensation deductions;
Limitations on certain deductions for NOLs arising after Dec. 31, 2017 (limited to 80% of taxable income);
Repeal of the section 199 manufacturing deduction; and
Reduced deductions for meals and entertainment as well as state and local lobbying.
Xcel Energy estimated the effects of the TCJA, which have been reflected in the consolidated financial statements.
Reductions in deferred tax assets and liabilities due to a decrease in corporate federal tax rates typically result in a net tax benefit. However, the impacts are primarily recognized as regulatory liabilities refundable to utility customers as a result of IRS requirements and past regulatory treatment.
Estimated impacts of the new tax law for SPS in December 2017 included:
$426 million ($559 million grossed-up for tax) of reclassifications of plant-related excess deferred taxes to regulatory liabilities upon valuation at the new 21% federal rate. The regulatory liabilities will be amortized consistent with IRS normalization requirements, resulting in customer refunds over the average remaining life of the related property;
$45 million and $28 million of reclassifications (grossed-up for tax) of excess deferred taxes for non-plant related deferred tax assets and liabilities, respectively, to regulatory assets and liabilities; and
$8 million of total estimated income tax benefit related to the federal tax reform implementation and a $2 million reduction to net income related to the allocation of Xcel Energy Services Inc.’s tax rate change on its deferred taxes.

29


Xcel Energy accounted for the state tax impacts of federal tax reform based on enacted state tax laws. Any future state tax law changes related to the TCJA will be accounted for in the periods state laws are enacted.
Federal Audit — SPS is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows:
Tax Year(s) Expiration
2009 - 2013 June 2020
2014 - 2016 September 2020

In 2015, the IRS commenced an examination of tax years 2012 and 2013. In 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy filed a protest with the IRS. As of Dec. 31, 2019, the case has been forwarded to the Office of Appeals and 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 2018, the IRS began an audit of tax years 2014 - 2016. As of Dec. 31, 2019 0 adjustments have been proposed.
State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2019, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. 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, 2019 Dec. 31, 2018
Unrecognized tax benefit — Permanent tax positions $3.7
 $3.0
Unrecognized tax benefit — Temporary tax positions 1.5
 1.5
Total unrecognized tax benefit $5.2
 $4.5
Changes in unrecognized tax benefits:
(Millions of Dollars) 2019 2018 2017
Balance at Jan. 1 $4.5
 $4.3
 $28.7
Additions based on tax positions related to the current year 0.7
 0.6
 0.9
Reductions based on tax positions related to the current year (0.1) (0.1) (0.6)
Additions for tax positions of prior years 0.2
 0.1
 1.3
Reductions for tax positions of prior years (0.1) (0.3) (19.9)
Settlements with taxing authorities 
 (0.1) (6.1)
Balance at Dec. 31 $5.2
 $4.5
 $4.3

Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:
(Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018
NOL and tax credit carryforwards $(4.4) $(3.8)

Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $1.4 million and $0.8 million at Dec. 31, 2019 and Dec. 31, 2018, respectively.
 
As the IRS Appeals and federal audit progresses and state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $3.7 million in the next 12 months.
Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.
Interest payable related to unrecognized tax benefits:
(Millions of Dollars) 2019 2018 2017
Receivable (payable) for interest related to unrecognized tax benefits at Jan. 1 $0.7
 $0.5
 $(0.9)
Interest income related to unrecognized tax benefits 
 0.2
 1.4
Receivable for interest related to unrecognized tax benefits at Dec. 31 $0.7
 $0.7
 $0.5

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2019, 2018, or 2017.
Other Income Tax Matters — NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:
(Millions of Dollars) 2019 2018
Federal tax credit carryforwards $29.5
 $5.7
State NOL carryforwards 1.2
 2.9

Federal carryforward periods expire between 2024 and 2039 and state carryforward periods expire between 2025 and 2036.
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:
 2019 
2018 (a)
 
2017 (a)
Federal statutory rate21.0 % 21.0 % 35.0 %
State income tax on pretax income, net of federal tax effect2.2 % 2.3 % 2.0 %
Increases (decreases) in tax from:

 

 

Wind PTCs(7.9) 
 
Plant regulatory differences (b)
(5.0) (4.8) (0.9)
Amortization of excess nonplant deferred taxes(0.9) (1.2) 
Other tax credits, net of NOL & tax credit allowances(0.6) (0.7) (0.6)
Adjustments attributable to tax returns(0.1) (1.5) (0.4)
Change in unrecognized tax benefits0.2
 0.1
 (1.0)
Tax reform
 
 (3.5)
Other, net
 0.2
 (0.5)
Effective income tax rate8.9 % 15.4 % 30.1 %
(a) 
Prior periods have been reclassified to conform to current year presentation.
(b) 
Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions.

30


Components of income tax expense for years ended Dec. 31:
(Millions of Dollars) 2019 2018 2017
Current federal tax (benefit) expense
 $(3.9) $12.3
 $(20.9)
Current state tax expense (benefit) 0.6
 2.3
 (12.8)
Current change in unrecognized tax expense (benefit) 
 2.3
 (24.3)
Deferred federal tax expense 22.3
 20.5
 89.9
Deferred state tax expense 6.0
 3.6
 14.5
Deferred change in unrecognized tax expense (benefit) 0.7
 (2.0) 22.1
Deferred ITCs (0.1) (0.1) (0.1)
Total income tax expense $25.6
 $38.9
 $68.4
Components of deferred income tax expense as of Dec. 31:
(Millions of Dollars) 2019 2018 2017
Deferred tax expense (benefit) excluding items below $52.7
 $44.2
 $(414.2)
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (23.8) (22.0) 540.7
Tax benefit (expense) allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other 0.1
 (0.1) 
Deferred tax expense $29.0
 $22.1
 $126.5

Components of the net deferred tax liability as of Dec. 31:
(Millions of Dollars) 2019 
2018 (a)
Deferred tax liabilities:    
Differences between book and tax bases of property $758.7
 $680.6
Operating lease assets 115.8
 
Regulatory assets 49.7
 49.2
Pension expense 33.1
 32.3
Total deferred tax liabilities $957.3
 $762.1
     
Deferred tax assets: 

 

Regulatory liabilities $111.2
 $116.8
Operating lease liabilities 115.8
 
Tax credit carryforward 29.5
 5.7
Deferred fuel costs 18.3
 12.7
Other employee benefits 5.8
 5.6
NOL carryforward 0.1
 0.2
Other 4.8
 2.0
Total deferred tax assets 285.5
 143.0
Net deferred tax liability $671.8
 $619.1
(a) Prior periods have been reclassified to conform to current year presentation.
8. Fair Value of Financial Assets and Liabilities
Fair Value Measurements
The 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; and
Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.
Specific valuation methods include:
Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAVs.
Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.
Electric commodity derivatives held by SPS include transmission congestion instruments, generally referred to as FTRs, purchased from SPP. FTRs purchased from an RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR.
If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of important inputs to the value of FTRs between auction processes, including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3. Non-trading monthly FTR settlements are expected to be recovered through fuel and purchased energy cost recovery mechanisms, and therefore changes in the fair value of the yet to be settled portions of FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of SPS, the numerous unobservable quantitative inputs pertinent to the value of FTRs are immaterial to the financial statements of SPS.
Derivative 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.

31


Interest Rate Derivatives — SPS may enter into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes. As of Dec. 31, 2019, accumulated other comprehensive losses related to interest rate derivatives included $0.1 million 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.
Gross notional amounts of commodity FTRs at Dec. 31, 2019 and 2018:
(Amounts in Millions) (a)
 Dec. 31, 2019 Dec. 31, 2018
MWh of electricity 6.4
 5.5
(a) 
Amounts are not reflective of net positions in the underlying commodities.
Consideration of Credit Risk and Concentrations — SPS continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the balance sheets.
SPS’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. At Dec. 31, 2019, 3 of the 10 most significant counterparties for these activities, comprising $12.2 million or 35% of this credit exposure, had investment grade ratings from Standard & Poor’s, Moody’s or Fitch Ratings. NaN of the 10 most significant counterparties, comprising $22.1 million or 65% of this credit exposure, were not rated by external rating agencies, but based on SPS’ internal analysis, had credit quality consistent with investment grade.  NaN of these significant counterparties, comprising $0.1 million or less than 1% of this credit exposure, had credit quality less than investment grade, based on internal analysis. NaN of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.









 
Qualifying Cash Flow Hedges — Financial impact of qualifying interest rate cash flow hedges on SPS’ accumulated other comprehensive loss, included in the statements of common stockholder’s equity and in the statements of comprehensive income:
(Millions of Dollars) 2019 2018 2017
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $(0.7) $(0.8) $(0.7)
After-tax net realized losses on derivative transactions reclassified into earnings 
 0.1
 
Adoption of ASU. 2018-02 (a)
 
 
 (0.1)
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $(0.7) $(0.7) $(0.8)
(a) 
In 2017, SPS implemented ASU No. 2018-02 related to TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings.
Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were immaterial, $0.1 million and $0.1 million for the years ended Dec. 31, 2019, 2018 and 2017, respectively.
Changes in the fair value of FTRs resulting in pre-tax net gains of $6.5 million, $7.0 million and $0.5 million recognized for the years ended Dec. 31, 2019, 2018 and 2017, respectively, were reclassified as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on expected recovery of FTR settlements through fuel and purchased energy cost recovery mechanisms.
FTR settlement gains of $6.0 million, $4.4 million and $0.8 million were recognized for the years ended Dec. 31, 2019, 2018 and 2017, respectively, and were recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.
SPS had 0 derivative instruments designated as fair value hedges during the years ended Dec. 31, 2019, 2018 and 2017.


















32



Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2019 and 2018:
  Dec. 31, 2019 Dec. 31, 2018
  Fair Value       Fair Value      
(Millions of Dollars) Level 1 Level 2 Level 3 
Fair Value
Total
 

Netting (a)
 Total Level 1 Level 2 Level 3 
Fair Value
Total
 

Netting (a)
 Total
Current derivative assets                        
Other derivative instruments:                        
Electric commodity $
 $
 $11.8
 $11.8
 $
 $11.8
 $
 $
 $14.9
 $14.9
 $(0.2) $14.7
Total current derivative assets $
 $
 $11.8
 $11.8
 $
 11.8
 $
 $
 $14.9
 $14.9
 $(0.2) 14.7
PPAs (b)
           3.2
           3.1
Current derivative instruments           $15.0
           $17.8
Noncurrent derivative assets                        
PPAs (b)
           12.6
           15.8
Noncurrent derivative instruments           $12.6
           $15.8
Current derivative liabilities                        
Other derivative instruments:                        
Electric commodity $
 $
 $0.1
 $0.1
 $
 $0.1
 $
 $
 $0.2
 $0.2
 $(0.2) $
Total current derivative liabilities $
 $
 $0.1
 $0.1
 $
 0.1
 $
 $
 $0.2
 $0.2
 $(0.2) 
PPAs (b)
           3.6
           3.6
Current derivative instruments           $3.7
           $3.6
Noncurrent derivative liabilities                        
PPAs (b)
           12.8
           16.4
Noncurrent derivative instruments           $12.8
           $16.4
(a) 
SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2019 and 2018. At both Dec. 31, 2019 and 2018, derivative assets and liabilities include 0 obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
(b) 
During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
Changes in Level 3 commodity derivatives for the years ended Dec. 31, 2019, 2018 and 2017:
  Year Ended Dec. 31
(Millions of Dollars) 2019 2018 2017
Balance at Jan. 1 $14.7
 $12.7
 $2.0
Purchases 26.7
 32.3
 41.2
Settlements (34.2) (41.6) (55.8)
Net transactions recorded during the period: 

    
Net gains recognized as regulatory assets 4.5
 11.3
 25.3
Balance at Dec. 31 $11.7
 $14.7
 $12.7

SPS recognizes transfers between levels as of the beginning of each period. There were 0 transfers of amounts between levels for derivative instruments for 2017 – 2019.
Fair Value of Long-Term Debt
As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:
  2019 2018
(Millions of Dollars) 
Carrying
Amount
 Fair Value 
Carrying
Amount
 Fair Value
Long-term debt, including current portion $2,419.7
 $2,706.1
 $2,126.1
 $2,139.8
 
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, 2019 and 2018, 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, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a combination of years of service and average pay. Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs subject to the limitations of applicable employee benefit and tax laws.
In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The SERP is maintained for certain executives that were participants 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, 2019 and 2018 were $39 million and $33 million, respectively, of which $2 million was attributable to SPS in both years. In 2019 and 2018, Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $4 million in 2019 and 2018, of which immaterial amounts were attributable to SPS.

33


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 2019 were above the assumed level of 6.78%;
Investment returns in 2018 were below the assumed level of 6.78%;
Investment returns in 2017 were above the assumed level of 6.78%; and
In 2020, Xcel Energy’s expected investment-return assumption is 6.78%.
 
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, 2019 (a)
 
Dec. 31, 2018 (a)
(Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total
Cash equivalents $18.9
 $
 $
 $
 $18.9
 $21.6
 $
 $
 $
 $21.6
Commingled funds 202.5
 
 
 144.8
 347.3
 128.6
 
 
 132.5
 261.1
Debt securities 
 98.2
 0.6
 
 98.8
 
 98.1
 
 
 98.1
Equity securities 12.1
 
 
 
 12.1
 14.4
 
 
 
 14.4
Other (16.8) 0.7
 
 (2.8) (18.9) 0.2
 0.8
 
 (4.0) (3.0)
Total $216.7
 $98.9
 $0.6
 $142.0
 $458.2
 $164.8
 $98.9
 $
 $128.5
 $392.2

(a) 
See Note 8 for further information on fair value measurement inputs and methods.
For each of the fair value hierarchy levels, SPS’ proportionate allocation of the total postretirement benefit plan assets that were measured at fair value:
  
Dec. 31, 2019 (a)
 
Dec. 31, 2018 (a)
(Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total
Cash equivalents $2.2
 $
 $
 $
 $2.2
 $1.8
 $
 $
 $
 $1.8
Insurance contracts 
 4.9
 
 
 4.9
 
 4.3
 
 
 4.3
Commingled funds: 6.7
 
 
 7.4
 14.1
 12.8
 
 
 3.8
 16.6
Debt securities: 
 22.1
 0.1
 
 22.2
 
 17.2
 
 
 17.2
Equity securities: 
 
 
 
 
 
 
 
 
 
Other 
 0.2
 
 
 0.2
 
 0.1
 
 
 0.1
Total $8.9
 $27.2
 $0.1
 $7.4
 $43.6
 $14.6
 $21.6
 $
 $3.8
 $40.0
(a) 
See Note 8 for further information on fair value measurement inputs and methods.
Immaterial assets were transferred in or out of Level 3 for 2019. No assets were transferred in or out of Level 3 for 2018.

34


Funded Status — Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for Xcel Energy are presented in the following table:
  Pension Benefits Postretirement Benefits
(Millions of Dollars) 2019 2018 2019 2018
Change in Benefit Obligation:        
Obligation at Jan. 1 $477.8
 $515.9
 $41.8
 $47.0
Service cost 8.8
 9.7
 0.9
 1.1
Interest cost 20.1
 18.4
 1.7
 1.6
Plan amendments 
 
 
 
Actuarial loss (gain) 44.2
 (34.8) 0.4
 (5.1)
Plan participants’ contributions 
 
 0.6
 0.6
Benefit payments (a)
 (32.1) (31.4) (2.2) (3.4)
Obligation at Dec. 31 $518.8
 $477.8
 $43.2
 $41.8
Change in Fair Value of Plan Assets:        
Fair value of plan assets at Jan. 1 $392.2
 $433.2
 $40.0
 $44.1
Actual return on plan assets 80.2
 (17.6) 5.1
 (1.3)
Employer contributions 17.9
 8.0
 0.1
 
Plan participants’ contributions 
 
 0.6
 0.6
Benefit payments (32.1) (31.4) (2.2) (3.4)
Fair value of plan assets at Dec. 31 $458.2
 $392.2
 $43.6
 $40.0
Funded status of plans at Dec. 31 $(60.6) $(85.6) $0.4
 $(1.8)
Amounts recognized in the Balance Sheet at Dec. 31:        
Noncurrent assets 
 
 0.4
 
Noncurrent liabilities (60.6) (85.6) 
 (1.8)
Net amounts recognized $(60.6) $(85.6) $0.4
 $(1.8)
Significant Assumptions Used to Measure Benefit Obligations:        
Discount rate for year-end valuation 3.49% 4.31% 3.47% 4.32%
Expected average long-term increase in compensation level 3.75
 3.75
 N/A
 N/A
Mortality table Pri-2012
 RP-2014
 Pri-2012
 RP-2014
Health care costs trend rate initial: Pre-65
 N/A
 N/A
 6.00% 6.50%
Health care costs trend rate initial: Post-65
 N/A
 N/A
 5.10% 5.30%
Ultimate trend assumption initial: Pre-65
 N/A
 N/A
 4.50% 4.50%
Ultimate trend assumption initial: Post-65
 N/A
 N/A
 4.50% 4.50%
Years until ultimate trend is reached N/A
 N/A
 3
 4
(a) 
Includes approximately $6.8 million in 2019 and $6.9 million in 2018, of lump-sum benefit payments used in the determination of a settlement charge.
Accumulated benefit obligation for the pension plan was $481.1 million and $445.8 million as of Dec. 31, 2019 and 2018, respectively.


35


Net Periodic Benefit Cost (Credit) Net periodic benefit cost (credit) other than service cost component is included in other income in the statement of income.
Components of net periodic benefit cost (credit) and the amounts recognized in other comprehensive income and regulatory assets and liabilities are as follows:
  Pension Benefits Postretirement Benefits
(Millions of Dollars) 2019 2018 2017 2019 2018 2017
Service cost $8.8
 $9.7
 $9.8
 $0.9
 $1.1
 $0.9
Interest cost 20.1
 18.4
 19.7
 1.7
 1.6
 1.7
Expected return on plan assets (28.6) (28.3) (27.9) (2.0) (2.5) (2.4)
Amortization of prior service credit (0.1) (0.1) 
 (0.5) (0.4) (0.4)
Amortization of net loss 11.3
 14.1
 13.0
 (0.4) (0.4) (0.6)
Settlement charge (a)
 2.4
 3.2
 
 
 
 
Net periodic pension cost (credit) 13.9
 17.0
 14.6
 (0.3) (0.6) (0.8)
Costs not recognized due to effects of regulation 0.9
 (2.2) 0.3
 
 
 
Net benefit cost (credit) recognized for financial reporting $14.8
 $14.8
 $14.9
 $(0.3) $(0.6) $(0.8)
Significant Assumptions Used to Measure Costs:            
Discount rate 4.31% 3.63% 4.13% 4.32% 3.62% 4.13%
Expected average long-term increase in compensation level 3.75
 3.75
 3.75
 
 
 
Expected average long-term rate of return on assets 6.78
 6.78
 6.78
 5.30
 5.80
 5.80
(a) 
A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2019 and 2018, as a result of lump-sum distributions during the 2019 and 2018 plan years, SPS recorded a total pension settlement charge of $2.4 million and $3.2 million in 2019 and 2018, respectively. A total of $0.6 million and $0.7 million of that amount was recorded in the income statement in 2019 and 2018, respectively.
  Pension Benefits Postretirement Benefits
(Millions of Dollars) 2019 2018 2019 2018
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:        
Net loss $209.7
 $230.9
 $(11.9) $(9.6)
Prior service credit (1.1) (1.2) (1.4) (1.8)
Total $208.6
 $229.7
 $(13.3) $(11.4)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:        
Current regulatory assets $11.0
 $12.9
 $
 $
Noncurrent regulatory assets 197.6
 216.8
 
 
Current regulatory liabilities 
 
 (0.8) (0.9)
Noncurrent regulatory liabilities 
 
 (12.5) (10.5)
Total $208.6
 $229.7
 $(13.3) $(11.4)
Measurement date Dec. 31, 2019 Dec. 31, 2018 Dec. 31, 2019 Dec. 31, 2018


Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. Required contributions were made in 2017 - 2020 to meet minimum funding requirements.
Total voluntary and required pension funding contributions across all 4 of Xcel Energy’s pension plans were as follows:
$150 million in January 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; and
$162 million in 2017, of which $24 million was attributable to SPS.
For future years, Xcel Energy and SPS anticipate contributions will be made as necessary.
 
The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Xcel Energy’s voluntary postretirement funding contributions were as follows:
Expects to contribute approximately $10 million during 2020;
$15 million during 2019;
$11 million during 2018;
$20 million during 2017; and
Amounts attributable to SPS were immaterial.

36


Target asset allocations:
  Pension Benefits Postretirement Benefits
  2019 2018 2019 2018
Domestic and international equity securities 37% 35% 15% 18%
Long-duration fixed income securities 30
 32
 
 
Short-to-intermediate fixed income securities 14
 16
 72
 70
Alternative investments 17
 15
 9
 8
Cash 2
 2
 4
 4
Total 100% 100% 100% 100%

Plan Amendments Xcel Energy, which includes SPS, amended the Xcel Energy Inc. Nonbargaining Pension Plan (South) in 2017 to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans.
In 2019 and 2018, there were no plan amendments made which affected the benefit obligation.
Projected Benefit Payments
SPS’ projected benefit payments:
(Millions of Dollars) Projected
Pension Benefit
Payments
 Gross Projected
Postretirement
Health Care
Benefit Payments
 Expected
Medicare Part D
Subsidies
 Net Projected
Postretirement
Health Care
Benefit Payments
2020 $30.7
 $2.9
 $
 $2.9
2021 29.4
 2.9
 
 2.9
2022 30.3
 2.9
 
 2.9
2023 30.4
 2.9
 
 2.9
2024 30.4
 2.8
 
 2.8
2025-2029 153.5
 13.2
 0.1
 13.1

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 2019, 2018 and 2017.
10. Commitments and Contingencies

Legal
SPS is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves complex judgments about future events. Management maintains accruals for losses that are probable of being incurred and subject to reasonable estimation.
Management may be unable to estimate an amount or range of a reasonably possible loss in certain situations, including 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 the ultimate liabilities, if any, arising from such current proceedings would have a material effect on SPS’ financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.
Rate Matters
Texas Fuel Reconciliation In December 2018, SPS filed an application with the PUCT for reconciliation of fuel costs for the period Jan. 1, 2016, through June 30, 2018, to determine whether all fuel costs incurred were eligible for recovery. In December 2019, the PUCT issued an order disallowing recovery of costs for Texas customers related to two specific solar PPAs. These PPAs were previously approved by the NMPRC as reasonable, necessary and economic. SPS recorded a total disallowance of approximately $6 million in December 2019.
SPP OATT Upgrade Costs — Under the SPP OATT, costs of transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade. SPP had not been charging its customers for these upgrades, even though the SPP OATT had allowed SPP to do so since 2008. In 2016, the FERC granted SPP’s request to recover previously unbilled charges and SPP subsequently billed SPS approximately $13 million.
In July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP the right to recover previously unbilled charges was remanded to the FERC. In February 2019, the FERC reversed its 2016 decision and ordered SPP to refund charges retroactively collected from its transmission customers, including SPS, related to periods before September 2015. In April 2019, several parties, including SPP, filed requests for rehearing. Timing of a FERC response to rehearing requests is uncertain. Any refunds received by SPS are expected to be given back to SPS customers through future rates.
In October 2017, SPS filed a separate complaint against SPP asserting SPP assessed upgrade charges to SPS in violation of the SPP OATT. The FERC granted a rehearing for further consideration in May 2018. Timing of FERC action on the SPS rehearing is uncertain. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the amounts through future SPS customer rates.
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.
In September 2018, SPS protested the proposed SPP tariff charges, and asked the FERC to reject the SPP filing. On Oct. 31, 2018, the FERC issued an order accepting the proposed charges, subject to refund, as of Nov. 1, 2018, and set the case for settlement hearing procedures. Hearings are scheduled for May 2020, with the ALJs’ initial decision expected in October 2020. SPS has incurred approximately $6 million in associated charges as of Dec. 31, 2019.
SPS Filing to Modify Wholesale Transmission Rates — In 2018, SPS filed revisions to its wholesale transmission formula rate. The proposal includes an update to depreciation rates for transmission plant. The new formula rate would also provide a credit to customers of “excess” ADIT resulting from the TCJA and recover certain wholesale regulatory commission expenses.
Proposed changes would increase wholesale transmission revenues by approximately $9.4 million, with approximately $4.4 million of the total recovered in SPP regional transmission rates. SPS proposed formula rate changes be effective Feb. 1, 2019.

37


In January 2019, the FERC issued an order accepting the proposed rate changes as of Feb. 1, 2019, subject to refund and settlement procedures. On Dec. 23, 2019, SPS filed a Stipulation and Agreement of Settlement. If approved by the FERC, the settlement would implement the requested depreciation and TCJA related changes, but would not modify current treatment of wholesale regulatory commission expenses.
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 or Disposal Sites SPS is currently remediating the site of a former facility. SPS has recognized its best estimate of costs/liabilities that will result from final resolution of these issues, however, the outcome and timing is unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.
Environmental Requirements Water and Waste
Federal CWA WOTUS Rule In 2015, the EPA and Corps published a final rule that significantly broadened the scope of waters under the CWA that are subject to federal jurisdiction, referred to as “WOTUS”. In 2019, the EPA repealed the 2015 rule and published a draft replacement rule. Until a final rule is issued, SPS cannot estimate potential impacts, but anticipates costs will be recoverable through regulatory mechanisms.
Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power plants that discharge treated effluent to surface waters as well as utility-owned landfills that receive CCRs. In 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport until November 2020. After 2020, SPS estimates that ELG compliance costs will be immaterial. The EPA, however, is conducting a rulemaking process to revise certain effluent limitations and pretreatment standards, which may impact compliance costs. SPS anticipates these costs will be fully recoverable through regulatory mechanisms.
Environmental Requirements Air
Regional Haze Rules — The regional haze program requires SO2, nitrogen oxide and particulate matter emission controls at power plants to reduce visibility impairment in national parks and wilderness areas. The program includes BART and reasonable further progress. Texas’ first regional haze plan has undergone federal review as described below.







 
BART Determination for Texas: The EPA has issued a revised final rule adopting a BART alternative Texas only SO2 trading program that applies to all Harrington and Tolk units. Under the trading program, SPS expects the allowance allocations to be sufficient for SO2 emissions. The anticipated costs of compliance are not expected to have a material impact; and SPS believes that compliance costs would be recoverable through regulatory mechanisms.
Several parties have challenged whether the final rule issued by the EPA should be considered to have met the requirements imposed in a Consent Decree entered by the United States District Court for the District of Columbia that established deadlines for the EPA to take final action on state regional haze plan submissions. The court has required status reports from the parties while the EPA works on the reconsideration rulemaking.
In December 2017, the National Parks Conservation Association, Sierra Club, and Environmental Defense Fund appealed the EPA’s 2017 final BART rule to the Fifth Circuit and filed a petition for administrative reconsideration. In January 2018, the court granted SPS’ motion to intervene in the Fifth Circuit litigation in support of the EPA’s final rule. The court has held the litigation in abeyance while the EPA decided whether to reconsider the rule. In August 2018, the EPA started a reconsideration rulemaking, which was supplemented by an additional agency notice in November 2019. It is not known when the EPA will make a final decision on this proposal.
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. The EPA has not announced a schedule for acting 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 is to be monitored for three years and a final designation is expected to be made by December 2020.
If the area near the Harrington plant is designated nonattainment in 2020, the TCEQ will need to develop an implementation plan, designed to achieve the NAAQS by 2025. The TCEQ could require additional SO2 controls at Harrington as part of such a plan. SPS cannot evaluate the impacts until the final designation is made and any required state plans are developed. SPS believes that should SO2 control systems be required for a plant, compliance costs or the costs of alternative cost-effective generation will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial condition or cash flows.







38


AROs — AROs have been recorded for SPS’ assets.
SPS’ AROs were as follows:
  2019
(Millions 
of Dollars)
 Jan. 1, 2019 
Amounts Incurred
(a)
 
Amounts
Settled
(b)
 Accretion 
Cash Flow
Revisions (c)
 Dec. 31, 2019
Electric            
Steam and other production $22.0
 $
 $(1.6) $1.4
 $29.5
 $51.3
Wind 
 16.0
 
 0.4
 
 16.4
Distribution 9.1
 
 
 0.4
 
 9.5
Miscellaneous 1.3
 
 
 
 (1.2) 0.1
Total liability $32.4
 $16.0
 $(1.6) $2.2
 $28.3
 $77.3
(a) 
Amounts incurred related to the Hale wind farm placed in service in 2019.
(b) 
Amounts settled related to asbestos abatement projects.
(c) 
In 2019, AROs were revised for changes in timing and estimates of cash flows. Changes in steam production AROs primarily related to the cost estimates to remediate ponds at production facilities.
  2018
(Millions 
of Dollars)
 
Jan. 1,
2018
 Accretion 
Cash Flow
Revisions
(a)
 
Dec. 31,
2018
(b)
Electric        
Steam and other
production
 $20.3
 $1.2
 $0.5
 $22.0
Distribution 7.0
 0.3
 1.8
 9.1
Miscellaneous 1.2
 0.1
 
 1.3
Total liability $28.5
 $1.6
 $2.3
 $32.4
(a) 
In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes in electric distribution AROs were primarily related to increased labor costs.
(b) 
There were no ARO amounts incurred or settled in 2018.
Indeterminate AROs — Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of SPS’ facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2019. Therefore, an ARO has not been recorded for these facilities.
Removal Costs — SPS records a regulatory liability for the plant removal costs that are recovered currently in rates. Removal costs have accumulated based on varying rates as authorized by the appropriate regulatory entities. SPS has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Removal costs as of Dec. 31, 2019 and 2018 were $174.5 million and $187.7 million, respectively.
Leases
SPS evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. Under ASC Topic 842, adopted by SPS on Jan. 1, 2019, 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. Starting in 2019, 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, 2019
PPAs $500.3
Other 48.0
Gross operating lease ROU assets 548.3
Accumulated amortization (25.9)
Net operating lease ROU assets $522.4

Components of lease expense:
(Millions of Dollars) 2019 2018 2017
Operating leases      
PPA capacity payments $48.1
 $51.1
 $51.4
Other operating leases (a)
 4.9
 7.9
 6.4
Total operating lease expense (b)
 $53.0
 $59.0
 $57.8
(a) 
Includes short-term lease expense of $1.5 million, $1.1 million and $1.2 million for 2019, 2018 and 2017, respectively.
(b) 
PPA capacity payments are included in electric fuel and purchased power on the statements of income. Expense for other operating leases is included in O&M expense.
Commitments under operating leases as of Dec. 31, 2019:
(Millions of Dollars) 
PPA (a) (b)
Operating
Leases
 
Other Operating
Leases
 
Total
Operating
Leases
2020 $46.2
 $3.4
 $49.6
2021 46.2
 3.3
 49.5
2022 46.2
 3.4
 49.6
2023 46.2
 3.4
 49.6
2024 46.2
 3.5
 49.7
Thereafter 404.5
 51.3
 455.8
Total minimum obligation 635.5
 68.3
 703.8
Interest component of obligation (160.0) (21.6) (181.6)
Present value of minimum obligation 475.5
 46.7
 522.2
Less current portion     (26.9)
Noncurrent operating lease liabilities     $495.3
       
Weighted-average remaining lease term in years     14.1
(a) 
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.

39


Commitments under operating leases as of Dec. 31, 2018:
(Millions of Dollars) 
PPA (a) (b)
Operating
Leases
 
Other Operating
Leases
 
Total
Operating
Leases
2019 $46.7
 $5.2
 $51.9
2020 46.2
 5.2
 51.4
2021 46.2
 5.1
 51.3
2022 46.2
 5.1
 51.3
2023 46.2
 5.1
 51.3
Thereafter 450.8
 56.3
 507.1
(a) 
Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.
(b) 
PPA operating leases contractually expire at various dates through 2033.
PPAs and Fuel Contracts
Non-Lease PPAs — SPS has entered into PPAs with other utilities and energy suppliers with various expiration dates through 2024 for purchased power to meet system load and energy requirements and operating reserve obligations.
In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Capacity payments are contingent on the IPP meeting contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on financial results are mitigated through purchased energy cost recovery mechanisms.
Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts, were payments for capacity of $19.9 million, $57.6 million and $58.4 million in 2019, 2018 and 2017, respectively.
At Dec. 31, 2019, the estimated future payments for capacity that SPS is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:
(Millions of Dollars) Capacity
2020 $12.3
2021 12.5
2022 12.7
2023 13.0
2024 5.9
Thereafter 
Total $56.4

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 2020 and 2033. SPS is required to pay additional amounts depending on actual quantities shipped under these agreements.
Estimated minimum purchases under these contracts as of Dec. 31, 2019:
(Millions of Dollars) Coal Natural gas
supply
 Natural gas
storage and
transportation
2020 $96.7
 $12.3
 $28.9
2021 67.7
 
 23.3
2022 38.8
 
 17.4
2023 
 
 12.7
2024 
 
 6.7
Thereafter 
 
 26.3
Total $203.2
 $12.3
 $115.3



 
VIEs
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, 2019 and 2018 with entities that have been determined to be VIEs. These agreements have expiration dates through 2041.
Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk plant from TUCO Inc. under contracts that will expire in December 2022. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing, and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.
SPS has not provided any significant financial support to TUCO, other than contractual payments for delivered coal. However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of fuel procurement costs. SPS has determined that TUCO is a VIE. SPS has concluded that it is not the primary beneficiary of TUCO, because SPS does not have the power to direct the activities that most significantly impact TUCO’s economic performance.
11. Other Comprehensive Income
Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:
  2019
(Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total
Accumulated other comprehensive loss at Jan. 1 $(0.7) $(0.7) $(1.4)
Other comprehensive loss before reclassifications (net of taxes of $0 and $(0.1), respectfully 
 (0.2) (0.2)
Losses reclassified from net accumulated other comprehensive loss:      
Amortization of net actuarial loss (net of taxes of $0) 
 0.2
(a) 
0.2
Net current period other comprehensive income (loss) 
 
 
Accumulated other comprehensive loss at Dec. 31 $(0.7) $(0.7) $(1.4)

(a) 
Included in the computation of net periodic pension and postretirement benefit costs. See Note 9 for further information.

40


  2018
(Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total
Accumulated other comprehensive loss at Jan. 1 $(0.8) $(0.7) $(1.5)
Losses reclassified from net accumulated other comprehensive loss: 

 

 

Interest rate derivatives (net of taxes of $0) 0.1
(a) 

 0.1
Net current period other comprehensive income 0.1
 
 0.1
Accumulated other comprehensive loss at Dec. 31 $(0.7) $(0.7) $(1.4)

(a) 
Included in interest charges.
12. 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, PSCo and SPS have established a utility money pool arrangement with the utility subsidiaries.
See Note 5 for further information.
Significant affiliate transactions among the companies and related parties for the years ended Dec. 31:
(Millions of Dollars) 2019 2018 2017
Operating expenses:      
Purchased power $
 $
 $1.4
Other operating expenses — paid to Xcel Energy Services Inc. 192.0
 195.1
 196.6
Interest expense 0.2
 0.6
 

Accounts receivable and payable with affiliates at Dec. 31 were:
  2019 2018
(Millions of Dollars) Accounts
Receivable
 Accounts
Payable
 Accounts
Receivable
 Accounts
Payable
NSP-Minnesota $4.2
 $
 $4.7
 $
PSCo 
 0.4
 
 0.7
Other subsidiaries of Xcel Energy Inc. 
 20.0
 5.8
 19.2
  $4.2
 $20.4
 $10.5
 $19.9

13. Summarized Quarterly Financial Data (Unaudited)
  Quarter Ended
(Millions of Dollars) March 31, 2019 June 30, 2019 Sept. 30, 2019 Dec. 31, 2019
Operating revenues $454.1
 $410.5
 $533.1
 $428.1
Operating income 74.5
 81.9
 135.4
 54.9
Net income 54.1
 58.8
 105.1
 45.1
 
  Quarter Ended
(Millions of Dollars) March 31, 2018 June 30, 2018 Sept. 30, 2018 Dec. 31, 2018
Operating revenues $447.2
 $481.3
 $540.1
 $464.6
Operating income (a)
 57.1
 87.6
 111.0
 56.0
Net income 33.1
 58.5
 81.5
 40.2

(a) 
In 2018, SPS implemented ASU No. 2017-07 related to net periodic benefit cost, which resulted in retrospective reclassification of pension costs from O&M expense to other income.
ITEM 9 — CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
SPS maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the CEO and CFO, allowing timely decisions regarding required disclosure. As of Dec. 31, 2019, 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, 2019 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.

41


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 2020 Annual Meeting of Shareholders, which is incorporated by reference.
 
ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm – Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for its 2020 Annual Meeting of Shareholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 6, 2020. Such information set forth under such heading is incorporated herein by this reference hereto.
PART IV
ITEM 15 — EXHIBITS, FINANCIAL STATEMENT SCHEDULES
1Financial Statements
 Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2019.
 
Report of Independent Registered Public Accounting Firm  Financial Statements
 
Statements of Income  For the three years ended Dec. 31, 2019, 2018 and 2017.
 
Statements of Comprehensive Income  For the three years ended Dec. 31, 2019, 2018 and 2017.
 
Statements of Cash Flows  For the three years ended Dec. 31, 2019, 2018 and 2017.
 
Balance Sheets  As of Dec. 31, 2019 and 2018.
 
Statements of Common Stockholder’s Equity  For the three years ended Dec. 31, 2019, 2018 and 2017.
  
2
Schedule II  Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2019, 2018 and 2017.
  
3Exhibits
*Indicates incorporation by reference
+Executive Compensation Agreements and Benefit Plans Covering Executive Officers and Directors
Exhibit NumberDescriptionReport or Registration StatementSEC File or Registration NumberExhibit Reference
SPS Form 10-Q for the quarter ended Sept. 30, 2017001-037893.01
SPS Form 10-K for the year ended Dec. 31, 2018001-037893.02
SPS Form 8-K dated Feb. 25, 1999001-0378999.2
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2003001-030344.04
SPS Form 8-K dated Oct. 3, 2006001-037894.01
SPS Form 8-K dated Aug. 10, 2011001-037894.01
SPS Form 8-K dated Aug. 10, 2011001-037894.02
SPS Form 8-K dated June 9, 2014001-037894.02
SPS Form 8-K dated Aug. 12, 2016001-037894.02
SPS Form 8-K dated Aug. 9, 2017001-037894.02

42


SPS Form 8-K dated Nov. 5, 2018001-037894.02
SPS Form 8-K dated June 18, 2019001-037894.02
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008001-0303410.02
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008001-0303410.05
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008001-0303410.08
Xcel Energy Inc. Form U5B dated Nov. 16, 2000001-03034H-1
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008001-0303410.17
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009001-0303410.06
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009001-0303410.08
Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010001-03034Appendix A
Xcel Energy Inc. Definitive Proxy Statement dated April 5, 2011001-03034Appendix A
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008001-0303410.07
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011001-0303410.18
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011001-0303410.17
Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013001-0303410.01
Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013001-0303410.02
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013001-0303410.22
Xcel Energy Inc. Form 8-K dated May 20, 2015001-0303410.02
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2016001-0303410.01
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016001-0303410.01
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017001-0303410.1
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017001-0303410.30
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018001-0303410.01
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018001-0303410.34
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018001-0303410.35
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018001-0303410.36
Xcel Energy Inc. Form 8-K dated June 7, 2019001-0303499.04
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019001-0303410.33
101.INSXBRL 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.SCHXBRL Schema
101.CALXBRL Calculation
101.DEFXBRL Definition
101.LABXBRL Label

43


101.PREXBRL Presentation
104Cover 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) 2019 2018 2017
Balance at Jan. 1 $5.6
 $6.4
 $6.4
Additions charged to costs and expenses 5.7
 4.9
 5.1
Additions charged to other accounts (a)
 1.5
 1.0
 1.2
Deductions from reserves (b)
 (7.5) (6.7) (6.3)
Balance at Dec. 31 $5.3
 $5.6
 $6.4
(a) 
Recovery of amounts previously written off.
(b) 
Deductions related primarily to bad debt write-offs.
ITEM 16 — FORM 10-K SUMMARY
None.

44


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. 21, 2020 /s/ ROBERT C. FRENZEL
  Robert C. Frenzel
  Executive Vice President, Chief Financial Officer and Director
  (Principal Financial Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the date indicated above.
/s/ BEN FOWKE /s/ DAVID T. HUDSON
Ben Fowke David T. Hudson
Chairman, Chief Executive Officer and Director President and Director
(Principal Executive Officer)  
   
/s/ ROBERT C. FRENZEL /s/ JEFFREY S. SAVAGE
Robert C. Frenzel Jeffrey S. Savage
Executive Vice President, Chief Financial Officer and Director Senior Vice President, Controller
(Principal Financial Officer) (Principal Accounting Officer)
   
/s/ DAVID L. EVES  
David L. Eves  
Executive Vice President, Group President, Utilities 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.


45