UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549

FORM 10-K
(Mark One)
x☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20172019
or
¨☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number:  001-03789
SOUTHWESTERN PUBLIC SERVICE COMPANY
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.)

New Mexico790 South Buchanan Street,Amarillo,
Texas
 75-057540079101
State or other jurisdiction
   (Address of incorporation or organizationPrincipal Executive Offices)

 (I.R.S. Employer Identification No.)Zip Code)

(303)571-7511
(Registrant’s Telephone Number, Including Area Code)
790 South Buchanan Street, Amarillo, Texas  79101
(Address of principal executive offices)
Registrant’s telephone number, including area code:  303-571-7511
Securities registered pursuant to Section 12(b) of the Act:None
Title of each classTrading SymbolName of each exchange on which registered
N/AN/AN/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.  ¨☒Yesx☐ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 1313 or Section 15(d) of the Act.  ¨☐ Yes x☒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.  x☒Yes¨☐ No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 andof 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 and post such files).  x☒Yes¨☐ No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x
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,”filer”, “accelerated filer,”filer”, “smaller reporting company,”company”, and “emerging growth company” in Rule 12b-2 of the Exchange ActAct. ☐ Large accelerated Filer ☐ Accelerated Filer ☒Non-accelerated Filer☐ Smaller Reporting Company ☐ Emerging Growth Company
Large accelerated filer ¨
Accelerated filer ¨
Non-accelerated filer x
Smaller Reporting Company ¨
(Do not check if a 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   x☒ No
As of Feb. 23, 201821, 2020, 100 shares of common stock, par value $1$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 20182020 Annual Meeting of StockholdersShareholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 3, 2018.6, 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
Index
PART I
3
Item 1 —
Business
3
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMSDefinition of Abbreviations
3
COMPANY OVERVIEWForward-Looking Statements
54
ELECTRIC UTILITY OPERATIONSWhere To Find More Information
54
Public Utility RegulationCompany Overview
54
Capacity and DemandElectric Operations
4
Public Utility Regulation
6
Energy Sources and Related Transmission Initiatives
6
Fuel Supply and CostsGeneral
7
Fuel SourcesEnvironmental
7
Renewable Energy SourcesEmployees
8
Item 1A —
Wholesale Commodity Marketing OperationsRisk Factors
8
Item 1B —
Summary of Recent Federal Regulatory DevelopmentsUnresolved Staff Comments
913
Item 2 —
Electric Operating StatisticsProperties
1013
Item 3 —
Natural Gas Facilities Used for Electric GenerationLegal Proceedings
1113
Item 4 —
GENERALMine Safety Disclosures
1113
ENVIRONMENTAL MATTERS
12
EMPLOYEES
12
Item 1A — Risk Factors
12
Item 1B — Unresolved Staff Comments
21
Item 2 — Properties
22
Item 3 — Legal Proceedings
22
Item 4 — Mine Safety Disclosures
22
  
PART II
2313
Item 5 —
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
2313
Item 6 —
Selected Financial Data
2313
Item 7 —
Management’s Discussion and Analysis of Financial Condition and Results of Operations
2313
Item 7A —
Quantitative and Qualitative Disclosures About Market Risk
2516
Item 8 —
Financial Statements and Supplementary Data
2716
Item 9 —
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
7041
Item 9A —
Controls and Procedures
7041
Item 9B —
Other Information
7041
  
PART III
7142
Item 10 —
Directors, Executive Officers and Corporate Governance
7142
Item 11 —
Executive Compensation
7142
Item 12 —
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
7142
Item 13 —
Certain Relationships and Related Transactions, and Director Independence
7142
Item 14 —
Principal Accountant Fees and Services
7142
  
PART IV
7142
Item 15 —
Exhibits, Financial Statement Schedules
7142
Item 16 - —
Form 10-K Summary
7744
  
SIGNATURESSignatures
7545


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.

PART I
Item l — Business

ITEM l — BUSINESS
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMSDefinitions of Abbreviations
Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
NCENew Century Energies, Inc.
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
CFTCCommodity Futures Trading Commission
D.C. CircuitUnited States Court of Appeals for the District of Columbia Circuit
DOE
United States Department of Energy

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 Terms and Abbreviations
ADITAccumulated deferred income taxes
AFUDCAllowance for funds used during construction
ALJAdministrative law judge
APBOAccumulated postretirement benefit obligationLaw Judge
AROAsset retirement obligation
ASCFASB Accounting Standards Codification
ASUFASB Accounting Standards Update
BARTBest available retrofit technology
CAACEOClean Air ActChief executive officer
CAIRCFOClean Air Interstate RuleChief financial officer
C&ICommercial and Industrial
CO2
Corps		Carbon dioxide
CCNCertificateU.S. Army Corps of convenience and necessity
CPPClean Power Plan
CSAPRCross-State Air Pollution RuleEngineers
CWIPConstruction work in progress
EGUDSMElectric generating unit

Demand side management
ELG
ERCOTElectric Reliability Council of TexasEffluent limitations guidelines
ETREffective tax rate
FASBFinancial Accounting Standards Board
FTRFinancial transmission right
GAAPGenerally accepted accounting principles
GHGGreenhouse gas
IMIntegrated Marketplace
IPPIndependent power producersproducing entity
IRCIRPInternal Revenue CodeIntegrated Resource Plan
ITCInvestment tax credit
MISOMGPMidcontinent Independent System Operator, Inc.Manufactured 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
NOxNitrogen oxide
NTCNotifications to construct
O&MOperating and maintenance
OCIOATTOther comprehensive income
PJMPJM Interconnection, LLC
PMParticulate matterOpen Access Transmission Tariff
PPAPurchased power agreement
PRPPotentially responsible party
PSIAPipeline system integrity adjustment
PTCProduction tax credit
PVPhotovoltaic
QFQualifying facilities
R&EResearch and experimentation
RECRenewable energy credit
ROEReturn on equity
RPSROFRRenewable portfolio standardsRight-of-first-refusal
ROURight-of-use
RTORegional Transmission Organization
SIPSERPState implementationSupplemental executive retirement plan
SO2
Sulfur dioxide
SPPSouthwest Power Pool, Inc.
Standard & Poor’sStandard & Poor’s Ratings Services
TCJA
2017 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



COMPANY OVERVIEW
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.
SPS was incorporated in 1921 under the laws of New Mexico.  
Where to Find More Information

SPS is a utility engaged primarily in the generation, purchase, transmission, distribution, and sale of electricity in portions of Texas and New Mexico.  SPS provides electric utility service to approximately 390,000 retail customers in Texas and New Mexico.  Approximately 71 percent of SPS’ retail electric operating revenues were derived from operations in Texas during 2017 and 2016.  Although SPS’ large C&I electric retail customers are comprised of many diversified industries, a significant portion of SPS’ large C&I electric sales include: oil and gas extraction, as well as petroleum refining and related industries.  For small C&I customers, significant electric retail sales include the following industries: oil and gas extraction and grocery establishments.  Generally, SPS’ earnings contribute approximately 10 percent to 15 percentwholly owned subsidiary of Xcel Energy Inc., and Xcel Energy’s consolidated net income.

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 wholesale customers served by SPS comprised approximately 29 percent of its total KWh sold in 2017.  

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.
ELECTRIC UTILITY OPERATIONS
Company Overview

spsstatea09.jpg
Electric customers0.4 millionSPS 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
Public Utility Regulation
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

Summary
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 Regulatory Agenciestotal energy for 2019:
chart-03ce4be280626248555a01.jpg
(a)
Includes biomass and hydroelectric.
Wind Energy Sources
Owned — Owned and Areasoperated wind farms with corresponding capacity:
2019 2018
Wind Farms Capacity Wind Farms Capacity
1 478 MW — —
PPAs — Number of JurisdictionPPAs with range:
2019 2018
PPAs Range PPAs Range
18 0.7 MW - 250.0 MW 18 0.7 MW - 250.0 MW
Capacity — The PUCT and NMPRC regulate 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:
ProjectCapacity
Hale460 MW
SPS currently has approximately 522 MW of wind under development or construction with an estimated completion date of 2020:
ProjectCapacityEstimated Completion
Sagamore522 MW2020
Solar Energy Sources
Solar energy PPAs:
TypeCapacity
Distributed Generation10 MW
Utility-Scale191 MW

Fossil Fuel Energy Sources
SPS’ retail electric operations and have jurisdiction over its retail rates and services and the construction of transmission or generation in their respective states. The municipalities in which SPS operates in Texas have original jurisdiction over SPS’ rates in those communities. The municipalities’ rate setting decisions are subject to review by the PUCT, which has ultimate authority to set the rates SPS charges in the municipalities. The NMPRC also has jurisdiction over the issuance of securities. SPS is regulated by the FERC for its 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,fossil fuel energy portfolio includes coal and natural gas transactions in interstate commerce. As approved by the FERC, SPS is a transmission-owning member of the SPP RTOpower from both owned generating facilities and operates within the SPP RTO and SPP IM wholesale market. SPS is authorized to make wholesale electric sales at market-based prices.PPAs.

See Item 2 — Properties for further information.
Fuel, PurchasedCoal Energy and Conservation Cost-Recovery Mechanisms—Sources
SPS has several retail adjustment clauses that recovertwo 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 purchased energyrequirements:
  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 other resource costs:

DCRF — Recovers distribution costs in Texas thatstorage services for power plants are not included in base rates.
EECRF — Recovers costs associated with providing energy efficiency programs in Texas.
EE rider — Recovers costs associated with providing energy efficiency programs in New Mexico.
FPPCAC — Adjusts monthlyprocured to recover the actual fuel and purchased power costs.
PCRF — Allows recoveryprovide an adequate supply of certain purchased power costs in Texas thatfuel. Remaining requirements are not included in base rates.
RPS — Recovers deferred costs associated with renewable energy programs in New Mexico.
TCRF — Recovers certain transmission infrastructure improvement costs and changes in wholesale transmission charges in Texas that are not included in base rates.

Fuel and purchased energy costs are recovered in Texasprocured through a fixed fuelliquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to natural gas indices. Natural gas supply and purchased energy recovery factor, which is part of SPS’ retail electric tariff. SO2 and NOx allowance revenues and costs are also recovered through the fixed fuel and purchased energy recovery factor. The regulations allow retail fuel factors to change up to three times per year.

The fixed fuel and purchased energy recovery factor providestransportation agreements include obligations for the over- purchase and/or under-recoverydelivery 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 and purchased energy expenses. Regulations also require refunding or surcharging over- or under- recovery amounts, including interest, when they exceed four percent of the utility’s annual fuel and purchased energy costs on a rolling 12-month basis, if this condition is expected to continue.requirements:

PUCT regulations require periodic examination of SPS’ fuel and purchased energy costs, the efficient use of fuel and purchased energy, fuel acquisition and management policies and purchased energy commitments. SPS is required to file an application for the PUCT to retrospectively review fuel and purchased energy costs at least every three years. In June 2016, SPS filed its fuel reconciliation application which reconciled fuel and purchased power costs for 2013 through 2015. In March 2017, the PUCT approved the application.
  Natural Gas
  Cost Percent
2019 $1.14
 55%
2018 2.24
 44

SPS recovers fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased economic energy cost adjustment clause accepted for filing by the FERC.


CapacityRenewable Energy Sources
SPS’ renewable energy portfolio includes wind and Demandsolar 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.
Uninterrupted system peak demand
Renewable energy as a percentage of total energy for SPS for each of the last three years2019:
chart-03ce4be280626248555a01.jpg
(a)
Includes biomass and hydroelectric.
Wind Energy Sources
Owned — Owned and the forecast for 2018, assuming normal weather conditions, is as follows:operated wind farms with corresponding capacity:
 System Peak Demand (in MW)
 2017 2016 2015 2018 Forecast
SPS4,374
 4,836
 4,678
 4,483
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:
ProjectCapacity
Hale460 MW
SPS currently has approximately 522 MW of wind under development or construction with an estimated completion date of 2020:
ProjectCapacityEstimated Completion
Sagamore522 MW2020
Solar Energy Sources
Solar energy PPAs:
TypeCapacity
Distributed Generation10 MW
Utility-Scale191 MW

The peak demand
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 the SPS system typically occurs in the summer. The 2017 system peak demand for SPS occurred on July 26, 2017. The decline in peak load from 2016 to 2017 is in part due to cooler weather in 2017. Additionally, the partial requirement contract with Golden Spread ended May 2017, contributing to the lower actual peak demand for SPS. The 2018 forecast assumes normal peak day weather.further information.

Coal Energy Sources and Related Transmission Initiatives

SPS expectshas two coal plants with approximately 2,100 MW of total 2019 net summer dependable capacity.
SPS plans to use existing electric generating stations, power purchases, DSM and new generation optionscontinue to meetevaluate its system capacity requirements. In addition, SPS has evaluated water supply issues at its Tolk facility, concluding that additional resource investment will be required to operate thecoal fleet for other potential early coal plant through its existing life. The Ogallala aquifer in this region of the country has depleted more rapidly than expected and SPS installed a horizontal water well that could help to delay the need for a more substantial investment solution. As a result of this issue and to a lesser extent, future environmental rules facing the plant, SPS is seeking a decrease to the remaining life of the facility in its current Texas and New Mexico rate case proceedings (see Note 10).

Purchased Power— SPS has contracts to purchase power from other utilities and IPPs. Long-term purchased power contracts typically require a periodic capacity charge and an energy charge for energy actually purchased. SPS also makes short-term purchases to meet system load and energy requirements, to replace generation from company-owned units under maintenance or during outages, to meet operating reserve obligations or to 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.

TUCO Substation to Yoakum County Substation to Hobbs Plant Substation 345 KV Transmission Line— In 2014, SPP evaluated anticipated transmission needs for certain parts of the SPP region which is commonly knownretirements as the High Priority Incremental Load Study. As a result, SPS received 44 transmission projects, with an original estimated cost of $557 million. The most significant of these projects are the TUCO Substation to the Yoakum County Substation to the Hobbs Plant Substation and the Hobbs Plant Substation to the China Draw Substation transmission line projects.

In 2016 and 2017, SPS received CCNs for the three segments of the TUCO Substation to Yoakum County Substation to Hobbs Plant Substation 345 KV transmission line, which are expected to be in service in the second quarter of 2020. This 345 KV transmission line is part of a larger project which includes an additional 345 KV transmission line from the Hobbs Plant Substation to the China Draw Substation, which was approved by the NMPRC in 2016 and is anticipated to be in service by June 2018. The estimated total investment for these transmission lines is approximately $402 million. 

Wind Proposals — In March 2017, SPS filed proposals with the NMPRC and the PUCT to build, own and operate 1,000 MW of new wind generation through two wind farms for a cost of approximately $1.6 billion. In addition, the proposal includes a PPA for 230 MW of wind.

In December 2017, SPS and parties filed a unanimous stipulation with the NMPRC. The stipulation is subject to approval by the NMPRC. The key terms of the stipulation are listed below:

An investment cap of $1,675 per KW, which is equal to 102.5 percent of the estimated construction costs;
SPS customers would receive a credit to their bills if actual capacity factors fall below 48 percent;
SPS customers would receive 100 percent of the federal PTC; and
SPS can file a HTY rate case and include projected capital additions for the wind farms five months beyond the end of the test year. Interim rates would also be made effective 30 days after filing which will allow SPS to closely match the start of cost recovery for that wind farm with the in service date.


On Feb. 9, 2018, the Hearing Examiner issued a certification of stipulation (certification) recommending approval of all but one aspect of the stipulation, which is the provision for interim rate recovery of SPS’ investment in the two wind farms. On Feb. 19, 2018, SPS filed exceptions to the recommended decision, as didstate resource plans or other parties to the stipulation.

In addition, SPS has reached a settlement in principle with parties in Texas and is working towards finalizing a stipulation. SPS has shared an updated analysis with all parties which shows the wind projects remain cost-effective following the passage of the TCJA. The settlements require approval by the NMPRC and PUCT. Both commissions are expected to rule on the settlements by the end of the first quarter of 2018. The Hale wind project in Texas and the Sagamore wind project in New Mexico are scheduled to be in service by mid-2019 and year-end 2020, respectively.

Lubbock Power & Light’s (LP&L’s) Request for Participation in ERCOT — In September 2017, LP&L filed its application with the PUCT and proposed to transition a portion of its load to ERCOT no later than June 2021. As a result of LP&L’s proposal, approximately $18 million in wholesale transmission revenue would be reallocated to remaining SPS transmission customers at the time of the load transition.  In November 2017, SPS and various other parties, including the PUCT Staff, filed direct testimony in response to LP&L’s application. SPS proposed an Interconnection Switching Fee to be determined by the PUCT.

In February 2018, SPS, LP&L, the PUCT Staff and various other parties filed a stipulation that provides SPS’ customers with an Interconnection Switching Fee of approximately $24 million to compensate them for the transfer of LP&L’s load from SPP to ERCOT. Under the settlement, SPS would allocate the Interconnection Switching Fee to its Texas and New Mexico retail and wholesale transmission customers through a bill credit following LP&L’s load transition to ERCOT (tentatively, June 2021). A PUCT decision is expected in March 2018. No final decision regarding LP&L’s departure or its potential timing is expected until completion of the PUCTregulatory proceedings.
Texas State ROFR Request for Declaratory Order — In February 2017, SPS and SPP filed a joint petition with the PUCT for a declaratory order regarding SPS’ ROFR. SPS contended that Texas law grants an incumbent electric utility, operating in areas outside of ERCOT, the ROFR to construct new transmission facilities located in the utility’s service area. SPP stated that Texas law does not provide a clear statement regarding the ROFR for incumbent utilities and therefore SPP was abiding by the portion of its OATT, which requires competitive solicitation to construct and operate new transmission facilities within areas of Texas’ SPP footprint.Coal Fuel Cost
In October 2017, the PUCT issued an order finding that SPS does not possess an exclusive right to construct and operate transmission facilities within its service area. In January 2018, SPS and two other parties filed appeals of the PUCT’s order in the Texas State District Court. The appeals have been consolidated. A schedule has not been set for the case.

Fuel Supply and Costs

The following table shows the deliveredDelivered cost per MMBtu of each significant category of fuelcoal consumed for owned electric generation theand percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.requirements:
  Coal Natural Gas 
Weighted Average
Owned Fuel Cost
SPS Generating Plants Cost Percent Cost Percent 
2017 $2.18
 74% $3.39
 26% $2.50
2016 2.12
 70
 2.81
 30
 2.32
2015 2.12
 73
 3.11
 27
 2.39
  Coal
  Cost Percent
2019 $2.19
 45%
2018 2.04
 56

See Items 1A and 7 for further discussion of fuel supply and costs.

FuelNatural Gas Energy Sources

Coal—SPS purchases all of the coal requirements for its two coal facilities, Harrington and Tolk electric generating stations, from TUCO. 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. The coal supply contract with TUCO expires on Dec. 31, 2022 for both Harrington and Tolk.

SPS normally maintains approximately 35 - 50 days of coal inventory. As of Dec. 31, 2017 and 2016, coal inventories at SPS were approximately 52 and 64 day supply, respectively. Milder weather, purchase commitments and relatively low power andhas eight natural gas prices resulted in coal inventories being above optimal levels. SPS’ generation stations primarily use low-sulfur western coal from mines operating in Wyoming. TUCO has coal agreements to supply 79 percentplants with approximately 2,300 MW of SPS’ estimated coal requirements in 2018 and a declining percentage of requirements in subsequent years. SPS’ general coal purchasing objective is to contract for approximately 75 percent of requirements for the first year, 40 percent of requirements in year two and 20 percent of requirements in year three.total 2019 net summer dependable capacity.

Natural gas— SPS uses both firm and interruptible natural gas supply in combustion turbines and certain boilers. Natural gas supplies, transportation and storage services for SPS’ power plants isare procured under contracts to provide an adequate supply of fuel, which typically is purchased with terms of one year or less. The transportation and storage contracts expire between 2018 to 2033. All of thefuel. Remaining requirements are procured through a liquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to various natural gas indices.

Most transportation contract pricing is based on FERC and Railroad Commission of Texas approved transportation tariff rates. Certain natural Natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. SPS’ commitments related to
Natural Gas Cost
Delivered cost per MMBtu of natural gas supply contracts were approximately $11 millionconsumed for owned electric generation and $17 million and commitments related to gas transportation and storage contracts were approximately $191 million and $161 million at Dec. 31, 2017 and 2016, respectively.percentage of total fuel requirements:

SPS has limited on-site fuel oil storage facilities and primarily relies on the spot market for incremental supplies.

  Natural Gas
  Cost Percent
2019 $1.14
 55%
2018 2.24
 44
Renewable Energy Sources

SPS’ renewable energy portfolio includes wind and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2017, SPS is in compliance with mandated RPS, which require generation from renewable resources of 3.7 percent of Texas electric retail salesRenewable percentages will vary year over year based on system additions, weather, system demand and 15.0 percent of New Mexico electric retail sales.transmission constraints.

See Item 2 — Properties for further information.
Renewable energy as a percentage of SPS’ total energy:energy for 2019:
chart-03ce4be280626248555a01.jpg
(a)
Includes biomass and hydroelectric.
Wind Energy Sources
Owned — Owned and operated wind farms with corresponding capacity:
  2017 2016
Renewable 24.0% 22.8%
Wind 21.2
 21.6
Solar 1.8
 1.2
2019 2018
Wind Farms Capacity Wind Farms Capacity
1 478 MW — —

PPAs — Number of PPAs with range:
SPS also offers customer-focused renewable energy initiatives. Windsource® allows customers in New Mexico to purchase electricity from renewable sources. The number of customers utilizing Windsource increased to approximately 940 in 2017 from 900 in 2016.
2019 2018
PPAs Range PPAs Range
18 0.7 MW - 250.0 MW 18 0.7 MW - 250.0 MW

Capacity — Wind capacity:
Wind
2019 2018
2,045 MW 1,565 MW
Average Cost (PPAs) — SPS acquires its wind energy from IPP contracts and QF tariffs. SPS currently has 24 of these agreements in place, with facilities ranging in size from under two MW to 250 MW.

SPS had approximately 1,500 MW of wind energy on its system at the end of 2017 and 2016. In addition to receiving purchased wind energy under these agreements, SPS typically receives wind RECs on certain agreements which are used to meet state renewable resource requirements.
The averageAverage cost per MWh of wind energy under the IPP contractsexisting PPAs:
2019 2018
$25 $26
Wind Energy Development
SPS placed approximately 460 MW of wind into service during 2019:
ProjectCapacity
Hale460 MW
SPS currently has approximately 522 MW of wind under development or construction with an estimated completion date of 2020:
ProjectCapacityEstimated Completion
Sagamore522 MW2020
Solar Energy Sources
Solar energy PPAs:
TypeCapacity
Distributed Generation10 MW
Utility-Scale191 MW

Fossil Fuel Energy Sources
SPS’ fossil fuel energy portfolio includes coal and QF tariffs wasnatural 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 $272,100 MW of total 2019 net summer dependable capacity.
SPS plans to continue to evaluate its coal fleet for 2017 and $25 for 2016. Theother potential early coal plant retirements as part of state resource plans or other regulatory proceedings.
Coal Fuel Cost
Delivered cost per MWhMMBtu 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:
ProjectMilesSize
TUCO-Yoakum-Hobbs64
345 KV
NEF-Cardinal15
115 KV
Potash Junction-Livingston Ridge15
115 KV
Mustang-Shell9
115 KV
North Loving-South Loving3
115 KV
Cunningham-Monument Tap7
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 BodyAdditional 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.
NMPRCRetail electric operations, rates services, construction of transmission or generation and other aspects of electric operations.
FERCWholesale 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 MarketSPS 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
MechanismAdditional Information
DCRFRecovers distribution costs not included in rates in Texas.
EECRFRecovers costs for energy efficiency programs in Texas.
EE RiderRecovers costs for energy efficiency programs in New Mexico.
FPPCACAdjusts monthly to recover fuel and purchased power costs in New Mexico.
PCRFAllows recovery of purchased power costs not included in Texas rates.
RPSRecovers deferred costs for renewable energy programs in New Mexico.
TCRFRecovers transmission infrastructure improvement costs and changes in wholesale transmission charges not included in Texas base rates.
Fixed Fuel and Purchased Recovery FactorProvides 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 AdjustmentSPS recovers production, fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased energy cost adjustment clause accepted by the FERC. Wholesale customers also pay the jurisdictional allocation of production costs.







Resource Plan
In December 2018, the NMPRC issued a final order accepting SPS’ IRP.
SPS is forecasting a surplus capacity of 382 MW in 2028, but a capacity deficit of approximately 2,896 MW in 2038. SPS’ optimal resource plan for the planning period incorporates the addition of wind, simple cycle combustion turbine generation, combined cycle energy varies by contract and entering PPAs. Various factors may impact this IRP, which could potentially require updates to the action plan and will be influenced bythe 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 numberlower 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 factors including regulation, state-specific renewable resource requirementsthe FERC with respect to natural gas transactions in interstate commerce and the year of contract execution.  Generally, contracts executed in 2017 continued to benefit from improvements in technology, excess capacity among manufacturers,PHMSA and motivation to commence new construction prior to the anticipated expiration of the federal PTCs. In December 2015, the federal PTCs were extended through 2019 with a phase down on sites that began construction in 2017.

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. See Item 7 for further discussion.


Summary of Recent Federal Regulatory Developments

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. In addition to the matters discussed below, see Note 10 to the accompanying financial statements for a discussion of other regulatory 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 CFTC jurisdictions. Public campaigns are conducted to raise awareness of the public safety issues of interacting with our electric systems. While programs to comply with regulatory requirements are in place, there is no guarantee the compliance programs or other measures will be sufficient to ensure against violations.

DOE Grid Resiliency Notice of Proposed Rule (NOPR) — In September 2017, the DOE requested the FERC to consider and adopt a Grid Resiliency and Pricing Rule to address threats to the U.S. electrical grid. Under the proposed rule, coal and nuclear generation facilities would have to meet certain criteria to qualify for full recovery of their costs including a fair rate of return. In January 2018, the FERC rejected the DOE’s proposal, but alternatively initiated an inquiry into how RTOs and Independent System Operators address grid resilience. Efforts to resolve U.S. grid resilience issues may result from this proceeding and Xcel Energy plans to monitor and respond as necessary.


Electric Operating Statistics

Electric Sales Statistics
 Year Ended Dec. 31
 2017 2016 2015
Electric sales (Millions of KWh)     
Residential3,356
 3,478
 3,536
Large C&I10,721
 10,518
 10,334
Small C&I4,701
 4,708
 4,719
Public authorities and other527
 555
 538
Total retail19,305
 19,259
 19,127
Sales for resale7,759
 8,689
 8,694
Total energy sold27,064
 27,948
 27,821
      
Number of customers at end of period     
Residential306,248
 305,076
 304,711
Large C&I221
 219
 221
Small C&I77,351
 77,319
 77,238
Public authorities and other6,316
 6,377
 6,354
Total retail390,136
 388,991

388,524
Wholesale7
 8
 8
Total customers390,143
 388,999

388,532
      
Electric revenues (Thousands of Dollars)     
Residential$367,234
 $343,475
 $347,966
Large C&I516,786
 462,576
 445,853
Small C&I375,961
 322,599
 353,450
Public authorities and other48,045
 44,892
 42,963
Total retail1,308,026
 1,173,542
 1,190,232
Wholesale388,715
 414,815
 409,956
Other electric revenues221,259
 262,602
 187,030
Total electric revenues$1,918,000
 $1,850,959
 $1,787,218
      
KWh sales per retail customer49,483
 49,510
 49,230
Revenue per retail customer$3,353
 $3,017
 $3,063
Residential revenue per KWh
10.94¢ 
9.88¢ 
9.84¢
Large C&I revenue per KWh4.82
 4.40
 4.31
Small C&I revenue per KWh8.00
 6.85
 7.49
Total retail revenue per KWh6.78
 6.09
 6.22
Wholesale revenue per KWh5.01
 4.77
 4.72

Energy Source Statistics
 Year Ended Dec. 31
 2017 2016 2015
 
Millions of
KWh
 
Percent of
Generation
 
Millions of
KWh
 
Percent of
Generation
 
Millions of
KWh
 
Percent of
Generation
Coal10,999
 40% 10,990
 39% 12,441
 44%
Natural Gas9,950
 36
 10,909
 38
 10,514
 36
Wind (a)
5,828
 21
 6,120
 22
 5,252
 19
Other (b)
770
 3
 347
 1
 150
 1
Total27,547
 100% 28,366
 100% 28,357
 100%
            
Owned generation12,845
 47% 15,015
 53% 16,480
 58%
Purchased generation14,702
 53
 13,351
 47
 11,877
 42
Total27,547
 100% 28,366
 100% 28,357
 100%

(a)
This category includes wind energy de-bundled from RECs and also includes Windsource RECs. SPS uses RECs to meet or exceed state resource requirements and may sell surplus RECs.
(b)
Distributed generation from the Solar*Rewardsprogram is not included, and was approximately 26, 14 and 13 million net KWh for 2017, 2016, and 2015, respectively.
General

Natural Gas Facilities Used for Electric Generation

SPS does not provide retail natural gas service, but purchases and transports natural gas for certain of 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 certain natural gas transactions in interstate commerce, and to the jurisdiction of the PHMSA and the PUCT for pipeline safety compliance.

GENERAL

Seasonality

The demandDemand 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. See Item 7 for further discussion.

Competition

SPS is a vertically integrated utility, subject to traditional cost-of-service regulation. However, SPS is subject to different public policies that promote competition and the development of energy markets. SPS’ industrial and large commercial customers have the ability to own or operate facilities to generate their own electricity. In addition, customers may have the option of substituting other fuels such as natural gas, steam or chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region.
Customers also have the opportunity to supply their own power with distributed generation including solar generation (typically rooftop solar) and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them.
Several states including New Mexico, have policies designed to promoteincentives for the development of rooftop solar, community solar gardens and other distributed energy resources through significant incentive policies; with these incentives and federal tax subsidies, distributedresources. Distributed generating resources are potential competitors to SPS’ electric service business.


business with these incentives and federal tax subsidies.
The FERC has continued to promote competitive wholesale markets through open access transmission and other means. As a result, SPSSPS’ wholesale customers can purchase their output from generation resources fromof competing wholesale 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. State public utilities commissions, including the NMPRC, have created resource planning programs that promote competition in the acquisition of electricity generation resources used to provide service to retail customers. In addition,
FERC Order No. 1000 seeks to establishestablished 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 certain cities subject to periodic renewal. Ifrenewal; however, a city elected not to renew the franchise agreement, it could seek alternative means for its citizens to access electric power, or gas, 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 alternatives.

available.
ENVIRONMENTAL MATTERS

Environmental
SPS’Environmental Regulation
Our facilities are regulated by federal and state environmental agencies. These 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 all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. SPS’
Our facilities have been designed and constructed to operate in compliance with applicable environmental standards.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 upon SPS’ operations. See Notes 10have.
We may be required to incur capital expenditures in the future for remediation of MGP and 11 to the financial statements for further discussion.

other sites if it is determined that prior compliance efforts are not sufficient.
There are significant present and future environmental regulations to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change.GHGs. SPS has undertaken a number ofnumerous initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals.


If these future environmental regulations do not provide credit for thetake into consideration investments we have already made to reduce GHG emissions, or if they require additional initiatives or emission reductions then their requirements wouldare 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 imposerequire 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 substantial costs.investment, even in plants slated for retirement. SPS believes, based on prior state commission practice, it would recover 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

Employees
As of Dec. 31, 2017,2019, SPS had 1,1691,158 full-time employees and oneno part-time employee,employees, of which 791779 were covered under collective-bargaining agreements. See Note 7 to the financial statements for further discussion.

Item 1A — Risk Factors

ITEM 1A — RISK FACTORS
Xcel Energy, which includes SPS, is subject to a variety of risks, many of which are beyond our control. Important risksRisks that may adversely affect the business, financial condition, and results of operations or cash flows are further described below. These risks should be carefully considered together with the other information set forth in this report and in future reports that Xcel Energy files with the SEC.

Oversight of Risk and Related Processes

A key accountability of theThe Board of Directors is responsible for the oversight of material risk and our Board of Directors employsmaintaining an effective process for doing so.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. Management broadly considers our business, the utility industry, the domesticIdentification and global economies and the environment when identifying, assessing, managing and mitigating risk. Identification andrisk analysis occurs formally through a key risk assessment process conducted by senior management, the financial disclosure process, the hazard risk management process andprocedures, internal auditingaudit and compliance with financial and operational controls.
Management also identifies and analyzes risk through itsthe business planning process, and development of goals and establishment of key performance indicators, which include riskincluding identification to determineof barriers to implementing SPS’our strategy. The business planning process also identifies areas in which there is a potential for a business arealikelihood and mitigating factors to takeprevent the assumption of inappropriate risk to meet goals, and determines how to prevent inappropriate risk-taking.


At a threshold level, SPS has developed a robust compliance program and promotes a culture of compliance, including tone at the top, which mitigates risk. The process for risk mitigation includes adherence to our code of conduct and other compliance policies, operation of formal risk management structures and groups and overall business management to mitigate the risks inherent in the implementation of strategy. Building on this culture of compliance, management further mitigates risks through operation of formal risk management structures and groups, including management councils, risk committees and the services of internal corporate areas such as internal audit, the corporate controller and legal services.

goals.
Management communicates regularly with the Board of Directors and key stakeholdersits sole stockholder regarding risk. Senior management presents and communicates a periodic risk assessment of key risks to the Board of Directors. The presentation and the discussion of the key risks provides the Board of Directors, withproviding information on the risks that management believes are material, including the earningsfinancial impact, timing, likelihood and controllability. Management also provides information to themitigating factors. The Board of Directors in presentationsregularly reviews management’s key risk assessments, which includes areas of existing and communications over the course of the year.future financial, operational and security risks.

Overall, the Board of Directors approaches oversight, management and mitigation of risk asis an integral and continuous part of itsthe Board of Directors’ governance of SPS. Processes are in place to ensure appropriate risk oversight, as well as identification and consideration of new risks. The Board of Directors regularly reviews management’s key risk assessment informed by these processes, and analyzes areas of existing and future risks and opportunities.

Risks Associated with Our Business

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 past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. These laws and regulations require us to obtain permits, licenses, and other approvals and to comply with a wide variety of environmental requirements including those for protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archaeological and historical resources). Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, shift generation to lower-emitting, but potentially more costly facilities, install pollution control equipment at our facilities, clean up spills and other contamination and correct environmental hazards. Environmental regulations may also lead to shutdown of existing facilities, either due to the difficulty in assuring compliance or that the costs of compliance makes operation of the units no longer economical. Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us. 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 certain other parties, caused environmental contamination.

We are also subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. Failure to meet the requirements of these mandates may result in fines or penalties, which could have a material effect on our results of operations. 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 or other environmental requirements, it could have a material effect on our results of operations, financial position or cash flows.

In addition, existing environmental laws or regulations may be revised, and new laws or regulations may be adopted or become applicable to us, including but not limited to, regulation of mercury, NOx, SO2, CO2 and other GHGs, particulates, cooling water intakes, water discharges and ash management. 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 from climate change can include changes in weather conditions, changes in precipitation and extreme weather events.


Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. 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 additional generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may result in decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions. Weather conditions could also have an impact on our revenues. We buy and sell electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand may raise electricity prices, which would increase the cost of energy we provide to our customers.

Severe weather impacts our service territories, primarily when thunderstorms and associated flooding, tornadoes, wildfires and snow or ice storms occur. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Changes in precipitation resulting in droughts or water shortages, whether caused by climate change or otherwise, could adversely affect our operations, principally our fossil generating units. A negative impact to water supplies due to long-term drought or water depletion conditions could adversely impact our ability to provide electricity to customers, as well as increase the price they pay for energy. We may not recover all costs related to mitigating these physical and financial risks.

Climate change may impact a region’s economic health, which could impact our revenues. Our financial performance is tied to the health of the regional economies we serve. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHGor additional environmental regulation 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.

Financial Risks

Our profitability depends in part on our ability to recover costs from our customers and there may be changes in circumstances or in the regulatory environment that impair our ability to recover costs from our customers.

We are subject to comprehensive regulation by federal and state utility regulatory agencies. The state utility commissions regulate many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that we can charge customers. The FERC has jurisdiction, among other things, over wholesale rates for electric transmission service and the sale of electric energy in interstate commerce.

The profitability of our operations is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment. We provide service at rates approved by one or more regulatory commissions. These 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 mechanisms approved in each jurisdiction. Thus, the rates we are allowed to charge may or may not match our costs at any given time. While rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital, in a continued low interest rate environment there has been pressure pushing down ROE. There can also be no assurance that the applicable regulatory commission will judge all of our costs to have been prudent, which could result in cost disallowances, or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of such costs. Changes in the long-term cost-effectiveness or changes to the operating conditions of our assets may result in early retirements and while regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs leaving all or a portion of these asset costs stranded. Higher than expected inflation may increase costs of construction and operations. Rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers. Furthermore, there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers, or these factors could cause us to exceed commitments made regarding cost caps and result in less than full recovery. Overall, management currently believes prudently incurred costs are generally recoverable given the existing regulatory mechanisms in place.

Adverse regulatory rulings or the imposition of additional regulations could have an adverse impact on our results of operations and hence could materially and adversely 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 any of our current ratings will remain in effect for any given period of time, or that a rating will not be lowered or withdrawn entirely by a rating agency. Significant events including a major disallowance of costs, significantly lower returns on equity or equity ratios or impacts of tax policy changes, among others, 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 certain procurement and derivative contracts that require the 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. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital markets are global in nature and are impacted by numerous issues and events throughout the world economy. Capital market disruption events, and resulting broad financial market distress could prevent us from issuing short term commercial paper, issuing new securities or cause us to issue securities with less than ideal 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. Changes in interest rates may also impact the fair value of the debt securities in the master pension trust, as well as our ability to earn a return on short-term investments of excess cash.

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/or breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we could incur losses.

We may at times have direct credit exposure in our short-term wholesale and commodity trading activity to various 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, MISO and ERCOT, in which any credit losses are socialized to all market participants.

We do have additional indirect credit exposures to various domestic and foreign financial institutions in the form of letters of credit provided as security by power suppliers under various long-term physical purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below the designated investment grade rating stipulated in the underlying long-term purchased power contracts, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in technical default under the contract, which would enable us to exercise our contractual rights.

Increasing costs associated with our defined benefit retirement plans and other employee benefits may adversely affect our results of operations, financial position or liquidity.

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, including mortality tables, have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock and bond market performance, changes in interest rates and changes in governmental regulations. In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans with modifications that allowed additional flexibility in the timing of contributions. 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 retirements or employees leaving SPS could trigger settlement accounting and could require SPS to recognize material incremental pension expense related to unrecognized plan losses in the year these liabilities are paid.


Increasing costs associated with health care plans may adversely affect our results of operations.

Our self-insured costs of health care benefits for eligible employees have increased in recent years. Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our operating results, financial position and liquidity. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. Changes in industry standards utilized by management in key assumptions (e.g., mortality tables) could have a significant impact on future liabilities and benefit costs. Legislation related to health care could also significantly change our benefit programs and costs.

Federal tax law may significantly impact our business.

SPS collects through regulated rates its estimated federal, state and local tax payments. There are a number of provisions in federal tax law designed to incentivize capital investments which have benefited our customers by keeping our utility subsidiaries’ rates lower than rates calculated without such provisions. Examples include the use of accelerated depreciation for most of our capital investments, PTCs for wind energy, ITCs for solar energy and R&E tax credits and deductions. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Changes to tax depreciable lives and the value of various tax credits could change the economics of resources and our resource selections. While regulation allows us to incorporate changes in tax law into the rate-setting process, there could be timing delays before regulated rates provide for realization of the tax changes in revenues. In addition, certain IRS tax policies such as the requirement to utilize normalization may impact our ability to economically deliver certain types of resources relative to market prices.

Operational Risks

Our natural gas and 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 and distribution activities include a variety of inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems, which could cause substantial financial losses.problems. Our electric generation, transmission and distribution activities also include inherent hazards and operating risks such as contact, fire and widespread outages which could cause substantial financial losses. In addition, these natural gas and electricoutages. These risks could result in loss of human life, significant property damage, to property, environmental pollution, impairment of our operations and substantial losses to us.financial losses. We maintain insurance against some, but not all, of these risks and losses.

The occurrence of any of these events, if not fully covered by insurance, could have a material effect on our financial position andcondition, results of operations. Foroperations and cash flows.
Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas transmission lines located near populated areas,infrastructure could result in significant costs. The PHMSA is responsible for administering the levelDepartment of potential damages resulting from these risks is greater.

Additionally, forTransportation’s national regulatory program to assure the safe transportation of natural gas, the operating orpetroleum and other costs that may be requiredhazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in order to comply with potential new regulations, including the Pipeline Safety Act, could be significant. The Pipeline Safety Act requires verificationdesign, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas.infrastructure. We have programs in place to comply with the Pipeline Safety ActPHMSA regulations and for systematicsystematically monitor and renew infrastructure monitoring and renewal over time. Atime, however, a significant incident or material finding of non-compliance could increase regulatory scrutiny and 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 long-lived and are planned to be used for decades. Transmission and generation investments typically have long lead times and therefore 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 over the planning horizon 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, public policy has driven increases in appliance and lightingenergy efficiency, and energy efficient buildings, wider adoption andof lower cost of renewable generation, and distributed generation including community solar gardens and customer-sited solar, shifts away from coal generation to decrease CO2carbon emissions and increasing use of natural gas in electric generation driven by lower natural gas prices. Over time, customerCustomer 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 the costs and investments. These changes also introduce additional uncertainty into long-term planning

Changing customer expectations and technologies are requiring significant investments in advanced grid infrastructure, which gives riseincreases exposure to a risk that thetechnology 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 growthchanges in customer demand may not coincide and that thewhile customer preference for the types of additionsresource generation may change, from planningwhich introduces further uncertainty into long-term planning. Additionally, multiple states may not agree as to execution. In addition, wethe appropriate resource mix, which may lead to costs to comply with one jurisdiction that are alsonot recoverable across all jurisdictions served by the same assets.
We are subject to longer-term availability of the natural resource 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.
The resource plans reviewed and approved by our state regulators assume continuation of the traditional utility cost of service model under which utility costs are recovered from customers as they receive the benefit of service. SPS is engaged in significant and ongoing infrastructure investment programs to accommodate renewable distributed generation and to maintain high system reliability. Changing customer expectations and changing technologies are requiring significant investments in advanced grid infrastructure. This also increases the exposure to potential outdating of technologies and the resultant risks. SPS is also investing in renewable and natural gas-fired generation to reduce our CO2 emissions profile. The inability of coal mining companies to attract capital could disrupt longer-term supplies. Early plant retirements that may result from these changes could expose us to premature financial obligations, which could result in less than full recovery of all remaining costs. Both decreasing use per customer driven by appliance and lighting efficiency and the availability of cost-effective distributed generation puts downward pressure on load growth. This could lead to under recovery of costs, excess resources to meet customer demand and increases in electric rates. Finally, multiple states served by a single system may not agree as to the appropriate resource mix and the differing views may lead to costs incurred to comply with one jurisdiction that are not recoverable across all of the jurisdictions served by the same assets.

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, in which we operate, emission allowances and/or renewable energy creditsRECs are also needed to comply with various statutes and commission rulings associated with energy transactions.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 (mark-to-market accounting). Actual settlementsbasis. 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.

If
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 encounter market supply shortageswill 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 suppliers are otherwise unableresults of operations and materially affect our ability to meet theirour financial obligations, including debt payments.
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual obligations, werelationships.
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 be unable to fulfill our contractual obligations to our customers at previously anticipated costs. Therefore, a significant disruption could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Any significantly higher energy or fuel costs relative to corresponding sales commitments could have a negative impact on 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 economic losses. Potential market supply shortages may not be fully resolved through alternative supply sourcesthe methodologies used by the various rating agencies. Any downgrade could lead to higher borrowing costs and may cause short-term disruptions incould impact our ability to provide electric servicesaccess 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 customers. The impact of these costability to fund our operations. Capital market disruption and reliability issues dependsfinancial 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 conditionsresults.
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 generation fuels mix, availabilitySPP, PJM Interconnection, LLC, Midcontinent Independent System Operator, Inc. and Electric Reliability Council of water for cooling, availabilityTexas, in which any credit losses are socialized to all market participants.
We have additional indirect credit exposure to financial institutions in the form of fuel transportation including rail shipmentsletters of coal, electric generation capacity, transmission, natural gas pipeline capacity, etc. Failurecredit 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 provide service duedrop below investment grade, the supplier would need to disruptionsreplace that security with an acceptable substitute. If the security were not replaced, the party could also resultbe in fines, penalties or cost disallowances throughdefault under the regulatory process.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 Xcel Energy Inc. were to become obligated to make payments under various guarantees and bond indemnities or to fund its other contingent liabilities, or if either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s credit rating below investment grade, Xcel Energy Inc. may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy part or potentially all of these exposures. 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, 2017,2019, Xcel Energy Inc. and its utility subsidiaries had approximately $14.5$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, 2017,2019, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $19$2.0 million and immaterial exposure. Xcel Energy also had additional guarantees of $53$60.4 million at Dec. 31, 20172019 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 arehave 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 wholly owned subsidiarysignificant 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 Xcel Energy Inc. Xcel Energy Inc. can exercise substantial control over our dividend policy and business and operations and may exercise that controla significant percentage of pension plan liabilities in a manner thatsingle 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 be perceived to beadversely affect our results of operations.
Increasing levels of large individual health care claims and overall health care claims could have an adverse toimpact on our interests.results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs.

All
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 membersregional 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 Boardoperating systems (or on a neighboring system).
The recent coronavirus outbreak in China is an example of Directors,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 manyinformation 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 executive officers,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 officersunable to quantify the potential impact of Xcel Energy Inc. Our Board makes determinations with respectcyber security threats or subsequent related actions. Cyber security incidents and regulatory action could result in a material decrease in revenues and may causesignificant 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 a number of significant corporate events,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 the paymentasset failure or unauthorized access to assets or information. A failure or breach of our dividends.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.


We
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 paid quarterly dividends to Xcel Energy Inc. In 2017, 2016generated less revenues and 2015 we paid $109 million, $85 millionincome when weather conditions are milder in the winter and $101 millioncooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’soperations, or 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 Item 5 for further discussion on dividend limitations.flows.

Public Policy Risks

We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.

Increased public awareness and concern regarding climate change may result in more state, regional and/or federal requirements to reduce or mitigate the effects of GHGs. Legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk as our electric generating 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. International agreements could have an impact to the extent they lead to future federal or state regulations.


In 2015, the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries (“nationally determined contributions”), with a goal of holding the increase in global average temperature to below 2o Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5o Celsius. If implemented, the Paris Agreement could result in future additional GHG reductions in the United States. On June 21, 2017, President Trump announced that the U.S. would withdraw from the Paris Agreement. Such a withdrawal, under terms of the Agreement, becomes effective in four years. Many state and local government entities, however, have indicated that they intend to pursue GHG mitigation with a goal of achieving the GHG reductions in the United States anticipated by the Paris Agreement.

We have been, and in the future may be subject to climate change lawsuits. An adverse outcome in any of these cases could require substantial capital expenditures and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expendituressignificant and could affect results of operations, financial condition or cash flows and financial condition if such costs are not recovered through regulated rates.

SomeAlthough the United States has not adopted any international or federal GHG emission reduction targets, many states and localities have indicated a desire tomay continue to pursue climate policies even in the absence of federal mandates. All of theThe steps that 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 underbeing discussed, the CPP or the Paris Agreement, repeallack of these policies wouldfederal action does not adversely impact thosethese state-endorsed actions and plans.

Whether under state or federal programs, an important factor is our ability to recover the costs incurred to comply with any regulatory requirements in a timely manner. 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.

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 now impose penalties of up to $1.2$1.3 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. Under statute, the FERC can adjust penalties for inflation. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties by regional entities,penalties. Also, the NERC or the FERC for violations. Additionally, the PHMSA, the Occupational Safety and Health Administration and other federal agencies also have penalty authority.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 in the event of non-compliance.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 financial results.cash flows.

Macroeconomic
Environmental Risks

We are subject to environmental laws and regulations, with which compliance could be difficult and costly.
Economic conditions impactWe are subject to environmental laws and regulations that affect many aspects of our business.

Our operations, are affected by local, nationalincluding air emissions, water quality, wastewater discharges and worldwide economic conditions. Growth in our customer base is correlatedthe 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 economic conditions. SPS serves a large numbervariety of petrochemical extractionenvironmental requirements. Environmental laws and processing businesses in Texasregulations 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 New Mexico. While the number of customers is growing, sales growth is relatively modest due to depressed oil commodity prices. Instability in the financial marketsother contamination and correct environmental hazards. Environmental regulations may also may affect the cost of capital and our ability to raise capital, which is discussed in the capital market risk factor section above.

Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay timely, increase customer bankruptcies, and may lead to increased bad debt.

Further, worldwide economic activity has an impact on the demand for basic commodities needed for utility infrastructure, such as steel, copper, aluminum, etc., whichshutdown of existing facilities. Failure to meet requirements of environmental mandates may impact our ability to acquire sufficient supplies. We operateresult in a capital intensive industry, and federal policy on trade could significantly impact the costs of the materials we use.fines or penalties. We may be at risk for higher than anticipated inflation bothrequired 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 respect to our own workforce, as well as our materialsclean energy, renewable energy and labor that we contract for with others. There may be delays before these higher costs can be recovered in rates.


Our operations could be impacted by war, acts of terrorism, threats of terrorism or disruptions in normal operating conditions due to localized or regional events.

Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any such 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 and results of operations. The potential for terrorism has subjected our operations to increased risks andenergy conservation offerings. It could have a material effect on our business. We have alreadyresults 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 increased costs for security and capital expenditures in response to these risks. In addition, we may experience additional capital and operating costs to implement security for our plants, such as additional physical plant security and additional security personnel. We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection. In addition, we may experience additional capital and operating costs to comply with the NERC critical infrastructure protection standards as theyrequirements.
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 implementedsubject to physical and clarified.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.
The insurance industry has also beenOur customers’ energy needs vary with weather. To the extent weather conditions are affected by these eventsclimate 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 insurancegoods 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 decrease. In addition,raise electricity prices, increasing the insurancecost of energy we are ableprovide to obtain may have higher deductibles, higher premiums and more restrictive policy terms.our customers.

A disruption
To the extent the frequency of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources,extreme weather events increases, this could negativelyincrease our cost of providing service. Periods of extreme temperatures could impact our business, as well asability to meet demand. Changes in precipitation resulting in droughts or water shortages could adversely affect our brand and reputation. Becauseoperations. Drought conditions also contribute to the increase in wildfire risk from our electric generation the transmission systems and local natural gas distribution companies 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 or an event (such as severe storm, severe temperature extremes, wildfires, solar storms, generator or transmission facility outage, breakdown or failure of equipment, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or any disruption of work force such as may be caused by flu or other epidemic) within our operating systems or on a neighboring system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material impact on our financial condition and results.

The degree to which we are able to maintain day-to-day operations in response to unforeseen events will in part determine the financial impact of certain events on our financial condition and results. It is difficult to predict the magnitude of such events and associated impacts.

A cyber incident or cyber security breach could have a material effect on our business.

We operate in an industry that requires the continued operation of sophisticated information technology and 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 the information processed in our systems (such as information about our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error. Our industry has begun to see 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 exposing 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. In addition, such an event would likely receive regulatory scrutiny at both the federal and state level. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. These potential cyber security incidents and corresponding regulatory action could result in a material decrease in revenues and may causesignificant 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 designed 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 the resulting disability, or failures of assets or unauthorized access to assets or information. If our technology systems were to fail or be breached, or those of our third-party service providers, we may be unable to fulfill critical business functions, including effectively maintaining certain internal controls over financial reporting. We are unable to quantify the potential impact of cyber security incidents on our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network monitoring may not be effective given the constant changes to threat vulnerability.

Rising energy prices could negatively impact our business.

Although commodity prices are currently relatively low, if fuel costs increase, customer demand could decline and bad debt expense may rise, which could have a material impact on our results of operations.facilities. While we have fuel clause recovery mechanisms, higher fuel costscarry liability insurance, given an extreme event, if SPS was found to be liable for wildfire damages, amounts that potentially exceed our coverage could significantlynegatively impact our results of operations, if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases could have an impact on ourfinancial condition or cash flows. Low fuelDrought 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 could have a positive impact on sales, though low oilrelated to mitigating these physical and natural prices could negatively impact oil and gas production activities and subsequently our sales volumes and revenue. We are unable to predict future prices or the ultimate impact of such prices on our results of operations or cash flows.

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.

Our operations use third party contractors in addition to employees to perform periodic and on-going work.
We rely on third party contractors with specific qualifications to perform work both for ongoing operations and maintenance and for capital construction. We have contractual arrangements with these contractors which typically include performance standards, progress payments, insurance requirements and security for performance. Cyber security breaches seen in the news have at times exploited third party equipment or software in order to gain access. Poor vendor performance could impact on going operations, restoration operations, our reputation and could introduce financial risk or risks of fines.

risks.
Item 1B — Unresolved Staff Comments

ITEM 1B — UNRESOLVED STAFF COMMENTS
None.


Item 2 —Properties

ITEM 2 —PROPERTIES
Virtually all of the utility plant property of SPS is subject to the lien of its first mortgage bond indenture.

Electric Utility Generating Stations:       
Station, Location and Unit Fuel Installed Summer 2017
Net Dependable
Capability (MW)		 
Steam:       
Cunningham-Hobbs, N.M., 2 Units Natural Gas 1957-1965 254
 
Harrington-Amarillo, Texas, 3 Units Coal 1976-1980 1,018
 
Jones-Lubbock, Texas, 2 Units Natural Gas 1971-1974 486
 
Maddox-Hobbs, N.M., 1 Unit Natural Gas 1967 112
 
Nichols-Amarillo, Texas, 3 Units Natural Gas 1960-1968 457
 
Plant X-Earth, Texas, 4 Units Natural Gas 1952-1964 411
 
Tolk-Muleshoe, Texas, 2 Units Coal 1982-1985 1,067
 
Combustion Turbine:       
Carlsbad-Carlsbad, N.M., 1 Unit Natural Gas 1968 —
 (a)
Cunningham-Hobbs, N.M., 2 Units Natural Gas 1998 212
 
Jones-Lubbock, Texas, 2 Units Natural Gas 2011-2013 336
 
Maddox-Hobbs, N.M., 1 Unit Natural Gas 1963-1976 61
 
    Total 4,414
 


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) Carlsbad Unit 5 was retired on Dec. 31, 2017.

(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, 2017:2019:
Conductor Miles 
345 KV8,5169,566

230 KV9,6089,784

115 KV13,55514,662

Less than 115 KV24,79526,216


SPS had 454452 electric utility transmission and distribution substations at Dec. 31, 2017.2019.





Natural gas utility mains at Dec. 31, 2019:
Miles
Transmission20
Distribution—
Item 3 —Legal Proceedings

ITEM 3 —LEGAL PROCEEDINGS
SPS is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are 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.

Additional Information

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 11 to the financial statements for further discussion of legal claims and environmental proceedings. See Item 1 and Note 10 to the financial statements, Item 1 and Item 7 for a discussion of proceedings involving utility rates and other regulatory matters.

further information.
Item 4 — Mine Safety Disclosures

ITEM 4 — MINE SAFTEY DISCLOSURES
None.


PART II

Item 5 —Marketfor Registrant’s Common Equity, Related Stockholder Matters andIssuer Purchases of Equity Securities

ITEM 5 —MARKETFOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS ANDISSUER PURCHASE OF EQUITY SECURITIES
SPS is a wholly owned subsidiary of Xcel Energy Inc. and there is no market for its common equity securities. SPS has dividend restrictions imposed by FERC rules and state regulatory commissions:

Dividends are subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only.
The most restrictive dividend limitation for SPS is imposed by its state regulatory commissions. SPS’ state regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy Inc. by requiring an equity-to-total capitalization ratio (excluding short-term debt) between 45.0 percent and 55.0 percent. In addition, SPS may not pay a dividend that would cause it to lose its investment grade bond rating. SPS’ equity-to-total capitalization ratio (excluding short-term debt) was 53.8 percent at Dec. 31, 2017 and $542 million in retained earnings was not restricted.

See Note 45 to the financial statements for further discussion of SPS’ dividend policy.

information.
The dividends declared during 20172019 and 20162018 were as follows:
(Thousands of Dollars) 2017 2016
(Millions of Dollars) 2019 2018
First quarter $26,715
 $25,645
 $57.5
 $33.3
Second quarter 25,014
 19,388
 83.4
 30.7
Third quarter 26,166
 27,498
 114.6
 40.0
Fourth quarter 26,753
 30,870
 78.3
 45.4
Item 6 —Selected Financial Data

ITEM 6 —SELECTED FINANCIAL DATA
This is omitted per conditions set forth in general instructions I (1)I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Item 7 —Management’s Discussionand Analysis of Financial Condition and Results of Operations

ITEM 7 —MANAGEMENT’S DISCUSSIONAND 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 ofand the results of operations for the current year as set forth in general instructions I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Non-GAAP Financial Review

Measures
The following discussion and analysis by management focuses on those factors that had a material effect on SPS’includes financial condition, results of operations, and cash flows during the periods presented, or are expected to have a material impactinformation prepared in the future. It should be read in conjunctionaccordance with the accompanying financial statements and the related notes to the financial statements.


Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements, including the TCJA’s impact to SPS and its customers,GAAP, as well as assumptionscertain 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 statements identifiedcompanies’ 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 this documentthese 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 words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would”actual and similar expressions.  Actual results may vary materially.  Forward-looking statements speak only asprojected financial performance and contribution of SPS. For 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 yearyears ended Dec. 31, 2017 (including risk factors listed from time2019 and Dec. 31, 2018, there were no adjustments to time by SPS in reports filedGAAP earnings and therefore GAAP earnings equal ongoing earnings.
Results of Operations
2019 Comparison with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K and Exhibit 99.01 hereto), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: 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; business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth, recovery, trade, fiscal, taxation and environmental policies in areas where SPS has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by SPS; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric market; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability or cost of capital; and employee work force factors.

Results of Operations

2018
SPS’ net income was approximately $159$263.1 million for 2017,2019, compared with net income of approximately $152$213.3 million for 2016. Rate increases in New Mexico2018. 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 a lower ETR wereincome taxes, partially offset by higherincreased interest and depreciation expense and O&M expenses.

expense.
Electric Revenues and Margins

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. The following tables details the electricElectric revenues and margin: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
(Millions of Dollars) 2017 2016
Electric revenues $1,918
 $1,851
Electric fuel and purchased power (1,055) (1,035)
Electric margin $863
 $816

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

Electric Revenues31, 2019:
(Millions of Dollars) 2017 vs. 2016
Retail rate increases (Texas and New Mexico) $62
Wholesale transmission revenue, net of costs 16
Demand revenue 12
Firm wholesale (20)
Estimated impact of weather (7)
Other, net 4
Total increase in electric revenues $67


Electric Margin
(Millions of Dollars) 2017 vs. 2016
Retail rate increases (Texas and New Mexico) $62
Demand revenue 12
Renewable energy credits 7
Firm wholesale (20)
Estimated impact of weather (7)
Fuel handling and procurement (5)
Wholesale transmission revenue, net of costs (3)
Other, net 1
Total increase in electric margin $47

(Millions of Dollars) 2019 vs. 2018
Purchase capacity costs $40.7
Regulatory rate outcomes 24.7
Demand revenue 24.7
Wholesale transmission revenue 13.7
Sales growth 5.9
Non-fuel riders 4.3
Firm wholesale (26.2)
PTC sharing (16.0)
Estimated weather impact (5.2)
Other (net) (5.9)
Total increase in electric margin $60.7
Non-Fuel Operating Expense and Other Items

O&M Expenses— O&M expenses increased $20 million, or 7.5 percent, for 2017 compared with 2016. The increase primarily relates to prior year deferrals associated with the Texas 2016 rate case. The significant changes are summarized in the table below:
(Millions of Dollars) 2017 vs. 2016
Texas 2016 electric rate case cost deferral $16
Electric distribution costs 4
Employee benefits expense 1
Plant generation costs (4)
Other, net 3
Total increase in O&M expenses $20

Depreciation and Amortization — Depreciation and amortization expense increased $31$20.3 million, or 19.4 percent,9.7%, for 20172019 compared with 2016.the prior year. The increase was primarily attributabledue to deferred depreciation expense from the 2016 Texas electric rate caseHale wind farm being placed into service and increased capital investments.

Taxes (Other Than Income Taxes)AFUDC, Equity and Debt— Taxes (other than income taxes)AFUDC increased $6by $11.1 million, or 10.0 percent,39.6% for 20172019 compared with 2016.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 property taxes in Texas.debt levels to fund capital investments.

Income Taxes — Income tax expense decreased $14$13.3 million for 20172019 compared with 2016.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 income tax expense2019 was primarily due to the estimated one-time, non-cash, income tax benefit recognizeditems referenced above.
2018 Comparison with 2017
A discussion of changes in SPS’ results of operations and liquidity and capital resources from the fourth quarter relatedyear 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 TCJA (see Note 6)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 net tax benefit related to the resolutionpart of, appeals/audits in 2017. The ETR was 30.1 percent for 2017, compared with 35.1 percent for 2016. The lower ETR in 2017 was primarily due to the adjustments referenced above.

this Annual Report on Form 10-K.
Item 7A —Quantitativeand Qualitative Disclosures About Market Risk






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
MechanismUtility ServiceAmount Requested (in millions)
Filing
Date
ApprovalAdditional Information
SPS (NMPRC)
Rate CaseElectric$51July 2019Pending
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.






ITEM 7A —QUANTITATIVEAND 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 98 to the financial statements for further discussion of market risks associated with derivatives.

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, when necessary, 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 nonperformancenon-performance risk.


Though no material non-performance risk currently exists with the counterparties to SPS’ commodity derivative contracts, distress in the financial markets may in the future impact that risk to the extent it impacts those counterparties. Distress in the financial markets may also impact counterparty risk, the fair value of the securities in the master pension trust, as well asfund, and SPS’ ability to earn a return on short-term investments of excess cash.investments.

Commodity Price Risk — SPS is exposed to commodity price risk in its electric operations. Commodity price risk is managed by entering into short-long- and long-termshort-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 within each rate-regulated operation 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, which is made up of management personnel not directly involved in the activities governed by this policy.committee.

Interest Rate Risk — SPS is subject to the risk of fluctuating interest rates in the normal course of business.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.

At Dec. 31, 2017, aA 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 at Dec. 31, 2016 a 100-basis-point change$0.4 million in the benchmark rate on SPS’ variable rate debt would impact annual pretax impact interest expense by approximately $0.5 million. 2018, respectively.
See Note 98 to the financial statements for a discussion of SPS’ interest rate derivatives.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, 2017,2019, a 10 percent10% increase in commodity prices would have resulted in an increase in credit exposure of $1.3$1.2 million, while a decrease in prices of 10 percent10% would have resulted in a decrease in credit exposure of $1.3$1.2 million. At Dec. 31, 2016,2018, a 10 percent10% increase in commodity prices would have resulted in an increase in credit exposure of $0.3$1.5 million, while a decrease in prices of 10 percent10% would have resulted in a decrease in credit exposure of $0.3$1.5 million.

SPS conducts standard credit reviews for all counterparties. SPScounterparties and employs additional credit risk control mechanisms when appropriate,controls, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures.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 follows accountinguses derivative contracts such as futures, forwards, interest rate swaps, options and disclosure guidance onFTRs 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 measurements that contains a hierarchy for inputs used in measuring fair value and requires disclosure of the observability of the inputs used in these measurements. See Note 9 to the financial statements for further discussion of the fair value hierarchy and the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.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 set forth in the contracts.transactions. Given this assessment and 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, 2017. SPS also assesses the impact of its own2019.
Adjustments to fair value for credit risk when determining the fair value 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 to the fair value of commodity derivative liabilities at Dec. 31, 2017.


Commodity derivative assets and liabilities assigned to Level 3 consist of FTRs. Determining the fair value of FTRs requires numerous management forecasts that vary in observability, including various forward commodity prices, retail and wholesale demand, generation and resulting transmission system congestion. Given the limited observability of management’s forecasts for several of these inputs, these instruments have been assigned a Level 3. Level 3 commodity derivatives assets and liabilities included $14.7 million and $2.0 million of estimated fair values, respectively, for FTRs held at Dec. 31, 2017.

2019.
Item 8 — Financial Statements and Supplementary Data

ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See 15-1 in Part IV for an index of financial statements included herein.

See Note 1513 to the financial statements for summarized quarterly financial data.further information.



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.

In 2016, SPS implemented the general ledger modules of a new enterprise resource planning system. SPS initiated and implemented additional work management systems modules in 2017. SPS does not believe this implementation had an adverse effect on its internal control over financial reporting.

SPS management assessed the effectiveness of SPS’ internal control over financial reporting as of Dec. 31, 2017.2019. 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, 2017,2019, 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, and Chief Executive Officer and Director Executive Vice President, Chief Financial Officer and Director
Feb. 23, 201821, 2020 Feb. 23, 201821, 2020



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and Board of Directors and Stockholder 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, 20172019 and 2016,2018, the related statements of income, comprehensive income, cash flows and common stockholder’sstockholder's equity, for each of the three years in the period ended December 31, 2017,2019, 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, 20172019 and 2016,2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2019, 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 23, 201821, 2020
We have served as the Company’s auditor since 2002.

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



SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF INCOME
(amounts in thousands of dollars)millions)
Year Ended Dec. 31 Year Ended Dec. 31
2017 2016 2015 2019 2018 2017
           
Operating revenues$1,918,000
 $1,850,959
 $1,787,218
 $1,825.8
 $1,933.2
 $1,918.0
           
Operating expenses           
Electric fuel and purchased power1,055,333
 1,034,950
 1,001,083
 875.4
 1,043.5
 1,055.3
Operating and maintenance expenses289,555
 269,471
 289,856
 285.3
 282.7
 285.4
Demand side management program expenses15,525
 16,028
 13,365
 16.6
 17.7
 15.5
Depreciation and amortization193,915
 162,429
 150,913
 229.9
 209.6
 193.9
Taxes (other than income taxes)66,863
 60,800
 57,536
 71.9
 68.0
 67.0
Total operating expenses1,621,191
 1,543,678
 1,512,753
 1,479.1
 1,621.5
 1,617.1
           
Operating income296,809
 307,281
 274,465
 346.7
 311.7
 300.9
           
Other income (expense), net2,359
 91
 (6) 2.2
 (3.0) (1.8)
Allowance for funds used during construction — equity9,310
 9,981
 7,378
 26.8
 19.1
 9.3
           
Interest charges and financing costs           
Interest charges — includes other financing costs of
$2,491, $3,055 and $3,158, respectively
86,233
 88,671
 84,040
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(5,384) (5,589) (4,491) (12.3) (8.9) (5.4)
Total interest charges and financing costs80,849
 83,082
 79,549
 87.0
 75.6
 80.8
           
Income before income taxes227,629
 234,271
 202,288
 288.7
 252.2
 227.6
Income taxes68,416
 82,114
 75,025
 25.6
 38.9
 68.4
Net income$159,213
 $152,157
 $127,263
 $263.1
 $213.3
 $159.2
See Notes to Financial Statements



SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF COMPREHENSIVE INCOME
(amounts in thousands of dollars)millions)
 Year Ended Dec. 31
 2017 2016 2015
Net income$159,213
 $152,157
 $127,263
      
Other comprehensive income (loss)     
      
Pension and retiree medical benefits:     
Amortization of losses (gains) included in net periodic benefit cost, net of tax of
$26, $(84), and $(260), respectively
44
 (148) (464)
      
Derivative instruments:     
Reclassification of losses to net income, net of tax of
$24, $80, and $97, respectively
39
 139
 172
      
Other comprehensive income (loss)83
 (9) (292)
Comprehensive income$159,296
 $152,148
 $126,971

 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



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

Year Ended Dec. 31Year Ended Dec. 31
2017 2016 20152019 2018 2017
Operating activities          
Net income$159,213
 $152,157
 $127,263
$263.1
 $213.3
 $159.2
Adjustments to reconcile net income to cash provided by operating activities:          
Depreciation and amortization193,870
 162,957
 153,241
232.2
 210.0
 193.9
Demand side management program amortization1,673
 1,673
 1,673
—
 1.7
 1.7
Deferred income taxes126,465
 122,983
 62,836
29.0
 22.1
 126.5
Amortization of investment tax credits(133) (213) (213)
Allowance for equity funds used during construction(9,310) (9,981) (7,378)(26.8) (19.1) (9.3)
Provision for bad debts5,091
 6,066
 4,655
5.7
 4.9
 5.1
Net derivative losses63
 217
 268
—
 0.1
 0.1
Other(28) 122
 (3,827)
Changes in operating assets and liabilities:          
Accounts receivable(10,392) (8,868) (3,291)(9.0) (19.5) (10.4)
Accrued unbilled revenues(10,386) (15,637) 25,506
(0.6) 15.3
 (10.4)
Inventories(1,928) (959) 5,686
(20.5) (16.0) (1.9)
Prepayments and other4,267
 22,651
 (24,712)2.8
 0.5
 4.3
Accounts payable11,836
 13,776
 (24,570)(8.5) (6.6) 11.8
Net regulatory assets and liabilities38,137
 (55,689) 26,452
13.8
 38.2
 38.1
Other current liabilities3,427
 5,156
 (30,762)5.8
 11.6
 3.4
Pension and other employee benefit obligations(21,679) (15,276) (9,405)(17.7) (16.0) (21.7)
Change in other noncurrent assets(1,206) (200) 2,352
Change in other noncurrent liabilities(18,524) 6,748
 8,974
Other, net3.5
 5.8
 (19.9)
Net cash provided by operating activities470,456
 387,683
 314,748
472.8
 446.3
 470.5
          
Investing activities          
Utility capital/construction expenditures(559,865) (512,522) (599,511)(844.4) (1,020.9) (550.6)
Allowance for equity funds used during construction9,310
 9,981
 7,378
Proceeds from insurance recoveries—
 3,901
 —
Investments in utility money pool arrangement(142,000) (75,000) (92,000)(133.0) (285.0) (142.0)
Receipts from utility money pool arrangement77,000
 75,000
 92,000
133.0
 350.0
 77.0
Other(493) (1,174) 3,136
—
 —
 (0.5)
Net cash used in investing activities(616,048) (499,814) (588,997)(844.4) (955.9) (616.1)
          
Financing activities          
(Repayment of) proceeds from short-term borrowings, net(50,000) 35,000
 (22,000)
(Repayments of) proceeds from short-term borrowings, net(42.0) 42.0
 (50.0)
Proceeds from issuance of long-term debt442,338
 295,985
 198,496
292.2
 295.0
 442.3
Repayment of long-term debt, including reacquisition premiums(271,613) (200,000) —
—
 —
 (271.6)
Borrowings under utility money pool arrangement335,000
 636,500
 579,700
296.0
 595.0
 335.0
Repayments under utility money pool arrangement(335,000) (636,500) (595,700)(296.0) (595.0) (335.0)
Capital contributions from parent143,659
 66,225
 214,535
426.3
 336.8
 143.7
Dividends paid to parent(108,765) (85,069) (100,544)(332.7) (131.0) (108.8)
Net cash provided by financing activities155,619
 112,141
 274,487
343.8
 542.8
 155.6
          
Net change in cash and cash equivalents10,027
 10
 238
Cash and cash equivalents at beginning of year844
 834
 596
Cash and cash equivalents at end of year$10,871
 $844
 $834
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)$(75,978) $(78,236) $(76,474)$(83.6) $(71.2) $(76.0)
Cash received (paid) for income taxes, net41,548
 61,813
 (23,987)11.9
 (10.6) 41.5
Supplemental disclosure of non-cash investing transactions:          
Property, plant and equipment additions in accounts payable$77,563
 $43,074
 $44,335
$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

SOUTHWESTERN PUBLIC SERVICE CO.
BALANCE SHEETS
(amounts in thousands,millions, except share and per share data)
 Dec. 31 Dec. 31
 2017 2016 2019 2018
Assets        
Current assets        
Cash and cash equivalents $10,871
 $844
 $16.2
 $44.0
Accounts receivable, net 79,581
 74,190
 92.7
 90.7
Accounts receivable from affiliates 1,297
 949
 4.2
 10.5
Investments in money pool arrangements 65,000
 —
 —
 —
Accrued unbilled revenues 129,804
 119,418
 115.1
 114.5
Inventories 40,433
 38,505
 31.0
 33.9
Regulatory assets 31,538
 38,721
 20.0
 26.0
Derivative instruments 15,882
 5,114
 15.0
 17.8
Prepaid taxes 15,025
 21,779
 0.8
 14.2
Prepayments and other 10,341
 7,855
 21.4
 10.7
Total current assets 399,772
 307,375
 316.4
 362.3
        
Property, plant and equipment, net 5,095,609
 4,695,819
 6,631.6
 5,946.4
        
Other assets        
Regulatory assets 362,943
 346,683
 364.0
 366.2
Derivative instruments 18,954
 22,113
 12.6
 15.8
Operating lease right-of-use assets 522.4
 —
Other 11,266
 7,477
 3.9
 5.1
Total other assets 393,163
 376,273
 902.9
 387.1
Total assets $5,888,544
 $5,379,467
 $7,850.9
 $6,695.8
        
Liabilities and Equity        
Current liabilities        
Short-term debt $—
 $50,000
 $—
 $42.0
Accounts payable 211,756
 176,157
 168.1
 191.8
Accounts payable to affiliates 22,577
 14,414
 20.4
 19.9
Regulatory liabilities 68,835
 41,577
 118.1
 85.8
Taxes accrued 35,243
 39,742
 40.4
 41.6
Accrued interest 23,275
 19,162
 26.2
 25.8
Dividends payable 26,753
 30,870
 46.3
 45.2
Derivative instruments 3,565
 3,565
 3.7
 3.6
Operating lease liabilities 26.9
 —
Other 29,641
 29,703
 30.7
 28.3
Total current liabilities 421,645
 405,190
 480.8
 484.0
        
Deferred credits and other liabilities        
Deferred income taxes 574,906
 989,137
 671.8
 619.1
Regulatory liabilities 784,564
 233,454
 732.3
 780.9
Asset retirement obligations 28,524
 28,663
 77.3
 32.4
Derivative instruments 19,949
 23,513
 12.8
 16.4
Pension and employee benefit obligations 90,266
 107,872
 67.0
 92.4
Operating lease liabilities 495.3
 —
Other 8,386
 24,084
 9.4
 7.9
Total deferred credits and other liabilities 1,506,595
 1,406,723
 2,065.9
 1,549.1
        
Commitments and contingencies 

 

 


 


Capitalization        
Long-term debt 1,829,941
 1,635,858
 2,419.7
 2,126.1
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2017 and 2016, respectively —
 —
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2019 and 2018, respectively —
 —
Additional paid in capital 1,590,242
 1,446,223
 2,350.9
 1,932.3
Retained earnings 541,588
 486,763
 535.0
 605.7
Accumulated other comprehensive loss (1,467) (1,290) (1.4) (1.4)
Total common stockholder’s equity 2,130,363
 1,931,696
 2,884.5
 2,536.6
Total liabilities and equity $5,888,544
 $5,379,467
 $7,850.9
 $6,695.8
See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
(amounts in thousands of dollars,millions, except share data)
Common Stock Issued   
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
Common
Stockholder’s
Equity
Common Stock Issued   
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
Common
Stockholder’s
Equity
Shares Par Value 
Additional
Paid In
Capital
 
Retained
Earnings
 Shares Par Value 
Additional
Paid In
Capital
 
Retained
Earnings
 
Balance at Dec. 31, 2014100
 $—
 $1,165,463
 $395,998
 $(989) $1,560,472
Balance at Dec. 31, 2016100
 $—
 $1,446.2
 $486.7
 $(1.3) $1,931.6
           
Net income      127,263
   127,263
      159.2
   159.2
Other comprehensive loss        (292) (292)        0.1
 0.1
Common dividends declared to parent      (85,254)   (85,254)      (104.6)   (104.6)
Contribution of capital by parent    205,760
     205,760
    144.0
     144.0
Balance at Dec. 31, 2015100
 $—
 $1,371,223
 $438,007
 $(1,281) $1,807,949
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      152,157
   152,157
      213.3
   213.3
Other comprehensive loss        (9) (9)        0.1
 0.1
Common dividends declared to parent      (103,401)   (103,401)      (149.2)   (149.2)
Contribution of capital by parent    75,000
     75,000
    342.1
     342.1
Balance at Dec. 31, 2016100
 $—
 $1,446,223
 $486,763
 $(1,290) $1,931,696
Balance at Dec. 31, 2018100
 $—
 $1,932.3
 $605.7
 $(1.4) $2,536.6
           
Net income      159,213
   159,213
      263.1
   263.1
Other comprehensive income        83
 83
        —
 —
Common dividends declared to parent      (104,648)   (104,648)      (333.8)   (333.8)
Contribution of capital by parent    144,019
     144,019
    418.6
     418.6
Adoption of ASU No. 2018-02      260
 (260) —
Balance at Dec. 31, 2017100
 $—
 $1,590,242
 $541,588
 $(1,467) $2,130,363
Balance at Dec. 31, 2019100
 $—
 $2,350.9
 $535.0
 $(1.4) $2,884.5
See Notes to Financial Statements



SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF CAPITALIZATION
(amounts in thousands of dollars, except share data)
 Dec. 31
 2017 2016
Long-Term Debt   
First Mortgage Bonds, Series due:   
   June 15, 2024, 3.3%$350,000
 $350,000
   Aug. 15, 2041, 4.5%400,000
 400,000
   Aug. 15, 2046, 3.4%300,000
 300,000
   Aug. 15, 2047, 3.7%450,000
 —
Unsecured Senior G Notes, due Dec. 1, 2018, 8.75%—
 250,000
Unsecured Senior C and D Notes, due Oct. 1, 2033, 6%100,000
 100,000
Unsecured Senior F Notes, due Oct. 1, 2036, 6%250,000
 250,000
Unamortized (discount) premium(1,746) 365
Unamortized debt expense(18,313) (14,507)
Total long-term debt$1,829,941
 $1,635,858
    
Common Stockholder’s Equity   
Common stock — 200 shares authorized of $1.00 par value,
100 shares outstanding at Dec. 31, 2017 and 2016, respectively
$—
 $—
Additional paid in capital1,590,242
 1,446,223
Retained earnings541,588
 486,763
Accumulated other comprehensive loss(1,467) (1,290)
Total common stockholder’s equity$2,130,363
 $1,931,696

See Notes to Financial Statements


NOTES TO FINANCIAL STATEMENTS

1.Summary of Significant Accounting Policies

Business and System of AccountsGeneral— SPS is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity.
SPS’ financial statements and disclosures 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, which arecommissions. Certain amounts in the same in all material respects.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.

Variable Interest Entities— SPS evaluates its arrangements and contracts with other entities, including but not limited to, PPAs and fuel contracts, to determine if the other party is a variable interest entity, if SPS has a variable interestevaluated events occurring after Dec. 31, 2019 up to the date of issuance of these financial statements. These statements contain all necessary adjustments and if SPS is the primary beneficiary. SPS follows accounting guidance for variable interest entities which requires consideration of the activitiesdisclosures resulting from that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether SPS is a variable interest entity’s primary beneficiary. See Note 11 for further discussion of variable interest entities.evaluation.

Use of Estimates— In recording transactions and balances resulting from business operations, SPS uses estimates based on the best information available.available in recording transactions and balances resulting from business operations. Estimates are used foron items such items 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. The recordedRecorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisionsRevisions can affect operating results.

Regulatory Accounting— SPS accounts for certain 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 OCI,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 OCI,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 restructuring or other 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’ financial condition, results of operations, financial condition and cash flows.
See Note 124 for further discussioninformation.
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.

Revenue Recognition— Revenuesliabilities related to the sale of energyincome taxes. Deferred tax assets are generally recorded when servicereduced by a valuation allowance if it is renderedmore likely than not that some portion or energy is delivered to customers. However, the determinationall of the energy salesdeferred tax asset will not be realized.
SPS follows the applicable accounting guidance to individual customersmeasure 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 reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the datetechnical merits of the last meter readingposition. Recognition of changes in uncertain tax positions are estimated and the corresponding unbilled revenue is recognized. SPS presents its revenues netreflected as a component of any excise or other fiduciary-type taxes or fees.

income tax expense.
SPS participates in SPP. SPS recognizes sales to both native loadreports interest and other end use customers on a gross basis. Revenues and charges for short-term wholesale sales of excess energy transacted through SPP are recorded on a gross basis in electric revenues and cost of sales. Other revenues and chargespenalties related to participatingincome taxes within the other income and transactinginterest charges in RTOs are recorded on a net basis in costthe statements of sales.income.

Xcel Energy Inc. and its subsidiaries, including SPS, has various rate-adjustment mechanisms in place that provide for the recovery of electric fuel costs and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.


Certain rate rider mechanisms qualify as alternative revenue programs under generally accepted accounting principles. 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, revenue is recognized equal to the revenue requirement, including return on rate base items, for the qualified mechanisms. The mechanisms are revised periodically for differences between the total amount collected under the riders and the revenue recognized, which may increase or decrease the level of revenue collected from customers.

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,files consolidated federal income tax returns as well as residential rebatesconsolidated 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 participationstate income taxes paid by Xcel Energy Inc. in air conditioner interruption and home weatherization.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.
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. Recorded revenues 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.

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 major 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 also includes costs associated with property held for future use. The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate.

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

SPS records depreciation expense related to its plant 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 2.8, 2.72.9% in 2019, 2.9% in 2018 and 2.6 percent for the years ended Dec. 31, 2017, 2016 and 2015, respectively.2.8% in 2017.

Leases — SPS evaluates a variety of contracts for lease classification at inception, including PPAs and rental arrangements for office space, vehicles, and equipment. Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. See Note 113 for further discussion of leases.information.

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 service rates.

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 1110 for further discussion of AROs.information.


Income TaxesBenefit Plans and Other Postretirement Benefits— SPS accountsmaintains pension and postretirement benefit plans for income taxes usingeligible employees. Recognizing the assetcost of providing benefits and liability method, whichmeasuring the projected benefit obligation of these plans requires the recognition of deferred tax assetsmanagement to make various assumptions 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 financialestimates.
Certain unrecognized actuarial gains and taxable income,losses and between the book and tax bases of assets and liabilities. SPS uses the tax 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. Taxunrecognized prior service costs or 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 certaindeferred as regulatory assets and liabilities, related torather than recorded as other comprehensive income, taxes, which are summarized in Note 12.

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. In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations.

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.

SPS reports interest and penalties related to income taxes within the other income and interest charges sections in the statements of income.

Xcel Energy Inc. and its subsidiaries, including SPS, file consolidated federal income tax returns as well as combined or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries which are recorded directly in equity by the subsidiaries based on the relative positive tax liabilities of the subsidiaries.

See Note 6 for further discussion of income taxes.

Types of and Accounting for Derivative Instruments— SPS uses derivative instruments in connection with its utility commodity price and interest rate activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the balance sheets at fair value as derivative instruments. This includes certain instruments used to mitigate market risk for the utility operations including transmission in organized markets. The 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. The 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. For further information on derivatives entered to mitigate market risk associated with transmission in organized markets, see Note 9.

Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective, are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction.

Normal Purchases and Normal Sales — SPS enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales.


SPS evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements. None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation.

See Note 9 for further discussion of SPS’ risk management and derivative activities.information.

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 as a primary input 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 for an identical contract in an active market, 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 7 and 9 for further discussion.

Cash and Cash Equivalents— SPS considers investments in certain instruments, including commercial paper and money market funds, 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.

Inventory— All inventory is recorded at average cost.

RECs — RECs are marketable environmental instruments that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced. SPS acquires RECs from the generation or purchase of renewable power.

When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost. The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. As a result of certain state regulatory orders, SPS reduces recoverable fuel costs for the cost of certain RECs and records that cost as a regulatory asset when the amount is recoverable in future rates.

Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs, related transaction costs, and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.

Emission Allowances — Emission allowances, including the annual SO2 and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees. SPS follows the inventory accounting model for all emission allowances. Sales of emission allowances are included in electric utility operating revenues and the operating activities section of the statements of cash flows.

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, excluding inflationary increases, are recorded based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded 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.


Any futureFuture costs of restoring sites where operation may be extended are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs.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 116 for further discussion of environmental costs.information.

Benefit PlansCash and Other Postretirement BenefitsCash Equivalents — SPS maintainsconsiders 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 benefit plansplan assets published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for eligible employees. Recognizingeach security.
See Notes 8 and 9 for further information.
Derivative Instruments— SPS uses derivative instruments in connection with its utility commodity price and interest rate activities, including forward contracts, futures, swaps and options. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on expected recovery of derivative instrument settlements through fuel and purchased energy cost recovery mechanisms. Interest rate hedging transactions are recorded as a component of interest expense.

Normal Purchases and Normal Sales — SPS enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale.
See Note 8 for further information.
Other Utility Items
AFUDC— AFUDC represents the cost of providing benefitscapital 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 measuringinterest 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 projected benefit obligationutility 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 plans under applicable accounting guidance requires management to make various assumptionsprograms are presented on a gross basis and estimates.

Based on regulatory recovery mechanisms, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI.

disclosed separately from revenue from contracts with customers.
See Note 76 for further discussion of benefit plans and other postretirement benefits.information.

GuaranteesConservation Programs— SPS recognizes, upon issuance 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 modificationconservation 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 a guarantee, a liabilitythese 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 fair market valuecost of RECs and records that cost as a regulatory asset when the obligation that has been assumedamount is recoverable in issuing the guarantee. This liability includes considerationfuture rates.
Sales of specific triggering eventsRECs are recorded in electric revenues on a gross basis. Cost of these RECs and other conditions which may modify the ongoing obligationamounts credited to performcustomers under the guarantee.margin-sharing mechanisms are recorded in electric fuel and purchased power expense.

The obligation recognized is reduced over the term of the guarantee as SPS is released from risk under the guarantee. See Note 11 for specific details of issued guarantees.

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. Operating results from the regulated electric utility segment serve as the primary basis for the chief operating decision maker to evaluate the performance of SPS.

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2017 up to the date of issuance of these financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.


2.Accounting Pronouncements

Recently Issued

Revenue RecognitionCredit Losses— In May 2014,2016, the FASB issued Revenue from Contracts with Customers,Financial Instruments - Credit Losses, Topic 606 (ASU No. 2014-09)326 (ASC Topic 326), which provideschanges how entities account for losses on receivables and certain other assets. The guidance requires use of a new framework for thecurrent expected credit loss model, which may result in earlier recognition of revenue. As the appropriate timing of recognition of revenue from contracts with customers in our regulated operations continues to generally be based on the delivery of electricity, SPS’ adoption will primarily result in increased disclosures regarding sources of revenues, including alternative revenue programs. The guidancecredit losses than under previous accounting standards. ASC Topic 326 is effective for interim and annual periods beginning on or after Dec. 15, 2017. SPS is implementing the standard on2019, and will be applied using a modified retrospective basis, which requires applicationmodified-retrospective approach, with a cumulative-effect adjustment to contracts with customers effectiveretained earnings as of Jan. 1, 2018.

Classification and Measurement2020. SPS expects the impact of Financial Instruments — In January 2016, the FASB issued Recognition and Measurementadoption of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which eliminates the available-for-sale classification for marketable equity securities and also replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. Under the new standard other than whento include first-time recognition of expected credit losses (i.e., bad debt expense) on unbilled revenues, with the consolidation or equity methodinitial allowance established at Jan. 1, 2020 charged to retained earnings. Recognition of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance is effective for interimthis allowance and annual reporting periods beginning after Dec. 15, 2017. The overallother impacts of the Jan. 1, 2018 adoption will not be material.

Leases — In February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which, for lessees, requires balance sheet recognition of right-of-use assets and lease liabilities for most leases. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018. SPS has not yet fully determined the impacts of implementation. However, adoption is expected to occur on Jan. 1, 2019 utilizing the practical expedients provided by the standard and proposed in Targeted Improvements, Topic 842 (Proposed ASU 2018-200). As such, agreements entered prior to Jan. 1, 2019 that are currently considered leases are expected to be recognized onimmaterial to the balance sheet, including contracts for use of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for natural gas-fueled generating facilities. SPS expects that similar agreements entered after Dec. 31, 2018 will generally qualify as leases under the new standard.financial statements.

Presentation of Net Periodic Benefit Cost —In March 2017, the FASB issued Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715 (ASU No. 2017-07), which establishes that only the service cost element of pension cost may be presented as a component of operating income in the income statement. Also under the guidance, only the service cost component of pension cost is eligible for capitalization. As a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the historical ratemaking treatment and the impacts of adoption will be limited to changes in classification of non-service costs in the statement of income. This guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017.

Recently Adopted

Accounting for the TCJALeases —In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118 Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), to supplement the accounting requirements of ASC Topic 740 Income Taxes (ASC Topic 740) as it relates to assessing and recognizing the impacts of the TCJA in the period of enactment. SAB 118 allows an entity to recognize provisional amounts in its financial statements in circumstances in which the entity’s assessment is incomplete, but for which a reasonable estimate can be made. Provisional amounts recognized are subject to adjustment for up to one year from the enactment date. For further details, see Note 6 to the financial statements.

Reporting Comprehensive Income — In February 2018,2016, the FASB issued Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, Leases, Topic 220 (ASU No. 2018-02), which addresses the stranded amounts of accumulated OCI which may result from enactment of a new tax law. Though accumulated OCI is presented on a net-of-tax basis, 842(ASC Topic 740 requires842), which provides new accounting and disclosure guidance for leasing activities, most significantly requiring that the effects of new tax laws on items in accumulated OCIoperating leases be recognized without a corresponding adjustment to accumulated OCI, and instead recorded to income tax expense. ASU No. 2018-02 permits stranded amounts of accumulated OCI specifically resulting fromon the TCJA to be removed from accumulated OCI and reclassified to retained earnings, if elected.balance sheet. SPS adopted the guidance inon Jan. 1, 2019 utilizing the fourth quarterpackage of 2017,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 recognizeTopic 842, and as a $0.3 million increaseresult, only those easement contracts entered on or after Jan. 1, 2019 will be evaluated to accumulated other comprehensive loss and retained earningsdetermine 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 the year ended Dec. 31, 2017, related to a revaluationleasing disclosures.

3. Property, Plant and Equipment

Major classes of deferred income taxproperty, 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 itemsamounts that regulators may allow to be collected or may require to be paid back to customers in accumulatedfuture electric rates. SPS would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive loss, atincome if changes in the TCJA federal tax rate.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

3.
(a)
Selected Balance Sheet DataIncludes amounts recorded for future recovery of AROs.
(b)
Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
(Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016
Accounts receivable, net    
Accounts receivable $85,929
 $80,569
Less allowance for bad debts (6,348) (6,379)
  $79,581
 $74,190
Components of regulatory liabilities:
(Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016
Inventories    
Materials and supplies $26,218
 $25,453
Fuel 14,215
 13,052
  $40,433
 $38,505
(Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016
Property, plant and equipment, net    
Electric plant $6,765,371
 $6,362,189
Construction work in progress 351,875
 260,327
Total property, plant and equipment 7,117,246
 6,622,516
Less accumulated depreciation (2,021,637) (1,926,697)
  $5,095,609
 $4,695,819


(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
4.
(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. SPS had no money pool borrowings outstanding during the three months ended Dec. 31, 2017.

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

(Amounts in Millions, Except Interest Rates) Twelve Months Ended Dec. 31, 2017 Twelve Months Ended Dec. 31, 2016 Twelve Months Ended Dec. 31, 2015
Borrowing limit $100
 $100
 $100
Amount outstanding at period end —
 —
 —
Average amount outstanding 13
 28
 21
Maximum amount outstanding 100
 100
 100
Weighted average interest rate, computed on a daily basis 1.12% 0.67% 0.40%
Weighted average interest rate at end of period N/A
 N/A
 N/A

Commercial Paper — SPS meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. SPS had no commercial paper borrowings outstanding during the three months ended Dec. 31, 2017. 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

(Amounts in Millions, Except Interest Rates) Twelve Months Ended Dec. 31, 2017 Twelve Months Ended Dec. 31, 2016 Twelve Months Ended Dec. 31, 2015
Borrowing limit $400
 $400
 $400
Amount outstanding at period end —
 50
 15
Average amount outstanding 69
 43
 100
Maximum amount outstanding 176
 140
 246
Weighted average interest rate, computed on a daily basis 1.13% 0.67% 0.46%
Weighted average interest rate at end of period NA
 0.95
 0.60

Letters of Credit — SPS may use letters of credit, generallytypically with terms of one-year,one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 20172019 and 2016,2018, there were $3 million and $5$2 million of letters of credit outstanding respectively, 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 hasentered into an amended five-year credit agreement with a syndicate of banks. The amended credit agreements have substantially the right to request an extensionsame terms and conditions as the prior credit agreements with the exception of the following:
Maturity extended from June 2021 termination dateto 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 two additional one-year periods. The extension requests are subject to majority bank group approval.commercial paper borrowings.

Other featuresFeatures of SPS’ credit facility include: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%.
The credit facility may be increased by up to $50 million.
(b)
All extension requests are subject to majority bank group approval.
The credit facility has a financial covenant requiringcross-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’ debt-to-total capitalization ratio be less than or equal to 65 percent. SPS wastotal assets default on indebtedness in compliance as its debt-to-total capitalization ratio was 46 percent and 47 percent at Dec. 31, 2017 and 2016, respectively. 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.
The credit facility has a cross-default provision that provides SPS will be in default on its borrowings under the facility if SPS or any As of its future significant subsidiaries whose total assets exceed 15 percent of SPS’ total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million.
Dec. 31, 2019, SPS was in compliance with all financial covenants on its debt agreements as of Dec. 31, 2017 and 2016.covenants.


At Dec. 31, 2017, SPS had the following committed credit facilityfacilities available (in millions):as of Dec. 31, 2019.
Credit Facility (a)
Credit Facility (a)
 
Drawn (b)
 Available 
Drawn (b)
 Available
$400
 $3
 $397
$500 $2 $498
(a)
This credit facility matures in June 2021.2024.
(b)
Includes letters of credit.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 no0 direct advances on the credit facility outstanding at Dec. 31, 20172019 and 2016.

2018.
Long-Term Borrowings and Other Financing Instruments

Generally, all real and personal 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 associated withfor refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines.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


In 2017, SPS issued $450 million of 3.70 percent first mortgage bonds due Aug. 15, 2047. In 2016, SPS issued $300 million of 3.40 percent first mortgage bonds due Aug. 15, 2046.

During the next five years, SPS has no long-term debt maturities.

Deferred Financing Costs— Deferred financing costs of approximately $18$23 million and $15$20 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 20172019 and 2016,2018, 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’ SPS dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out ofaccounts. Dividends are solely to be paid from retained earnings only.

The most restrictive dividend limitation forearnings. SPS is imposed by its state regulatory commissions. required to be current on particular interest payments before dividends can be paid.
SPS’ state regulatory commissions indirectly limitadditionally impose dividend limitations, which are more restrictive than those imposed by the amountFERC.
Requirements and actuals as of dividends that SPS can pay Xcel Energy Inc. by requiring an equity-to-total capitalization ratio (excluding short-term debt) between 45.0 percent and 55.0 percent. In addition,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. SPS’ equity ratio (excluding short-term debt) was 53.8 percent at Dec. 31, 2017 and $542 million in retained earnings was not restricted.

5.Preferred Stock

SPS has authorized the issuance of preferred stock.
Preferred
Shares
Authorized		 Par Value Preferred
Shares
Outstanding
10,000,000
 $1.00
 None

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 December 2017, the TCJA was signed into law. While the legislation will require interpretations and regulations to be issued by the IRS, theThe key provisions impacting Xcel Energy (which includes SPS), generally beginning in 2018, include:

included:
Corporate federal tax rate reduction from 35 percent35% to 21 percent;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 percent80% of taxable income);
Repeal of the section 199 manufacturing deduction; and
Reduced deductions for meals and entertainment as well as state and local lobbying.

Entities are required under ASC Topic 740 to recognize the accounting impacts of a tax law change, including the impacts of a change in tax rates on deferred tax assets and liabilities, in the period including the date of the tax law enactment. The SEC staff issued guidance in SAB 118 that supplements the accounting requirements of ASC Topic 740 if elements of the TCJA assessment are not complete, and provides for up to a one year period to finalize the required accounting. Xcel Energy has estimated the effects of the TCJA, which have been reflected in the Dec. 31, 2017 consolidated financial statements. Issuance of U.S. Treasury regulations interpreting the TCJA, other U.S. Treasury and IRS guidance or interpretations of the application of ASC Topic 740 may result in changes to these estimates.

Overall for Xcel Energy, reductionsReductions in deferred tax assets and liabilities due to the reductiona 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 of deferred taxes in the determination of regulated rates of the utility subsidiaries, including deferred taxes related to regulated plant and certain other deferred tax assets and liabilities, the impact was primarily recognized as a regulatory liability refundable to utility customers.treatment.

The fourth quarter 2017 estimated accountingEstimated impacts of the December 2017 enactment of the new tax law atfor 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 percent21% 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.

Xcel Energy has accounted for the state tax impacts of federal tax reform based on currently 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.

Consolidated Appropriations Act, 2016 — In December 2015, the Consolidated Appropriations Act, 2016 (Act) was signed into law. The Act provided for the following:

Immediate expensing, or “bonus depreciation,” of 50 percent for property placed in service in 2015, 2016, and 2017;
PTCs at 100 percent of the applicable rate for wind energy projects that begin construction by the end of 2016; 80 percent of the credit rate for projects that begin construction in 2017; 60 percent of the credit rate for projects that begin construction in 2018; and 40 percent of the credit rate for projects that begin construction in 2019. The wind energy PTC was not extended for projects that begin construction after 2019;
ITCs at 30 percent for commercial solar projects that begin construction by the end of 2019; 26 percent for projects that begin construction in 2020; 22 percent for projects that begin construction in 2021; and 10 percent for projects thereafter;
R&E credit was permanently extended; and
Delay of two years (until 2020) of the excise tax on certain employer-provided health insurance plans.

The accounting related to the Act was recorded beginning in the fourth quarter of 2015 because a change in tax law is accounted for beginning in the period of enactment.

Federal Audit — SPS is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statutesStatute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows:
Tax Year(s) Expiration
2009 - 20112013 June 2018
2012 - 2013October 20182020
2014September 2018
2015September 2019
- 2016 September 2020


In 2012, the IRS commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. The IRS proposed an adjustment to the federal tax loss carryback claims that would have resulted in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015 claims. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (“Appeals”). In the third quarter of 2017, Xcel Energy and Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. SPS did not accrue any income tax benefit related to this adjustment. As of Dec. 31, 2017, the case has been forwarded to the Joint Committee on Taxation.

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the third quarter of 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. After evaluating the proposed adjustment, Xcel Energy filed a protest with the IRS. Xcel Energy anticipates the issue will be forwarded to Appeals. As of Dec. 31, 2017,2019, 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 uncertain.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, 2017,2019, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. In 2016, Texas began an audit of years 2009 and 2010, andThere are currently no state income tax audits in September 2017, began an audit of 2011. In the fourth quarter of 2017, Texas concluded these audits and SPS recognized the related benefit.progress.

Unrecognized Tax Benefits — The unrecognizedUnrecognized 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 of cash to the taxing authority to an earlier period.

Unrecognized tax benefits — permanent vs temporary:
A reconciliation of the amount of
(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 benefit is as follows:benefits:
(Millions of Dollars) 2019 2018 2017
Balance at Jan. 1 $4.5
 $4.3
 $28.7
Additions based on tax positions related to the current year 0.7
 0.6
 0.9
Reductions based on tax positions related to the current year (0.1) (0.1) (0.6)
Additions for tax positions of prior years 0.2
 0.1
 1.3
Reductions for tax positions of prior years (0.1) (0.3) (19.9)
Settlements with taxing authorities —
 (0.1) (6.1)
Balance at Dec. 31 $5.2
 $4.5
 $4.3

(Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016
Unrecognized tax benefit — Permanent tax positions $2.3
 $4.5
Unrecognized tax benefit — Temporary tax positions 2.0
 24.2
Total unrecognized tax benefit $4.3
 $28.7

A reconciliation of the beginning and ending amount of unrecognizedUnrecognized tax benefit is as follows:
(Millions of Dollars) 2017 2016 2015
Balance at Jan. 1 $28.7
 $24.7
 $13.2
Additions based on tax positions related to the current year 0.9
 1.4
 4.2
Reductions based on tax positions related to the current year (0.6) —
 (0.6)
Additions for tax positions of prior years 1.3
 3.9
 9.0
Reductions for tax positions of prior years (19.9) (1.3) (1.1)
Settlements with taxing authorities (6.1) —
 —
Balance at Dec. 31 $4.3
 $28.7
 $24.7

The unrecognized tax benefit amountsbenefits were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts ofcarryforwards:
(Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018
NOL and tax credit carryforwards $(4.4) $(3.8)

Net deferred tax benefitsliability associated with NOLthe unrecognized tax benefit amounts and related NOLs and tax creditcredits carryforwards are as follows:were $1.4 million and $0.8 million at Dec. 31, 2019 and Dec. 31, 2018, respectively.
(Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016
NOL and tax credit carryforwards $(5.9) $(5.9)

It is reasonably possible that SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals progresses and audit resumes and state audits resume. 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 $1 million.$3.7 million in the next 12 months.

The payablePayable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the
Interest payable for interest related to unrecognized tax benefits are as follows:benefits:
(Millions of Dollars) 2019 2018 2017
Receivable (payable) for interest related to unrecognized tax benefits at Jan. 1 $0.7
 $0.5
 $(0.9)
Interest income related to unrecognized tax benefits —
 0.2
 1.4
Receivable for interest related to unrecognized tax benefits at Dec. 31 $0.7
 $0.7
 $0.5
(Millions of Dollars) 2017 2016 2015
Payable for interest related to unrecognized tax benefits at Jan. 1 $(0.9) $—
 $(0.1)
Interest income (expense) income related to unrecognized tax benefits 1.4
 (0.9) 0.1
Receivable (payable) for interest related to unrecognized tax benefits at Dec. 31 $0.5
 $(0.9) $—


No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2017, 2016,2019, 2018, or 2015.2017.

Other Income Tax Matters— NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:
(Millions of Dollars) 2019 2018
Federal tax credit carryforwards $29.5
 $5.7
State NOL carryforwards 1.2
 2.9

(Millions of Dollars) 2017 2016
Federal NOL carryforward $115
 $275
Federal tax credit carryforwards 5
 4
State NOL carryforwards 40
 60

The federalFederal carryforward periods expire between 20212024 and 2037. The2039 and state carryforward periods expire between 20212025 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. The following reconciles such differences
Effective income tax rate for the years endingended Dec. 31:
 2017 
2016 (a)
 
2015 (a)
2019 
2018 (a)
 
2017 (a)
Federal statutory rate 35.0 % 35.0 % 35.0 %21.0 % 21.0 % 35.0 %
State income tax on pretax income, net of federal tax effect 0.9 % 1.0 % 1.0 %2.2 % 2.3 % 2.0 %
Increases (decreases) in tax from: 

 

 



 

 

Wind PTCs(7.9) —
 —
Plant regulatory differences (b)
(5.0) (4.8) (0.9)
Amortization of excess nonplant deferred taxes(0.9) (1.2) —
Other tax credits, net of NOL & tax credit allowances(0.6) (0.7) (0.6)
Adjustments attributable to tax returns(0.1) (1.5) (0.4)
Change in unrecognized tax benefits0.2
 0.1
 (1.0)
Tax reform (3.5) —
 —
—
 —
 (3.5)
Change in unrecognized tax benefits (1.0) 0.8
 0.5
Tax credits recognized, net of federal income tax expense (0.7) (0.5) (0.3)
Regulatory differences - other utility plant items (0.8) (1.0) (0.8)
Other, net 0.2
 (0.2) 1.7
—
 0.2
 (0.5)
Effective income tax rate 30.1 % 35.1 % 37.1 %8.9 % 15.4 % 30.1 %
(a) 
The priorPrior periods included in this footnote 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.

The components
Components of income tax expense for the years endingended Dec. 31 were:31:
(Thousands of Dollars) 2017 2016 2015
Current federal tax benefit $(20,858) $(40,853) $(1,327)
Current state tax (benefit) expense (12,725) (2,929) 2,448
Current change in unrecognized tax (benefit) expense (24,333) 3,126
 11,281
Deferred federal tax expense 89,934
 116,404
 67,640
Deferred state tax expense 14,437
 7,757
 5,399
Deferred change in unrecognized tax expense (benefit) 22,094
 (1,178) (10,203)
Deferred investment tax credits (133) (213) (213)
Total income tax expense $68,416
 $82,114
 $75,025
(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


The componentsComponents of deferred income tax expense for the years endingas of Dec. 31 were: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

(Thousands of Dollars) 2017 2016 2015
Deferred tax (benefit) expense excluding items below $(414,231) $128,393
 $63,453
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities 540,744
 (5,416) (780)
Tax (expense) benefit allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other (48) 6
 163
Deferred tax expense $126,465
 $122,983
 $62,836

The componentsComponents of the net deferred tax liability atas of Dec. 31 were as follows:31:
(Thousands of Dollars) 2017 
2016 (a)
(Millions of Dollars) 2019 
2018 (a)
Deferred tax liabilities:        
Differences between book and tax bases of property $659,165
 $1,034,675
 $758.7
 $680.6
Operating lease assets 115.8
 —
Regulatory assets 47,519
 14,811
 49.7
 49.2
Pension expense 33,815
 51,895
 33.1
 32.3
Other 4,604
 3,267
Total deferred tax liabilities $745,103
 $1,104,648
 $957.3
 $762.1
    
Deferred tax assets: 

 

 

 

Regulatory liabilities 115,302
 (13,167) $111.2
 $116.8
NOL carryforward 26,238
 100,179
Operating lease liabilities 115.8
 —
Tax credit carryforward 29.5
 5.7
Deferred fuel costs 10,448
 10,226
 18.3
 12.7
Other employee benefits 5,769
 9,656
 5.8
 5.6
Tax credit carryforward 5,178
 3,738
NOL carryforward 0.1
 0.2
Other 7,262
 4,879
 4.8
 2.0
Total deferred tax assets $170,197
 $115,511
 285.5
 143.0
Net deferred tax liability $574,906
 $989,137
 $671.8
 $619.1

(a) Prior periods have been reclassified to conform to current year presentation.
(a)
The prior period included in this footnote has been reclassified to conform to current year presentation.

7.Benefit Plans8. Fair Value of Financial Assets and Other Postretirement BenefitsLiabilities

Consistent with the process for rate recovery of pension and postretirement benefits for its employees, SPS accounts for its participation in, and related costs of, pension and other postretirement benefit plans sponsored by Xcel Energy Inc. as multiple employer plans. SPS is responsible for its share of cash contributions, plan costs and obligations and is entitled to its share of plan assets; accordingly, SPS accounts for its pro rata share of these plans, including pension expense and contributions, resulting in accounting consistent with that of a single employer plan exclusively for SPS employees.

Xcel Energy, which includes SPS, offers various benefit plans to its employees. Approximately 68 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2017, SPS had 791 bargaining employees covered under a collective-bargaining agreement, which expires in October 2019.

Fair Value Measurements
The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishesand 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. The three levels in the hierarchy and examples of each level are as follows:

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

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


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 inputsmodels requiring significant management judgment or estimation.

Specific valuation methods include the following: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.

Insurance contractsInterest rate derivatives — Insurance contract fair values take into consideration the value of the investments in separate accounts of the insurer, which are priced based on observable inputs.

Investments in commingled funds, equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value. The investments in commingled funds may be redeemed for NAV with proper notice. Proper notice varies by fund and can range from daily with a few days’ notice to annually with 90 days’ notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Depending on the fund, unscheduled distributions from real estate investments may require approval of the fund or may be redeemed with proper notice, which is typically quarterly with 45-90 days’ notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity.

Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.

Derivative Instruments —Fair values for foreign currency derivatives are determined using pricing models based on the prevailing forward exchange rate of the underlying currencies. 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.

Pension Benefits
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.



















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 the employee’sand average pay and, in some cases, social security benefits.pay. Xcel Energy Inc.’s and SPS’Energy’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.

In addition to the qualified pension plans, Xcel Energy maintains a supplemental executive retirement plan (SERP)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 unfunded, nonqualified benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions attributable to SPS funded by SPS’Xcel Energy’s consolidated operating cash flows. The total obligationsObligations of the SERP and nonqualified plan as of Dec. 31, 20172019 and 20162018 were $37$39 million and $44$33 million, respectively, of which $2 million and $3 million werewas attributable to SPS.SPS in both years. In 20172019 and 2016,2018, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $5$4 million in 2019 and $8 million, respectively,2018, of which immaterial amounts were attributable to SPS.

In 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of the SERP and its deferred compensation plan. Rabbi trust funding of deferred compensation plan distributions attributable to SPS will be supplemented by SPS operating cash flows as determined necessary. The amount of rabbi trust funding attributable to SPS is immaterial. Also in 2016, Xcel Energy amended the deferred compensation plan to provide eligible participants the ability to diversify deferred settlements of equity awards, other than time-based equity awards, into various fund options.

Xcel Energy, Inc. andwhich includes SPS, basebases the investment-return assumption on expected long-term performance for each of the investment types includedasset classes in theits pension asset portfolio and considerpostretirement health care portfolios. For pension assets, Xcel Energy considers the historical returns achieved by theits asset portfolio over the past 20-year20 years or longer period, as well as the long-term projected return levels projected and recommended by investment experts.levels. Xcel Energy Inc. and SPS continually review the pension assumptions. The pension
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 percent;
Investment returns in 2016 were below the assumed level of 6.78 percent;

Investment returns in 2015 were below the assumed level of 7.22 percent;6.78%; and
In 2018, SPS’2020, Xcel Energy’s expected investment-return assumption is 6.78 percent.6.78%.

The
Pension plan and postretirement benefit assets are invested in a portfolio according to Xcel Energy Inc.’s and SPS’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 projected 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 particular industry, index or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by pensionthe assets in any year.

The following table presentsState agencies also have issued guidelines to the target pension asset allocationsfunding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for SPS at Dec. 31Texas and New Mexico amounts collected in rates. These assets are invested in a manner consistent with the investment strategy for the upcoming year:pension plan.
  2017 2016
Domestic and international equity securities 34% 36%
Long-duration fixed income and interest rate swap securities 31
 31
Short-to-intermediate fixed income securities 19
 15
Alternative investments 14
 16
Cash 2
 2
Total 100% 100%

TheXcel 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. The aggregate projected asset allocation presented in the table above for the master pension trust results from the plan-specific strategies.

Pension Plan Assets

The following tables present, forFor each of the fair value hierarchy levels, SPS’ pension plan assets that are 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 ashierarchy levels, SPS’ proportionate allocation of Dec. 31, 2017 and 2016:the total postretirement benefit plan assets that were measured at fair value:
  Dec. 31, 2017
(Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total
Cash equivalents $26,934
 $—
 $—
 $—
 $26,934
Commingled funds:          
U.S. equity funds 68,103
 —
 —
 —
 68,103
Non U.S. equity funds 12,156
 —
 —
 26,427
 38,583
U.S. corporate bond funds 54,830
 —
 —
 —
 54,830
Emerging market equity funds —
 —
 —
 41,706
 41,706
Emerging market debt funds 9,967
 —
 —
 22,063
 32,030
Private equity investments —
 —
 —
 11,168
 11,168
Real estate —
 —
 —
 25,896
 25,896
Other commingled funds 643
 —
 —
 15,476
 16,119
Debt securities:          
Government securities —
 57,578
 —
 —
 57,578
U.S. corporate bonds —
 41,041
 —
 —
 41,041
Non U.S. corporate bonds —
 6,717
 —
 —
 6,717
Equity securities:          
U.S. equities 15,157
 —
 —
 —
 15,157
Other (3,271) 566
 —
 72
 (2,633)
Total $184,519
 $105,902
 $—
 $142,808
 $433,229
  
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.

  Dec. 31, 2016
(Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total
Cash equivalents $29,237
 $—
 $—
 $—
 $29,237
Commingled funds:          
U.S. equity funds 62,899
 —
 —
 —
 62,899
Non U.S. equity funds 24,472
 —
 —
 21,931
 46,403
U.S. corporate bond funds 41,226
 —
 —
 —
 41,226
Emerging market equity funds —
 —
 —
 24,637
 24,637
Emerging market debt funds 9,825
 —
 —
 10,574
 20,399
Commodity funds —
 —
 —
 2,876
 2,876
Private equity investments —
 —
 —
 12,098
 12,098
Real estate —
 —
 —
 23,232
 23,232
Other commingled funds —
 —
 —
 28,247
 28,247
Debt securities:          
Government securities —
 38,105
 —
 —
 38,105
U.S. corporate bonds —
 36,293
 —
 —
 36,293
Non U.S. corporate bonds —
 5,818
 —
 —
 5,818
Mortgage-backed securities —
 821
 —
 —
 821
Asset-backed securities —
 389
 —
 —
 389
Equity securities:          
U.S. equities 10,477
 —
 —
 —
 10,477
Other —
 (2,762) —
 —
 (2,762)
Total $178,136
 $78,664
 $—
 $123,595
 $380,395

ThereImmaterial assets were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2017, 20162019. No assets were transferred in or 2015.out of Level 3 for 2018.

Benefit ObligationsFunded Status — A comparisonComparisons of the actuarially computed pension benefit obligation, andchanges in plan assets and funded status of the pension and postretirement health care plans for SPS isXcel Energy are presented in the following table:
(Thousands of Dollars) 2017 2016
Accumulated Benefit Obligation at Dec. 31 $478,843
 $453,317
     
Change in Projected Benefit Obligation:    
Obligation at Jan. 1 $483,601
 $467,394
Service cost 9,758
 9,761
Interest cost 19,710
 21,259
Plan amendments (984) —
Actuarial loss 31,218
 25,053
Transfer to other plan —
 (3,305)
Benefit payments (27,424) (36,561)
Obligation at Dec. 31 $515,879
 $483,601
(Thousands of Dollars) 2017 2016
Change in Fair Value of Plan Assets:    
Fair value of plan assets at Jan. 1 $380,395
 $378,913
Actual return on plan assets 56,756
 23,306
Employer contributions 23,502
 18,088
Transfer to other plan —
 (3,351)
Benefit payments (27,424) (36,561)
Fair value of plan assets at Dec. 31 $433,229
 $380,395
(Thousands of Dollars) 2017 2016
Funded Status of Plans at Dec. 31:    
Funded status (a)
 $(82,650) $(103,206)

  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) 
Amounts are recognizedIncludes approximately $6.8 million in noncurrent liabilities on SPS’ balance sheets.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.


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:
(Thousands of Dollars) 2017 2016
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:    
Net loss $237,024
 $247,381
Prior service credit (1,372) —
Total $235,652
 $247,381
  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.
(Thousands of Dollars) 2017 2016
 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 $13,851
 $13,524
 $11.0
 $12.9
 $—
 $—
Noncurrent regulatory assets 221,801
 233,857
 197.6
 216.8
 —
 —
Current regulatory liabilities —
 —
 (0.8) (0.9)
Noncurrent regulatory liabilities —
 —
 (12.5) (10.5)
Total $235,652
 $247,381
 $208.6
 $229.7
 $(13.3) $(11.4)
Measurement date Dec. 31, 20172019 Dec. 31, 20162018Dec. 31, 2019Dec. 31, 2018

  2017 2016
Significant Assumptions Used to Measure Benefit Obligations:    
Discount rate for year-end valuation 3.63% 4.13%
Expected average long-term increase in compensation level 3.75
 3.75
Mortality table RP-2014
 RP-2014


Mortality — In 2014, the Society of Actuaries published a new mortality table (RP-2014) that increased the overall life expectancy of males and females. In 2014, SPS adopted this mortality table, with modifications, based on its population and specific experience. During 2017, a new projection table was released (MP-2017). SPS evaluated the updated projection table and concluded that the methodology currently in use and adopted in 2016 is consistent with the recently updated 2017 table and continues to be representative of SPS’ population.

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 2015 through 20182017 - 2020 to meet minimum funding requirements.

Total voluntary and required pension funding contributions across all four4 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 January 2018, of which $8 million was attributable to SPS; and
$162 million in 2017, of which $24 million was attributable to SPS
$125 million in 2016, of which $18 million was attributable to SPS; and
$90 million in 2015, of which $12 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.

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 2016,2019 and 2018, there were no plan amendments made which affected the benefit obligation.

Projected Benefit Payments
Benefit Costs —The components of SPS’ net periodic pension cost were: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

(Thousands of Dollars) 2017 2016 2015
Service cost $9,758
 $9,761
 $11,006
Interest cost 19,710
 21,259
 20,184
Expected return on plan assets (27,883) (27,602) (28,610)
Amortization of prior service cost —
 —
 39
Amortization of net loss 12,981
 11,986
 15,087
Net periodic pension cost 14,566
 15,404
 17,706
Credits not recognized due to effects of regulation 306
 2,042
 2,597
Net benefit cost recognized for financial reporting $14,872
 $17,446
 $20,303

  2017 2016 2015
Significant Assumptions Used to Measure Costs:      
Discount rate 4.13% 4.66% 4.11%
Expected average long-term increase in compensation level 3.75
 4.00
 3.75
Expected average long-term rate of return on assets 6.78
 6.78
 7.22

In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy Inc., costs are allocated to SPS based on Xcel Energy Services Inc. employees’ labor costs. Amounts allocated to SPS were $8 million, $4 million and $5 million in 2017, 2016 and 2015, respectively. Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2018 pension cost calculations is 6.78 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy, including SPS, uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year. As these differences between actual investment returns and the expected investment returns are incorporated into the market-related value, the differences are recognized over the expected average remaining years of service for active employees.

Defined Contribution Plans

Xcel Energy, which includes SPS, maintains 401(k) and other defined contribution plans that cover substantially allmost employees. The expense to these plans for SPS was approximately $3 million in 2017, 20162019, 2018 and 2015.2017.

Postretirement Health Care Benefits

Xcel Energy, which includes SPS, has a contributory health and welfare benefit plan that provides health care and death benefits to certain retirees. Xcel Energy discontinued contributing toward health care benefits for SPS nonbargaining employees retiring after June 30, 2003. Employees of NCE who retired in 2002 continue to receive employer-subsidized health care benefits. Nonbargaining employees of the former NCE who retired after 1998, bargaining employees of the former NCE who retired after 1999 and nonbargaining employees of NCE who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy.

Regulatory agencies for nearly all retail and wholesale utility customers have allowed rate recovery of accrued postretirement benefit costs.

Plan Assets — Certain state agencies that regulate Xcel Energy Inc.’s utility subsidiaries also have issued guidelines related to the funding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for Texas and New Mexico jurisdictional amounts collected in rates. These assets are invested in a manner consistent with the investment strategy for the pension plan.

The following table presents the target postretirement asset allocations for Xcel Energy Inc. and SPS at Dec. 31 for the upcoming year:
  2017 2016
Domestic and international equity securities 24% 25%
Short-to-intermediate fixed income securities 60
 57
Alternative investments 9
 13
Cash 7
 5
Total 100% 100%


Xcel Energy Inc. and SPS base investment-return assumptions for the postretirement health care fund assets on expected long-term performance for each of the investment types included in the asset portfolio. Assumptions and target allocations are determined at the master trust level. The investment mix at each of Xcel Energy Inc.’s utility subsidiaries may vary from the investment mix of the total asset portfolio. The assets are invested in a portfolio according to Xcel Energy Inc.’s and SPS’ 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 projected 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 particular industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by postretirement health care assets in any year.

The following tables present, for each of the fair value hierarchy levels, SPS’ proportionate allocation of the total postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2017 and 2016:
  Dec. 31, 2017
(Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total
Cash equivalents $2,787
 $—
 $—
 $—
 $2,787
Insurance contracts —
 4,716
 —
 —
 4,716
Commingled funds:          
U.S. equity funds 7,032
 —
 —
 —
 7,032
U.S fixed income funds 3,245
 —
 —
 —
 3,245
Emerging market debt funds 3,836
 —
 —
 —
 3,836
Debt securities:          
Government securities —
 5,480
 —
 —
 5,480
U.S. corporate bonds —
 5,995
 —
 —
 5,995
Non U.S. corporate bonds —
 2,027
 —
 —
 2,027
Asset-backed securities —
 2,218
 —
 —
 2,218
Mortgage-backed securities —
 3,276
 —
 —
 3,276
Equity securities:          
Non U.S. equities 3,323
 —
 —
 —
 3,323
Other —
 104
 —
 —
 104
Total $20,223
 $23,816
 $—
 $—
 $44,039
  Dec. 31, 2016
(Thousands of Dollars) Level 1 Level 2 Level 3 
Investments Measured at NAV

 Total
Cash equivalents $1,966
 $—
 $—
 $—
 $1,966
Insurance contracts —
 4,519
 —
 —
 4,519
Commingled funds:          
U.S. equity funds 5,208
 —
 —
 —
 5,208
U.S fixed income funds 2,593
 —
 —
 —
 2,593
Emerging market debt funds 2,911
 —
 —
 —
 2,911
Other commingled funds —
 —
 —
 5,258
 5,258
Debt securities:          
Government securities —
 3,611
 —
 —
 3,611
U.S. corporate bonds —
 5,962
 —
 —
 5,962
Non U.S. corporate bonds —
 1,653
 —
 —
 1,653
Asset-backed securities —
 1,810
 —
 —
 1,810
Mortgage-backed securities —
 2,748
 —
 —
 2,748
Equity securities:

          
Non U.S. equities 3,919
 —
 —
 —
 3,919
Other —
 139
 —
 —
 139
Total $16,597
 $20,442
 $—
 $5,258
 $42,297

There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2017, 2016 or 2015.

Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for SPS is presented in the following table:
(Thousands of Dollars) 2017 2016
Change in Projected Benefit Obligation:    
Obligation at Jan. 1 $41,860
 $40,864
Service cost 875
 775
Interest cost 1,659
 1,821
Medicare subsidy reimbursements 14
 31
Plan participants’ contributions 637
 653
Actuarial loss 4,688
 1,293
Benefit payments (2,764) (3,577)
Obligation at Dec. 31 $46,969
 $41,860
(Thousands of Dollars) 2017 2016
Change in Fair Value of Plan Assets:    
Fair value of plan assets at Jan. 1 $42,297
 $42,684
Actual return on plan assets 3,686
 1,978
Plan participants’ contributions 637
 653
Employer contributions 183
 559
Benefit payments (2,764) (3,577)
Fair value of plan assets at Dec. 31 $44,039
 $42,297
(Thousands of Dollars) 2017 2016
Funded Status of Plans at Dec. 31:    
Funded status (a)
 $(2,930) $437

(a)
Amounts are recognized in noncurrent liabilities and noncurrent assets on SPS’ balance sheet as of Dec. 31, 2017 and 2016, respectively.
(Thousands of Dollars) 2017 2016
Amounts Not Yet Recognized as Components of Net Periodic Benefit Credit:    
Net gain $(8,620) $(12,595)
Prior service credit (2,229) (2,630)
Total $(10,849) $(15,225)
(Thousands of Dollars) 2017 2016
Amounts Not Yet Recognized as Components of Net Periodic Benefit Credit Have Been Recorded as Follows Based Upon Expected Recovery in Rates:    
Current regulatory liabilities $(827) $(1,004)
Noncurrent regulatory liabilities (10,022) (14,221)
Total $(10,849) $(15,225)
Measurement dateDec. 31, 2017Dec. 31, 2016
  2017 2016
Significant Assumptions Used to Measure Benefit Obligations:    
Discount rate for year-end valuation 3.62% 4.13%
Mortality table RP 2014
 RP 2014
Health care costs trend rate — initial Pre-65 7.00% 5.50%
Health care costs trend rate — initial Post-65
5.50%
5.50%


Beginning with the Dec. 31, 2017 measurement, Xcel Energy Inc. and SPS separated its initial medical trend assumption for pre-Medicare (Pre-65) and post-Medicare (Post-65) claims costs of 7.0 percent and 5.5 percent, respectively, in order to reflect different short-term expectations based on recent experience differences. The ultimate trend assumption remained at 4.5 percent for both Pre-65 and Post-65 claims costs as similar long-term trend rates are expected for both populations. The period until the ultimate rate is reached is five years. Xcel Energy Inc. and SPS base the medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by the retiree medical plan.

A one-percent change in the assumed health care cost trend rate would have the following effects on SPS:
  One-Percentage Point
(Thousands of Dollars) Increase Decrease
APBO $4,559
 $(3,858)
Service and interest components 266
 (225)

Cash Flows — 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 under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Xcel Energy, which includes SPS, contributed $20 million, $18 million and $18 million during 2017, 2016 and 2015, respectively, of which the amounts attributable to SPS were immaterial. Xcel Energy expects to contribute approximately $12 million during 2018, of which amounts attributable to SPS will be zero.

Plan Amendments —In 2017 and 2016, there were no plan amendments made which affected the benefit obligation.

Benefit Costs — The components of SPS’ net periodic postretirement benefit costs were:
(Thousands of Dollars) 2017 2016 2015
Service cost $875
 $775
 $954
Interest cost 1,659
 1,821
 1,745
Expected return on plan assets (2,355) (2,377) (2,540)
Amortization of prior service credit (401) (401) (401)
Amortization of net gain (618) (583) (639)
Net periodic postretirement benefit credit $(840) $(765) $(881)
  2017 2016 2015
Significant Assumptions Used to Measure Costs:      
Discount rate 4.13% 4.65% 4.08%
Expected average long-term rate of return on assets 5.80
 5.80
 5.80

In addition to the benefit costs in the table above, for the postretirement health care plans sponsored by Xcel Energy Inc., costs are allocated to SPS based on Xcel Energy Services Inc. employees’ labor costs.

Projected Benefit Payments — The following table lists SPS’ projected benefit payments for the pension and postretirement benefit plans:
(Thousands 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
2018 $30,475
 $3,277
 $22
 $3,255
2019 28,755
 3,189
 19
 3,170
2020 29,621
 3,229
 21
 3,208
2021 29,721
 3,351
 25
 3,326
2022 30,712
 3,384
 30
 3,354
2023-2027 155,784
 14,773
 141
 14,632


8.Other Income (Expense), Net

Other income (expense), net for the years ended Dec. 31 consisted of the following:
(Thousands of Dollars) 2017 2016 2015
Interest income $2,407
 $129
 $129
Other nonoperating income —
 5
 11
Insurance policy expense (48) (43) (40)
Other nonoperating expense —
 —
 (106)
Other income (expense), net $2,359
 $91
 $(6)

9.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 certain 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. The three levels in the hierarchy are as follows:

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

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

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

Specific valuation methods include the following:

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 a regional transmission organization (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 insignificant to the financial statements of SPS.

Derivative Instruments Fair Value Measurements

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

Interest Rate Derivatives — SPS may enter into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.

At Dec. 31, 2017, 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’ risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up 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.

The following table details the gross notional amounts of commodity FTRs at Dec. 31, 2017 and 2016:
(Amounts in Thousands) (a)
 Dec. 31, 2017 Dec. 31, 2016
MWh of electricity 4,251
 2,685

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

Consideration of Credit Risk and Concentrations — SPS continuously monitors the creditworthiness of the 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. Given this assessment, as well as an assessment of the impact of SPS’ own credit risk when determining the fair value of derivative liabilities, the impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the balance sheets.

SPS employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

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, 2017, two of the eight most significant counterparties for these activities, comprising $10.6 million or 28 percent of this credit exposure, had investment grade ratings from S&P’s, Moody’s or Fitch Ratings. Five of the eight most significant counterparties, comprising $7.8 million or 20 percent of this credit exposure, were not rated by external rating agencies, but based on SPS’ internal analysis, had credit quality consistent with investment grade. One of these significant counterparties, comprising approximately $0.1 million or less than 1 percent of this credit exposure, had credit quality less than investment grade, based on external analysis. Seven of these significant counterparties are municipal or cooperative electric entities, or other utilities.


Financial Impact of Qualifying Cash Flow Hedges — The 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, is detailed in the following table:
(Thousands of Dollars) 2017 2016 2015
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $(678) $(817) $(989)
After-tax net realized losses on derivative transactions reclassified into earnings 39
 139
 172
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $(639) $(678) $(817)

Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were $0.1 million, $0.2 million and $0.3 million each of the years ended Dec. 31, 2017, 2016 and 2015, respectively.

Changes in the fair value of FTRs resulting in pre-tax net gains of $0.5 million and $3.0 million for the years ended Dec. 31, 2017 and 2016, respectively and pre-tax net losses of $3.1 million for the year ended Dec. 31, 2015, 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 $0.8 million and $2.1 million were recognized for the years ended Dec. 31, 2017 and 2016, respectively and FTR settlement losses of $1.6 million were recognized for the years ended Dec. 31, 2015, recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

SPS had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2017, 2016 and 2015. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

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, 2017:
  Dec. 31, 2017
  Fair Value Fair Value Total 
Counterparty Netting (b)
  
(Thousands of Dollars) Level 1 Level 2 Level 3   Total
Current derivative assets            
Other derivative instruments:            
Electric commodity $—
 $—
 $14,717
 $14,717
 $(1,994) $12,723
Total current derivative assets $—
 $—
 $14,717
 $14,717
 $(1,994) 12,723
PPAs (a)
           3,159
Current derivative instruments           $15,882
Noncurrent derivative assets            
PPAs (a)
           $18,954
Noncurrent derivative instruments           $18,954
Current derivative liabilities            
Other derivative instruments:            
Electric commodity $—
 $—
 $1,994
 $1,994
 $(1,994) $—
Total current derivative liabilities $—
 $—
 $1,994
 $1,994
 $(1,994) —
PPAs (a)
           3,565
Current derivative instruments           $3,565
Noncurrent derivative liabilities            
PPAs (a)
           $19,949
Noncurrent derivative instruments           $19,949

(a)
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.
(b)
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, 2017. At Dec. 31, 2017, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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, 2016:
  Dec. 31, 2016
  Fair Value Fair Value Total 
Counterparty Netting (b)
  
(Thousands of Dollars) Level 1 Level 2 Level 3   Total
Current derivative assets            
Other derivative instruments:            
Electric commodity $—
 $—
 $3,254
 $3,254
 $(1,299) $1,955
Total current derivative assets $—
 $—
 $3,254
 $3,254
 $(1,299) 1,955
PPAs (a)
           3,159
Current derivative instruments           $5,114
Noncurrent derivative assets            
PPAs (a)
           $22,113
Noncurrent derivative instruments           $22,113
Current derivative liabilities            
Other derivative instruments:            
Electric commodity $—
 $—
 $1,299
 $1,299
 $(1,299) $—
Total current derivative liabilities $—
 $—
 $1,299
 $1,299
 $(1,299) —
PPAs (a)
           3,565
Current derivative instruments           $3,565
Noncurrent derivative liabilities            
PPAs (a)
           $23,513
Noncurrent derivative instruments           $23,513

(a)
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.
(b)
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, 2016. At Dec. 31, 2016, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents the changes in Level 3 commodity derivatives for the years ended Dec. 31, 2017, 2016 and 2015:
  Year Ended Dec. 31
(Thousands of Dollars) 2017 2016 2015
Balance at Jan. 1 $1,955
 $5,060
 $15,884
Purchases 41,176
 7,616
 23,425
Settlements (55,758) (41,923) (31,703)
Net transactions recorded during the period: 

    
Net gains (losses) recognized as regulatory assets 25,350
 31,202
 (2,546)
Balance at Dec. 31 $12,723
 $1,955
 $5,060

SPS recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the years ended Dec. 31, 2017, 2016 and 2015.

Fair Value of Long-Term Debt

As of Dec. 31, 2017 and 2016, other financial instruments for which the carrying amount did not equal fair value were as follows:
  2017 2016
(Thousands of Dollars) 
Carrying
Amount
 Fair Value 
Carrying
Amount
 Fair Value
Long-term debt, including current portion $1,829,941
 $2,001,992
 $1,635,858
 $1,741,502


The fair value of SPS’ long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of Dec. 31, 2017 and 2016, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

10.Rate Matters

Tax Reform — Regulatory Proceedings

The specific impacts of the TCJA on retail customer rates are subject to regulatory approval. SPS is in the process of quantifying the rate impacts of the TCJA and addressing these impacts in its open proceedings focused on retail base rate impacts.

On Jan. 25, 2018, the PUCT issued an order requiring utilities to apply deferred accounting for the impacts of the TCJA. On Feb. 16, 2018, SPS provided the PUCT supplemental testimony on the impacts of the TCJA for its ongoing Texas 2017 electric rate case, including increasing its equity ratio to 58 percent to offset the negative impact of the TCJA on its credit metrics and potentially its credit ratings.

In February 2018, SPS provided the NMPRC a preliminary quantification of the impacts of the TCJA on its ongoing New Mexico 2017 electric rate case. SPS also recommended increasing its equity ratio to 58 percent to offset the negative impact of the TCJA on its credit metrics and potentially its credit ratings. In a separate NMPRC investigation into the impacts of the TCJA on regulated utilities in New Mexico, SPS provided additional information on the impacts of the TCJA on 2018 operations on Feb. 23, 2018.

Pending and Recently Concluded Regulatory Proceedings — PUCT

Appeal of the Texas 2015 Electric Rate Case Decision — In 2014, SPS had requested an overall retail electric revenue rate increase of $42 million. In 2015, the PUCT approved an overall rate decrease of approximately $4 million, net of rate case expenses. In April 2016, SPS filed an appeal with the Texas State District Court (District Court) challenging the PUCT’s order that had denied SPS’ request for rehearing on certain items in SPS’ Texas 2015 electric rate case related to capital structure, incentive compensation and wholesale load reductions. In March 2017, the District Court denied SPS’ appeal.  In April 2017, SPS appealed the District Court’s decision to the Court of Appeals. A decision is pending.

Texas 2017 Electric Rate Case — In 2017, SPS filed a $55 million, or 5.8 percent, retail electric, non-fuel base rate increase case in Texas with each of its Texas municipalities and the PUCT. The request was based on the 12-month period ended June 30, 2017, with the final three months based on estimates, a requested ROE of 10.25 percent, a Texas retail electric rate base of approximately $1.9 billion and an equity ratio of 53.97 percent.

The following table summarizes SPS’ rate increase request:
Revenue Request (Millions of Dollars)  
Incremental revenue request $69
TCRF revenue conversion to base rates (a)
 (14)
  Net revenue increase request $55

(a)
The roll-in of the TCRF rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. SPS can request another TCRF rider after the conclusion of this rate case to recover transmission investments subsequent to June 30, 2017.

Key dates in the revised procedural schedule are as follows:

Intervenors’ direct testimony — April 25, 2018;
PUCT Staff direct testimony — May 2, 2018;
PUCT Staff and intervenors’ cross-rebuttal testimony — May 14, 2018;
SPS’ rebuttal testimony — May 23, 2018; and
Hearings — June 4 - 14, 2018.

The final rates are expected to be effective retroactive to Jan. 23, 2018 through a customer surcharge. A PUCT decision is expected in the fourth quarter of 2018. As discussed above, the PUCT has opened a docket on the impact of the TCJA, which may have a significant impact on this rate case. On Feb. 16, 2018, SPS provided additional information on the impacts of the TCJA.


Pending Regulatory Proceedings — NMPRC

Appeal of the New Mexico 2016 Electric Rate Case Dismissal — In November 2016, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately $41 million, representing a total revenue increase of approximately 10.9 percent. The rate filing was based on a requested ROE of 10.1 percent, an equity ratio of 53.97 percent, an electric rate base of approximately $832 million and a FTY ending June 30, 2018. In April 2017, the NMPRC dismissed SPS’ rate case. In May 2017, SPS filed a notice of appeal to the New Mexico Supreme Court. A decision is pending.

New Mexico 2017 Electric Rate Case — In October 2017, SPS filed an electric rate case with the NMPRC seeking an increase in retail electric base rates of approximately $43 million. The request is based on a HTY ended June 30, 2017, a ROE of 10.25 percent, an equity ratio of 53.97 percent and a jurisdictional rate base of approximately $885 million, including rate base additions through Nov. 30, 2017. This rate case also takes into account the decline in sales of 380 MW in 2017 from certain wholesale customers and seeks to adjust the life of SPS’ Tolk power plant (Unit 1 from 2042 to 2032 and Unit 2 from 2045 to 2032).

Key dates in the procedural schedule are as follows:

Staff and intervenor direct testimony — April 13, 2018;
SPS’ rebuttal testimony — May 2, 2018; and
Hearings — May 15 - 25, 2018.

SPS anticipates a decision and implementation of final rates in the second half of 2018. As discussed above, the NMPRC has opened a docket on the impact of the TCJA, which may have a significant impact on this rate case.

Pending Regulatory Proceedings — FERC

SPP Open Access Transmission Tariff (OATT) Upgrade Costs — Under the SPP OATT, costs of participant-funded, or “sponsored,” transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade.  The SPP OATT has allowed SPP to charge for these upgrades since 2008, but SPP had not been charging its customers for these upgrades.  In 2016, the FERC granted SPP’s request to recover the charges not billed since 2008.  SPP subsequently billed SPS approximately $13 million for these charges. SPP is also billing SPS ongoing charges of approximately $0.5 million per month. SPS is currently seeking recovery of these SPP charges in its pending Texas and New Mexico base rate cases.

In October 2017, SPS filed a complaint against SPP regarding the amounts billed asserting that SPP has assessed upgrade charges to SPS even where SPS’ transmission service was not dependent upon the upgrade as required by the SPP OATT.  If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the differential in future rate proceedings.

11.Commitments and Contingencies


Commitments

Capital Commitments — SPS has made commitments in connection with a portion of its projected capital expenditures. SPS’ capital commitments primarily relate to the following major projects:

Transmission NTC — SPS has accepted NTCs for several hundred miles of transmission line and related substation projects based on needs identified through SPP’s various planning processes, including those associated with economics, reliability, generator interconnection and the load addition processes. Most significant are the 345 KV transmission line from TUCO to Yoakum County to Hobbs Plant and the Hobbs Plant to China Draw 345 KV transmission lines.

New Mexico and Texas Wind Projects — SPS is seeking approval from the NMPRC and the PUCT to build, own and operate 1,000 MW of new wind generation through the addition of two wind generation facilities in New Mexico and Texas.

Fuel Contracts— SPS has entered into various long-term commitments for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2018 and 2029. SPS is required to pay additional amounts depending on actual quantities shipped under these agreements.


The estimated minimum purchases for SPS under these contracts as of Dec. 31, 2017, are as follows:
(Millions of Dollars) Coal Natural gas
supply		 Natural gas
storage and
transportation
2018 $172
 $11
 $29
2019 106
 —
 32
2020 64
 —
 32
2021 20
 —
 27
2022 21
 —
 21
Thereafter —
 —
 50
Total $383
 $11
 $191

Additional expenditures for fuel and natural gas storage and transportation will be required to meet expected future electric generation needs. SPS’ risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the cost-rate adjustment mechanisms, which provide for pass-through of most fuel, storage and transportation costs to customers.

PPAs — SPS has entered into PPAs with other utilities and energy suppliers with expiration dates through 2033 for purchased power to meet system load and energy requirements and meet operating reserve obligations. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Capacity payments are typically contingent on the independent power producing entity meeting contract obligations, including plant availability requirements. Contractual payments are adjusted based on market indices. The effects of price adjustments on our 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 $58 million, $57 million and $57 million in 2017, 2016 and 2015, respectively. At Dec. 31, 2017, the estimated future payments for capacity that SPS is obligated to purchase pursuant to these executory contracts, subject to availability, are as follows:
(Millions of Dollars) Capacity
2018 $58
2019 20
2020 12
2021 12
2022 13
Thereafter 18
Total $133

Additional energy payments under these PPAs and PPAs accounted for as operating leases will be required to meet expected future electric demand.

Leases— SPS leases a variety of equipment and facilities. These leases, primarily for office space, generating facilities, vehicles, aircraft and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations were approximately $58 million, $57 million and $55 million for 2017, 2016 and 2015, respectively. These expenses include capacity payments for PPAs accounted for as operating leases of $51 million, $51 million and $49 million in 2017, 2016 and 2015, respectively, recorded to electric fuel and purchased power expenses.


Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases in accordance with the applicable accounting guidance. Future commitments under operating leases are:
(Millions of Dollars) Operating
Leases		 
        PPA (a) (b)
Operating
Leases
 Total
Operating
Leases
2018 $5
 $52
 $57
2019 5
 51
 56
2020 5
 51
 56
2021 5
 51
 56
2022 5
 51
 56
Thereafter 61
 543
 604

(a)
Amounts do not include PPAs accounted for as executory contracts.
(b)
PPA operating leases contractually expire through 2033.

Variable Interest Entities— The accounting guidance for consolidation of variable interest entities requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an enterprise is a variable interest entity’s primary beneficiary.

PPAs — Under certain PPAs, SPS purchases power from independent power producing entities for which SPS is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which SPS procures the natural gas required to produce the energy that it purchases. In addition, certain solar PPAs provide SPS with 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 independent power producing entity.

SPS has determined that certain independent power producing entities are variable interest entities. SPS is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is required to be provided other than contractual payments for energy and capacity set forth in the PPAs.

SPS has evaluated each of these variable interest entities 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 has 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 897 MW of capacity under long-term PPAs at both Dec. 31, 2017 and 2016 with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2041.

Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk electric generating stations from TUCO under contracts for those facilities that 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.

No significant financial support has been, or is required to be provided to TUCO by SPS, other than contractual payments for delivered coal. However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of certain fuel procurement costs. SPS has determined that TUCO is a variable interest entity. 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.

Environmental Contingencies

SPS has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, SPS believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, SPS is pursuing, or intends to pursue, recovery from other PRPs and through the regulated rate process. New and changing federal and state environmental mandates can also create added financial liabilities for SPS, which are normally recovered through the regulated rate process. To the extent any costs are not recovered through the options listed above, SPS would be required to recognize an expense.


Site Remediation — Various federal and state environmental laws impose liability, without regard to the legality of the original conduct, 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 or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former manufactured gas plants operated by SPS, its predecessors, or other entities; and third-party sites, such as landfills, for which SPS is alleged to be a PRP that sent wastes to that site.

MGP, Landfill or Disposal Sites— SPS is currently involved in investigating and/or remediating an MGP, landfill or other disposal site. SPS has identified one site where contamination is present and where investigation and/or remediation activities are currently underway. Other parties may have responsibility for some portion of the investigation and/or remediation activities that are underway. SPS anticipates that the investigation or remediation activities will continue through at least 2018. SPS has accrued $0.1 million for the site as of Dec. 31, 2017 and 2016, respectively. There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred. SPS anticipates that any amounts spent will be fully recovered from customers.

Environmental Requirements

Water and Waste
Asbestos Removal — Some of SPS’ facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. SPS has recorded an estimate for final removal of the asbestos as an ARO. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is not expected to be material and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Federal CWA Waters of the United States Rule —In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) published a final rule that significantly expanded the types of water bodies regulated under the CWA and broadened the scope of waters subject to federal jurisdiction. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule.  In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected in 2018.

In February 2017, President Trump issued an executive order requiring the EPA and the Corps to review and revise the final rule. On June 2017, the agencies issued a proposed rule that rescinds the final rule and reinstates the prior definition of “Water of the U.S.” The agencies are also undertaking a rulemaking to develop a new definition of “Waters of the U.S.”

Federal CWA Effluent Limitations Guidelines (ELG) — In 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals.  In 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport until November 2020 while the agency conducts a rulemaking process to potentially revise the effluent limitations and pretreatment standards for these waste streams.

Air
GHG Emission Standard for Existing Sources (CPP) — In 2015, the EPA issued its final CPP rule for existing power plants.  Among other things, the CPP requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim and final emission performance targets. 

The CPP was challenged by multiple parties in the D.C. Circuit Court.  In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. The stay will remain in effect until the D.C. Circuit Court reaches its decision and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a decision of its own.

In March 2017, President Trump signed an executive order requiring the EPA Administrator to review the CPP rule and if appropriate publish proposed rules suspending, revising or rescinding it. Accordingly, the EPA requested that the D.C. Circuit Court hold the litigation in abeyance until the EPA completes its work under the executive order. The D.C. Circuit granted the EPA’s request and is holding the litigation in abeyance, while considering briefs by the parties on whether the court should remand the challenges to the EPA rather than holding them in abeyance, determining whether and how the court continues or ends the stay that currently applies to the CPP.

In October 2017, the EPA published a proposed rule to repeal the CPP, based on an analysis that the CPP exceeds the EPA’s statutory authority under the CAA. In the proposal, the EPA stated it has not yet determined whether it will promulgate a new rule to regulate GHG emissions from existing EGUs. In December 2017, the EPA issued an Advanced Notice of Proposed Rulemaking to take and consider comments on whether to issue a future rule and what such a rule should include.

CSAPR — CSAPR addresses long range transport of PM and ozone by requiring reductions in SO2 and NOx from utilities in the eastern half of the United States, including Texas, using an emissions trading program.

CSAPR was adopted to address interstate emissions impacting downwind states’ attainment of the ozone and particulate NAAQS. As the EPA revises NAAQS, it will consider whether to make any further reductions to CSAPR emission budgets and whether to change which states are included in the emissions trading program.

In September 2017, the EPA adopted a final rule that withdraws Texas from the CSAPR particle program and determines that further emission reductions in Texas are not needed to address interstate particle transport. Texas is no longer subject to the annual SO2 and NOX emission budgets under CSAPR. In November 2017, the National Parks Conservation Association and Sierra Club appealed this rule to the D.C. Circuit Court. In January 2018, the Court granted SPS’ motion to intervene in support of the EPA’s final rule.

Regional Haze Rules — The regional haze program requires SO2, NOX and PM emission controls at power plants and other industrial facilities to reduce visibility impairment in national parks and wilderness areas. The program is divided into two parts: BART and reasonable further progress. Texas’ first regional haze plan has undergone federal review as described below.

BART Determination for Texas: The EPA published a proposed BART rule for Texas in January 2017 that could have required installation of dry scrubbers to reduce SO2 emissions from Harrington Units 1 and 2. Investment costs associated with dry scrubbers for Harrington Units 1 and 2 could have been approximately $400 million. In October 2017, the EPA 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 from units in 2019 and future years. The anticipated costs of compliance are not expected to have a material impact on the results of operations, financial position or cash flows; 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 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 matter is now submitted to the court.

In December 2017, the National Parks Conservation Association, Sierra Club, and Environmental Defense Fund appealed the EPA’s October 2017 final BART rule to the Fifth Circuit, and filed a petition for administrative reconsideration of the final rule with the EPA. In January 2018, the court granted SPS’ motion to intervene in the Fifth Circuit litigation in support of the EPA’s final rule.

Reasonable Progress Rule: In January 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 approximately $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 of the regional haze program. The risk of these controls being imposed along with the risk of investments to provide additional cooling water to Tolk have caused SPS to seek to decrease the remaining depreciable life of the Tolk units. The EPA has not announced a schedule for acting on the remanded rule.

Implementation of the NAAQS for SO2 — The EPA adopted a more stringent NAAQS for SO2 in 2010, and evaluated areas in three phases. In December 2017, the EPA adopted a final rule that completed its initial designations of areas attaining or not attaining the standard. The EPA’s final actions designate all areas near SPS generating plants as meeting the SO2 NAAQS with one exception. In June 2016, 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 Texas Commission on Environmental Quality (TCEQ) will need to develop an implementation plan, which would be due by 2022, 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 or require upgrades 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 position or cash flows.

Revisions to the NAAQS for Ozone— In 2015, the EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75 parts per billion (ppb) to 70 ppb. In November 2017, the EPA published final designations of areas that meet the 2015 ozone standard. SPS meets the 2015 ozone standard in all areas where its generating units operate.

Asset Retirement Obligations

Recorded AROs — AROs have been recorded for property related to the following: electric steam and other production, electric distribution and transmission, and general property. The electric production obligations include asbestos, processed water containment facilities which are included under the category of ash-containment, storage tanks and control panels. The asbestos recognition associated with electric production includes certain specific plants.

SPS recognized AROs for the removal of electric transmission and distribution equipment, which consists of obligations associated with polychlorinated biphenyl, mineral oil, mercury and street lighting lamps. The electric general ARO includes small obligations related to storage tanks.

A reconciliation of SPS’ AROs for the years ended Dec. 31, 2017 and 2016 is as follows:
(Thousands of Dollars) Beginning Balance Jan. 1, 2017 Accretion 
Cash Flow
Revisions (a)
 
Ending Balance
    Dec. 31, 2017 (b)
Electric plant        
Steam production asbestos $19,070
 $1,155
 $(1,676) $18,549
Electric distribution 6,799
 249
 —
 7,048
Steam production ash containment 1,593
 85
 —
 1,678
Other 1,201
 48
 —
 1,249
Total liability $28,663
 $1,537
 $(1,676) $28,524
(a)
In 2017, an asbestos ARO was revised for changes in timing of estimated cash flows.
(b)
There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2017.

(Thousands of Dollars) Beginning Balance Jan. 1, 2016 Accretion 
Cash Flow
Revisions
 
Ending Balance
    Dec. 31, 2016 (a)
Electric plant        
Steam production asbestos $17,981
 $1,089
 $—
 $19,070
Steam production ash containment 1,513
 80
 —
 1,593
Electric distribution 6,559
 240
 —
 6,799
Other 1,180
 42
 (21) 1,201
Total liability $27,233
 $1,451
 $(21) $28,663

(a)
There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2016.

Indeterminate AROs — Outside of the known and 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 amount of asbestos or cost of removal could be determined as of Dec. 31, 2017. Therefore, an ARO has not been recorded for these facilities.

Removal Costs — SPS records a regulatory liability for the plant removal costs of generation, transmission and distribution facilities that are recovered currently in rates. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long time periods over which the amounts were accrued and the changing of rates over time, SPS has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accordingly, the recorded amounts of estimated future removal costs are considered regulatory liabilities. Removal costs as of Dec. 31, 2017 and 2016 were $197 million and $209 million, respectively.

Legal Contingencies

SPS is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation.
Management is sometimesmay be unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.


For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on SPS’ financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Rate Matters
Other ContingenciesTexas 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.

See Note 10
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 discussion.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.







12.Regulatory Assets and Liabilities

AROs — AROs have been recorded for SPS’ assets.
SPS’ financial statements are prepared in accordance with the applicable accounting guidance,AROs were as discussed in Note 1. Under this guidance, 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. If changes in the utility industry or the business of SPS no longer allow for the application of regulatory accounting guidance under GAAP, SPS would be required to recognize the write-off of regulatory assets and liabilities in net income or OCI.

The components of regulatory assets shown on the balance sheets of SPS at Dec. 31, 2017 and 2016 are:follows:
(Thousands of Dollars) See
Note(s)		 Remaining
Amortization Period		 Dec. 31, 2017 Dec. 31, 2016
Regulatory Assets     Current Noncurrent Current Noncurrent
Pension and retiree medical obligations (a)
7
 Various $12,752
 $223,038
 $13,986
 $234,171
Excess deferred taxes - TCJA 6
 Various —
 44,685
 —
 —
Net AROs (b)
 11
 Plant lives —
 24,201
 —
 24,352
Recoverable deferred taxes on AFUDC recorded in plant (c)
 1
 Plant lives —
 23,888
 —
 44,258
Losses on reacquired debt 4
 Term of related debt807
 22,664
 127
 1,617
Renewable resources and environmental initiatives 11
 One to three years 1,600
 1,301
 3,580
 2,900
Conservation programs (d)
 1
 One to two years 2,674
 733
 3,754
 2,431
Other   Various 13,705
 22,433
 17,274
 36,954
Total regulatory assets     $31,538
 $362,943
 $38,721
 $346,683

  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) 
IncludesAmounts incurred related to the non-qualified pension plan.Hale wind farm placed in service in 2019.
(b) 
Includes amounts recorded for future recovery of AROs.Amounts settled related to asbestos abatement projects.
(c) 
Includes a write-downIn 2019, AROs were revised for changes in timing and estimates of $23.2 million as a resultcash 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 the revaluation of deferred tax gross up at the new federal tax rate at Dec. 31, 2017.cash flows. Changes in electric distribution AROs were primarily related to increased labor costs.
(d)(b) 
Includes costs for conservation programs, as well as incentives allowedThere were no ARO amounts incurred or settled in certain jurisdictions.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.
The
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 regulatory liabilities shownlease 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 sheetssheet.
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 SPS at Dec. 31, 2017 and 2016 are:lease expense:
(Thousands of Dollars) See
Note(s)		 Remaining
Amortization Period		 Dec. 31, 2017 Dec. 31, 2016
Regulatory Liabilities     Current Noncurrent Current Noncurrent
Excess deferred taxes - TCJA (a)
 6
 Various $—
 $563,662
 $—
 $—
Plant removal costs 11
 Plant lives —
 196,875
 —
 208,638
Revenue subject to refund 10
 One to two years 6,825
 6,503
 5,093
 3,602
Gain from asset sales 10
 Various —
 2,476
 —
 2,530
Deferred electric energy costs 1
 Less than one year 48,460
 —
 32,451
 —
Contract valuation adjustments (b)
 1, 9
 Term of related contract 12,723
 —
 1,955
 —
Other   Various 827
 15,048
 2,078
 18,684
Total regulatory liabilities     $68,835
 $784,564
 $41,577
 $233,454

(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) 
Primarily relates to the revaluationIncludes short-term lease expense of recoverable/regulated plant ADIT$1.5 million, $1.1 million and $28.0$1.2 million revaluation impact of non-plant ADIT at Dec. 31, 2017.for 2019, 2018 and 2017, respectively.
(b) 
IncludesPPA capacity payments are included in electric fuel and purchased power on the fair valuestatements of certain long-term PPAs used to meet energy capacity requirements.income. Expense for other operating leases is included in O&M expense.

AtCommitments under operating leases as of Dec. 31, 2017 and 2016, approximately $64 million and $65 million of SPS’ regulatory assets represented past expenditures not currently earning a return, respectively. This amount primarily includes formula rates, loss on reacquired debt and certain expenditures associated rate cases.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
13.
(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.

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, 2017 and 2016 were as follows: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)
  Year Ended Dec. 31, 2017
(Thousands of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total
Accumulated other comprehensive loss at Jan. 1 $(678) $(612) $(1,290)
Losses reclassified from net accumulated other comprehensive loss 39
 44
 83
Net current period other comprehensive income 39
 44
 83
       
Adoption of ASU No. 2018-02 (a)
 (137) (123) (260)
Accumulated other comprehensive loss at Dec. 31 $(776) $(691) $(1,467)

(a) 
In 2017, SPS implemented ASU No. 2018-02 related to the TCJA, which resulted in reclassification of certain credit balances within accumulated other comprehensive loss to retained earnings. For further information, see Note 2.

  Year Ended Dec. 31, 2016
(Thousands of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total
Accumulated other comprehensive loss at Jan. 1 $(817) $(464) $(1,281)
Other comprehensive loss before reclassifications —
 (148) (148)
Losses reclassified from net accumulated other comprehensive loss 139
 —
 139
Net current period other comprehensive income (loss) 139
 (148) (9)
Accumulated other comprehensive loss at Dec. 31 $(678) $(612) $(1,290)


Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2017 and 2016 were as follows:
  Amounts Reclassified from Accumulated
Other Comprehensive Loss		 
(Thousands of Dollars) Year Ended Dec. 31, 2017 Year Ended Dec. 31, 2016 
Losses on cash flow hedges:     
Interest rate derivatives $63
(a) 
$219
(a) 
Total, pre-tax 63
 219
 
Tax benefit (24) (80) 
Total, net of tax 39
 139
 
Defined benefit pension and postretirement losses:     
Amortization of net loss 69
(b) 
—
(b) 
Total, pre-tax 69
 —
 
Tax benefit (25) —
 
Total, net of tax 44
 —
 
Total amounts reclassified, net of tax $83
 $139
 

(a)
Included in interest charges.
(b)
Included in the computation of net periodic pension and postretirement benefit costs. See Note 79 for details regarding these benefit plans.further information.

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

 

 

Interest rate derivatives (net of taxes of $0) 0.1
(a) 
—
 0.1
Net current period other comprehensive income 0.1
 —
 0.1
Accumulated other comprehensive loss at Dec. 31 $(0.7) $(0.7) $(1.4)


14.
(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 45 for further discussion of this borrowing arrangement.information.

The table below contains significantSignificant 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
 —
(Thousands of Dollars) 2017 2016 2015
Operating revenues:      
Electric $2
 $56
 $—
Operating expenses:      
Purchased power 1,436
 8,809
 8,632
Other operating expenses — paid to Xcel Energy Services Inc. 196,558
 188,175
 197,134
Interest expense —
 189
 156
Interest income —
 —
 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

  2017 2016
(Thousands of Dollars) Accounts
Receivable		 Accounts
Payable		 Accounts
Receivable		 Accounts
Payable
NSP-Minnesota $964
 $—
 $935
 $—
NSP-Wisconsin 7
 —
 —
 333
PSCo —
 279
 —
 745
Other subsidiaries of Xcel Energy Inc. 326
 22,298
 14
 13,336
  $1,297
 $22,577
 $949
 $14,414


15.
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
(Thousands of Dollars) March 31, 2017 June 30, 2017 Sept. 30, 2017 Dec. 31, 2017
Operating revenues $460,072
 $479,796
 $551,623
 $426,509
Operating income 58,415
 74,489
 122,407
 41,498
Net income 25,055
 35,362
 67,781
 31,015
  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.
  Quarter Ended
(Thousands of Dollars) March 31, 2016 June 30, 2016 Sept. 30, 2016 Dec. 31, 2016
Operating revenues $390,839
 $440,445
 $554,926
 $464,749
Operating income 53,569
 68,386
 122,362
 62,964
Net income 22,523
 32,211
 68,346
 29,077
ITEM 9 — CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

ITEM 9A — CONTROLS AND PROCEDURES
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 the 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 chief executive officer (CEO)CEO and chief financial officer (CFO),CFO, allowing timely decisions regarding required disclosure. As of Dec. 31, 2017,2019, 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 the procedures, the CEO and CFO have concluded that SPS’ disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No changechanges in SPS’ internal control over financial reporting has occurred during SPS’ most recent fiscal quarter that has materially affected, or isare 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, 2017,2019 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, and as approved by the SEC and as indicated in SPS’ Management Report on Internal Controls herein.

In 2016, SPS implemented the general ledger modules of a new enterprise resource planning system to improve certain financial and related transaction processes. SPS initiated and implemented additional work management systems modulesover Financial Reporting, which is contained in 2017. SPS updated its internal control over financial reporting, as necessary, to accommodate modifications to its business processes and accounting systems. SPS does not believe that this implementation had an adverse effect on its internal control over financial reporting.

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
ITEM 9B — OTHER INFORMATION
None.

None.


PART III

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

ITEM 10 — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10 — Directors, Executive Officers and Corporate Governance

ITEM 11 — EXECUTIVE COMPENSATION
Item 11 — Executive Compensation

ITEM 12 — SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13 — Certain Relationships and Related Transactions, and Director Independence

ITEM 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 20182020 Annual Meeting of Shareholders,
which is incorporated by reference.

Item 14 — Principal Accountant Fees and Services

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 the 2018its 2020 Annual Meeting of StockholdersShareholders which
definitive Proxy Statement is expected to be filed with the SEC on or about April 3, 2018.6, 2020. Such information set forth under such
heading is incorporated herein by this reference hereto.

PART IV

Item 15 — Exhibits, Financial Statement Schedules
ITEM 15 — EXHIBITS, FINANCIAL STATEMENT SCHEDULES
1.1Financial Statements
 Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2017.2019.
 
Report of Independent Registered Public Accounting Firm — Financial Statements
 
Statements of Income — For the three years ended Dec. 31, 2017, 20162019, 2018 and 2015.2017.
 
Statements of Comprehensive Income — For the three years ended Dec. 31, 2017, 20162019, 2018 and 2015.2017.
 
Statements of Cash Flows — For the three years ended Dec. 31, 2017, 20162019, 2018 and 2015.2017.
 
Balance Sheets — As of Dec. 31, 20172019 and 2016.2018.
 
Statements of Common Stockholder’s Equity — For the three years ended Dec. 31, 2017, 20162019, 2018 and 2015.2017.
Statements of Capitalization — As of Dec. 31, 2017 and 2016.
  
2.2
Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2017, 20162019, 2018 and 2015.2017.
  
3.3Exhibits
*Indicates incorporation by reference
+Executive Compensation ArrangementsAgreements and Benefit Plans Covering Executive Officers and Directors
Exhibit NumberDescriptionReport or Registration StatementSEC File or Registration NumberExhibit Reference
3.01*
Amended and Restated Articles of Incorporation dated Sept. 30, 1997 (Exhibit 3.01 to
SPS Form 10-Q for the quarter ended Sept. 30, 2017 (file no. 001-03789)).001-037893.01
3.02*
By-Laws of SPS as Amended and Restated on Sept. 26, 2013. (Exhibit 3.02 toJan. 25, 2019
SPS Form 10-Q/A10-K for the quarteryear ended Sept. 30, 2013 (file no. 001-03789)).Dec. 31, 2018001-037893.02
4.01*
Indenture dated Feb. 1, 1999 between SPS and Thethe Chase Manhattan Bank (Exhibit 99.2 to
SPS Form 8-K (file no. 001-03789) dated Feb. 25, 1999).1999001-0378999.2
4.02*
Third Supplemental Indenture dated Oct. 1, 2003 to the indenture dated Feb. 1, 1999 between SPS and JPMorgan Chase Bank, as successor Trustee, creating $100 million principal amount of 6% Series C and Series D Notes 6 percent due 2033 (Exhibit 4.04 to
Xcel Energy Inc. Form 10-Q (file no. 001-03034) for the quarter ended Sept. 30, 2003).2003001-030344.04
4.03*
Fourth Supplemental Indenture dated Oct. 1, 2006 between SPS and Thethe Bank of New York, as successor Trustee, (Exhibit 4.01 tocreating $200 million principal amount of 5.6% Series E Notes due 2016 and $250 million principal amount of 6% Series F Notes due 2036
SPS Form 8-K (file no. 001-03789) dated Oct. 3, 2006).

2006001-037894.01
4.064.04*
Indenture dated as of Aug. 1, 2011 between SPS and U.S,U.S. Bank National Association, as Trustee  (Exhibit 4.01 to
SPS Form 8-K dated Aug. 10, 2011 (file no. 001-03789)).001-037894.01
4.074.05*
Supplemental Indenture dated as of Aug. 3, 2011 between SPS and U.S. Bank National Association, as Trustee, creating $200 million principal amount of 4.50 percent4.50% First Mortgage Bonds, Series No. 1 due 2041  (Exhibit 4.02 to
SPS Form 8-K dated Aug. 10, 2011 (file no. 001-03789)).001-037894.02
4.084.06*
Sixth Supplemental Indenture dated as of June 1, 2014 between SPS and The Bank of New York Mellon Trust Company, N.A., as successor Trustee. (Exhibit 4.03 to SPS’ Form 8-K dated June 2, 2014 (file no. 001-03789)).
4.10*
Supplemental Indenture No. 3 dated as of June 1, 2014 between SPS and U.S. Bank National Association, as Trustee, creating $150 million principal amount of 3.30 percent3.30% First Mortgage Bonds, Series No. 3 due 2024. (Exhibit 4.02 to SPS’2024
SPS Form 8-K dated June 9, 2014 (file no. 001-03789)).001-037894.02
4.114.07*
Supplemental Indenture dated as of Aug. 1, 2016 between SPS and U.S. Bank National Association, as Trustee, creating $300 million principal amount of 3.40 percent3.40% First Mortgage Bonds, Series No. 4 due 2046. (Exhibit 4.02 to2046
SPS Form 8-K of SPS dated Aug. 12, 2016 (file no. 001-03789)).001-037894.02
4.124.08*
Supplemental Indenture dated as of Aug. 1, 2017 between SPS and U.S. Bank National Association, as Trustee, creating $450 million principal amount of 3.70 percent3.70% First Mortgage Bonds, Series No. 5 due 2047. (Exhibit 4.02 to2047
SPS Form 8-K of SPS dated Aug. 9, 2017 (file no. 001-03789)).001-037894.02

10.014.09*+
Supplemental Indenture dated as of Oct. 1, 2018 between SPS and U.S. Bank National Association, as Trustee, creating $300 million principal amount of 4.40% First Mortgage Bonds, Series due 2048
SPS Form 8-K dated Nov. 5, 2018001-037894.02
4.10*
Supplemental Indenture dated as of June 1, 2019 between SPS and U.S. Bank National Association, as Trustee, creating $300 million principal amount of 3.75% First Mortgage Bonds, Series due 2049
SPS Form 8-K dated June 18, 2019001-037894.02
10.01*+
Xcel Energy Inc. Nonqualified Pension Plan (2009 Restatement) (Exhibit 10.02 to
Xcel Energy Inc. Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).2008001-0303410.02
10.02*+
Xcel Energy Senior Executive Severance and Change-in-Control Policy (2009 Amendment and Restatement) (Exhibit 10.05 to
Xcel Energy Inc. Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).2008001-0303410.05
10.03*+
Xcel Energy Inc. Non-Employee Directors Deferred Compensation Plan as amended and restated on Jan. 1, 2009 (Exhibit 10.08 to
Xcel Energy Inc. Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).2008001-0303410.08
10.04*+
Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to
Xcel Energy Inc. Form U5B (file no. 001-03034) dated Nov. 16, 2000).2000001-03034H-1
10.05*+
Xcel Energy Inc. Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 (Exhibit 10.17 to
Xcel Energy Inc. Form 10-K of Xcel Energy  (file no. 001-03034) for the year ended Dec. 31, 2008).2008001-0303410.17
10.06*+
First Amendment to Exhibit 10.02 dated Aug. 26, 2009 to the
Xcel Energy Senior Executive Severance and Change-in-Control Policy  (Exhibit 10.06 toInc. Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).2009001-0303410.06
10.07*+
Xcel Energy Inc. Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.08 to
Xcel Energy Inc. Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).2009001-0303410.08
10.08*+
Xcel Energy Inc. Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix A to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).
10.09*+
Xcel Energy Inc. 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix B to Schedule 14A,
Xcel Energy Inc. Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).2010001-03034Appendix A
10.1010.09*+
Stock Equivalent Plan for Non-Employee Directors of Xcel Energy Inc. as amended and restated effective Feb. 23, 2011 (Appendix A to the
Xcel Energy Inc. Definitive Proxy Statement (file no. 001-03034) filed Apr.dated April 5, 2011).2011001-03034Appendix A
10.1110.10*+
Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.07 to
Xcel Energy Inc. Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).2008001-0303410.07
10.1210.11*+
Second Amendment to Exhibit 10.02 dated Oct. 26, 2011 to the
Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.18 toInc. Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011).2011001-0303410.18
10.1310.12*+
First Amendment to Exhibit 10.10 effective Nov. 29, 2011 to the
Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011).2011001-0303410.17
10.1410.13*+
First Amendment to Exhibit 10.08 dated Feb. 20, 2013 to the
Xcel Energy Inc. Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended March 31, 2013).2013001-0303410.01
10.1510.14*+
Fourth Amendment to Exhibit 10.02 dated Feb. 20, 2013 to the
Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.02 toInc. Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended March 31, 2013).2013001-0303410.02
10.1610.15*+
FirstSecond Amendment to Exhibit 10.10 dated May 21, 2013 to the
Xcel Energy Inc. 2005 Long Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.21 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013).2013001-0303410.22
10.1710.16*+
Second Amendment dated May 21, 2013 to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.22 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013).
10.18*+
Xcel Energy Inc. 2005 Long-Term Incentive Plan Form of Long-Term Incentive Award Agreement (Exhibit 10.23 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013).

10.19*+
Xcel Energy Inc. 2015 Omnibus Incentive Plan (incorporated by reference to Appendix B to Schedule 14A, Definitive Proxy Statement to Xcel Energy Inc. (file no. 001-03034) dated April 6, 2015).
10.20*+
Stock Equivalent Program for Non-Employee Directors of Xcel Energy Inc. (As First Effective May 20, 2015) under the Xcel Energy Inc. 2015 Omnibus Incentive Plan. (Exhibit 10.02 toPlan
Xcel Energy Inc. Form 8-K of Xcel Energy, dated May 26,20, 2015 (file no. 001-03034).001-0303410.02
10.2110.17*+
Fifth Amendment Exhibit 10.02 dated May 3, 2016
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2016001-0303410.01
10.18*+
Third Amendment to Exhibit 10.10 dated Sept. 30, 2016
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016001-0303410.01
10.19*+
Fourth Amendment to Exhibit 10.11 dated Oct. 23, 2017
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017001-0303410.1
10.20*+
Sixth Amendment to Exhibit 10.02 dated Feb. 22, 2018
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017001-0303410.30
10.21*+
Seventh Amendment to Exhibit 10.02 dated May 7, 2018
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018001-0303410.01
10.22*+
Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018001-0303410.34
10.23*+
Form of Xcel Energy Inc. 2015 Omnibus Incentive Plan Award Agreement and Award Terms and Conditions (Restricted Stock Units and Performance Share Units) under the Xcel Energy Inc. 2015 Omnibus Incentive Plan. (Exhibit 10.03 to Form 8-K of Xcel Energy, dated May 26, 2015 (file no. 001-03034).
10.22*+

Xcel Energy Inc.Amended and Restated 2015 Omnibus Incentive Plan Form of Award Agreement. (Exhibit 10.28 to Form 10-K of
Xcel Energy (file no. 001-03034)Inc. Form 10-K for the year ended Dec. 31, 2015).2018001-0303410.35
10.2310.24*+
Stock Program for Non-Employee Directors of Xcel Energy Inc. Executive Annualas Amended and Restated on Dec. 12, 2017 under the 2015 Omnibus Incentive Award Sub-plan pursuant to the Plan
Xcel Energy Inc. 2015 Omnibus Incentive Plan. (Exhibit 10.29 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2015).2018001-0303410.36
10.2410.25*+
Fifth Amendment dated May 3, 2016 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended June 30, 2016).
10.25*
SecondThird Amended and Restated Credit Agreement, dated as of June 20, 20167, 2019 among SPS, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, MUFG Bank, Ltd., and The Bank of Tokyo-Mitsubishi UFJ, Ltd.Citibank, N.A., as Documentation Agents. (Exhibit 99.04 toAgents
Xcel Energy Inc. Form 8-K of Xcel Energy dated June 20, 2016 (file no. 001-03034)).7, 2019001-0303499.04
10.26*+
Third Amendment dated Sept. 30, 2016 to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2016).
10.27*+
Form of Xcel Energy Inc. 2015 Omnibus Incentive Plan Award Agreement and Award Terms and Conditions (Restricted Stock Units and Performance Share Units) under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan. (Exhibit 10.27 toPlan
Xcel Energy Inc. Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2016).2019001-0303410.33
10.28*+
Fourth Amendment to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.1 to Form 10-Q of Xcel Energy for the quarter ended Sept. 30, 2017 (file no. 001-03034)).
10.29*+
Sixth Amendment dated Feb. 22, 2018 to Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.30 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2017.
12.0123.01
Statement of Computation of Ratio of Earnings to Fixed Charges.
23.01
Consent of Independent Registered Public Accounting Firm.
31.01
Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02
Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01
101.INS
Statement pursuant to Private Securities Litigation Reform Act of 1995.
XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101101.SCHThe following materials from SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2017 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Statements of Income, (ii) the Statements of Comprehensive Income, (iii) the Statements of Cash Flows, (iv) the Balance Sheets, (v) the Statements of Stockholder’s Equity, (vi) the Statements of Capitalization, (vii) Notes to Financial Statements, (viii) document and entity information, and (ix) Schedule II.Schema
101.CALXBRL Calculation
101.DEFXBRL Definition
101.LABXBRL Label


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.Southwestern Public Service Co. Valuation and Qualifying Accounts Years Ended Dec. 31 2017, 2016 AND 2015
(amounts in thousands)
    Additions    
  
Balance at
Jan. 1
 
Charged to
Costs and
Expenses
 
Charged to
Other
Accounts(a)
 
Deductions
from
Reserves (b)
 
Balance at
Dec. 31
Allowance for bad debts:          
2017 $6,379
 $5,091
 $1,169
 $6,291
 $6,348
2016 5,888
 6,066
 907
 6,482
 6,379
2015 5,839
 4,655
 1,036
 5,642
 5,888

  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 relaterelated primarily to bad debt write-offs.

Item 16 — Form 10-K Summary
ITEM 16 — FORM 10-K SUMMARY
None.

None.


SIGNATURES

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. 23, 201821, 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/ MARVIN E. MCDANIEL, JR.DAVID L. EVES  
Marvin E. McDaniel, Jr.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.




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