10-K

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, 2017

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

(Exact name of registrant as specified in its charter)

New Mexico	75-0575400
State or other jurisdiction of incorporation or organization	(I.R.S. Employer Identification No.)

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

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

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  ¨ Yes 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 and 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,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act

Large accelerated filer ¨	Accelerated filer ¨
Non-accelerated filer 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, 2018, 100 shares of common stock, par value $1 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 2018 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 3, 2018. 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 TERMS	3
COMPANY OVERVIEW	5
ELECTRIC UTILITY OPERATIONS	5
Public Utility Regulation	5
Capacity and Demand	6
Energy Sources and Related Transmission Initiatives	6
Fuel Supply and Costs	7
Fuel Sources	7
Renewable Energy Sources	8
Wholesale Commodity Marketing Operations	8
Summary of Recent Federal Regulatory Developments	9
Electric Operating Statistics	10
Natural Gas Facilities Used for Electric Generation	11
GENERAL	11
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	23
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	23
Item 6 — Selected Financial Data	23
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 7A — Quantitative and Qualitative Disclosures About Market Risk	25
Item 8 — Financial Statements and Supplementary Data	27
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	70
Item 9A — Controls and Procedures	70
Item 9B — Other Information	70
PART III	71
Item 10 — Directors, Executive Officers and Corporate Governance	71
Item 11 — Executive Compensation	71
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	71
Item 13 — Certain Relationships and Related Transactions, and Director Independence	71
Item 14 — Principal Accountant Fees and Services	71
PART IV	71
Item 15 — Exhibits, Financial Statement Schedules	71
Item 16 - Form 10-K Summary	77
SIGNATURES	75

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.

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PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
NCE	New Century Energies, Inc.
NSP-Minnesota	Northern States Power Company, a Minnesota corporation
NSP-Wisconsin	Northern States Power Company, a Wisconsin corporation
PSCo	Public Service Company of Colorado
SPS	Southwestern Public Service Company
Utility subsidiaries	NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
Xcel Energy	Xcel Energy Inc. and its subsidiaries
Federal and State Regulatory Agencies
CFTC	Commodity Futures Trading Commission
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
DOE	United States Department of Energy
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
IRS	Internal Revenue Service
NERC	North American Electric Reliability Corporation
NMPRC	New Mexico Public Regulation Commission
PHMSA	Pipeline and Hazardous Materials Safety Administration
PUCT	Public Utility Commission of Texas
SEC	Securities and Exchange Commission
Electric and Resource Adjustment Clauses
DCRF	Distribution cost recovery factor
DSM	Demand side management
EE	Energy efficiency
EECRF	Energy efficiency cost recovery factor
FPPCAC	Fuel and purchased power cost adjustment clause
PCRF	Power cost recovery factor
TCRF	Transmission cost recovery factor (recovers transmission infrastructure improvement costs and changes in wholesale transmission charges)
Other Terms and Abbreviations
AFUDC	Allowance for funds used during construction
ALJ	Administrative law judge
APBO	Accumulated postretirement benefit obligation
ARO	Asset retirement obligation
ASC	FASB Accounting Standards Codification
ASU	FASB Accounting Standards Update
BART	Best available retrofit technology
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
C&I	Commercial and Industrial
CO2	Carbon dioxide
CCN	Certificate of convenience and necessity
CPP	Clean Power Plan
CSAPR	Cross-State Air Pollution Rule
CWIP	Construction work in progress
EGU	Electric generating unit

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ERCOT	Electric Reliability Council of Texas
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
FTR	Financial transmission right
GAAP	Generally accepted accounting principles
GHG	Greenhouse gas
IPP	Independent power producers
IRC	Internal Revenue Code
ITC	Investment tax credit
MISO	Midcontinent Independent System Operator, Inc.
Moody’s	Moody’s Investor Services
NAAQS	National Ambient Air Quality Standard
Native load	Customer demand of retail and wholesale customers whereby a utility has an obligation to serve under statute or long-term contract.
NAV	Net asset value
NOL	Net operating loss
NOx	Nitrogen oxide
NTC	Notifications to construct
O&M	Operating and maintenance
OCI	Other comprehensive income
PJM	PJM Interconnection, LLC
PM	Particulate matter
PPA	Purchased power agreement
PRP	Potentially responsible party
PSIA	Pipeline system integrity adjustment
PTC	Production tax credit
PV	Photovoltaic
QF	Qualifying facilities
R&E	Research and experimentation
REC	Renewable energy credit
ROE	Return on equity
RPS	Renewable portfolio standards
RTO	Regional Transmission Organization
SIP	State implementation plan
SO2	Sulfur dioxide
SPP	Southwest Power Pool, Inc.
Standard & Poor’s	Standard & 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
Measurements
KV	Kilovolts
KWh	Kilowatt hours
MMBtu	Million British thermal units
MW	Megawatts
MWh	Megawatt hours

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COMPANY OVERVIEW

SPS was incorporated in 1921 under the laws of New Mexico.  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 percent of Xcel Energy’s consolidated net income.

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

ELECTRIC UTILITY OPERATIONS

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction— The PUCT and NMPRC regulate 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, and natural gas transactions in interstate commerce. As approved by the FERC, SPS is a transmission-owning member of the SPP RTO and operates within the SPP RTO and SPP IM wholesale market. SPS is authorized to make wholesale electric sales at market-based prices.

Fuel, Purchased Energy and Conservation Cost-Recovery Mechanisms— SPS has several retail adjustment clauses that recover fuel, purchased energy and other resource costs:

• DCRF — Recovers distribution costs in Texas that 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 monthly to recover the actual fuel and purchased power costs.

• PCRF — Allows recovery of certain purchased power costs in Texas that 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 Texas through a fixed fuel 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 provides for the over- or under-recovery of 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.

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.

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.

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Capacity and Demand

Uninterrupted system peak demand for SPS for each of the last three years and the forecast for 2018, assuming normal weather conditions, is as follows:

	System Peak Demand (in MW)
	2017	2016	2015	2018 Forecast
SPS	4,374	4,836	4,678	4,483

The peak demand 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.

Energy Sources and Related Transmission Initiatives

SPS expects to use existing electric generating stations, power purchases, DSM and new generation options to meet 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 the 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 known 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.

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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 did 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 PUCT 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.

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 delivered cost per MMBtu of each significant category of fuel consumed for owned electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.

	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

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

Fuel 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.

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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 and 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 percent 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.

Natural gas— SPS uses both firm and interruptible natural gas supply in combustion turbines and certain boilers. Natural gas for SPS’ power plants is 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 the 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 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 gas supply contracts were approximately $11 million 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.

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

Renewable Energy Sources

SPS’ renewable energy portfolio includes wind and solar power from 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 sales and 15.0 percent of New Mexico electric retail sales.

Renewable energy as a percentage of SPS’ total energy:

	2017		2016
Renewable	24.0	%	22.8	%
Wind	21.2		21.6
Solar	1.8		1.2

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.

Wind— 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 average cost per MWh of wind energy under the IPP contracts and QF tariffs was approximately $27 for 2017 and $25 for 2016. The cost per MWh of wind energy varies by contract and may be influenced by a number of factors including regulation, state-specific renewable resource requirements and the year of contract execution.  Generally, contracts executed in 2017 continued to benefit from improvements in technology, excess capacity among manufacturers, 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.

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 hedge sales and purchases. See Item 7 for further discussion.

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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.

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Electric Operating Statistics

Electric Sales Statistics

	Year Ended Dec. 31
	2017			2016			2015
Electric sales (Millions of KWh)
Residential	3,356			3,478			3,536
Large C&I	10,721			10,518			10,334
Small C&I	4,701			4,708			4,719
Public authorities and other	527			555			538
Total retail	19,305			19,259			19,127
Sales for resale	7,759			8,689			8,694
Total energy sold	27,064			27,948			27,821
Number of customers at end of period
Residential	306,248			305,076			304,711
Large C&I	221			219			221
Small C&I	77,351			77,319			77,238
Public authorities and other	6,316			6,377			6,354
Total retail	390,136			388,991			388,524
Wholesale	7			8			8
Total customers	390,143			388,999			388,532
Electric revenues (Thousands of Dollars)
Residential	$	367,234		$	343,475		$	347,966
Large C&I	516,786			462,576			445,853
Small C&I	375,961			322,599			353,450
Public authorities and other	48,045			44,892			42,963
Total retail	1,308,026			1,173,542			1,190,232
Wholesale	388,715			414,815			409,956
Other electric revenues	221,259			262,602			187,030
Total electric revenues	$	1,918,000		$	1,850,959		$	1,787,218
KWh sales per retail customer	49,483			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 KWh	4.82			4.40			4.31
Small C&I revenue per KWh	8.00			6.85			7.49
Total retail revenue per KWh	6.78			6.09			6.22
Wholesale revenue per KWh	5.01			4.77			4.72

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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
Coal	10,999	40	%	10,990	39	%	12,441	44	%
Natural Gas	9,950	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
Total	27,547	100	%	28,366	100	%	28,357	100	%
Owned generation	12,845	47	%	15,015	53	%	16,480	58	%
Purchased generation	14,702	53		13,351	47		11,877	42
Total	27,547	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.

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 demand for electric power is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, SPS’ operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. 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 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 promote the development of solar and other distributed energy resources through significant incentive policies; with these incentives and federal tax subsidies, distributed generating resources are potential competitors to SPS’ electric service business.

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The FERC has continued to promote competitive wholesale markets through open access transmission and other means. As a result, SPS can purchase generation resources from competing wholesale suppliers 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 1000 seeks to establish competition for construction and operation of certain new electric transmission facilities. SPS has franchise agreements with certain cities subject to periodic renewal. If 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. While facing these challenges, SPS believes its rates and services are competitive with currently available alternatives.

ENVIRONMENTAL MATTERS

SPS’ facilities are regulated by federal and state environmental agencies. These agencies 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’ facilities have been designed and constructed to operate in compliance with applicable environmental standards. 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 10 and 11 to the financial statements for further discussion.

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. SPS has undertaken a number of 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 the investments we have already made to reduce GHG emissions, or if they require additional initiatives or emission reductions, then their requirements would potentially impose additional substantial costs. SPS believes, based on prior state commission practice, it would recover the cost of these initiatives through rates.

EMPLOYEES

As of Dec. 31, 2017, SPS had 1,169 full-time employees and one part-time employee, of which 791 were covered under collective-bargaining agreements. See Note 7 to the financial statements for further discussion.

Item 1A — Risk Factors

Xcel Energy, which includes SPS, is subject to a variety of risks, many of which are beyond our control. Important risks that may adversely affect the business, financial condition and results of operations 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 the Board of Directors is the oversight of material risk, and our Board of Directors employs an effective process for doing so. Management and the Board of Directors have responsibility for overseeing the identification and mitigation of key risks.

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 domestic and global economies and the environment when identifying, assessing, managing and mitigating risk. Identification and analysis occurs formally through a key risk assessment process conducted by senior management, the financial disclosure process, the hazard risk management process and internal auditing and compliance with financial and operational controls. Management also identifies and analyzes risk through its business planning process and development of goals and key performance indicators, which include risk identification to determine barriers to implementing SPS’ strategy. The business planning process also identifies areas in which there is a potential for a business area to take inappropriate risk to meet goals, and determines how to prevent inappropriate risk-taking.

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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.

Management communicates regularly with the Board of Directors and key stakeholders regarding risk. Senior management presents a periodic assessment of key risks to the Board of Directors. The presentation and the discussion of the key risks provides the Board of Directors with information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability. Management also provides information to the Board of Directors in presentations and communications over the course of the year.

Overall, the Board of Directors approaches oversight, management and mitigation of risk as an integral and continuous part of its 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.

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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.

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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.

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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 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 and mechanical problems, which could cause substantial financial losses. Our electric 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 electric risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. We maintain insurance against some, but not all, of these risks and losses.

The occurrence of any of these events not fully covered by insurance could have a material effect on our financial position and results of operations. For our natural gas transmission lines located near populated areas, the level of potential damages resulting from these risks is greater.

Additionally, for natural gas the operating or other costs that may be required in order to comply with potential new regulations, including the Pipeline Safety Act, could be significant. The Pipeline Safety Act requires verification of 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. We have programs in place to comply with the Pipeline Safety Act and for systematic infrastructure monitoring and renewal over time. A significant incident could increase regulatory scrutiny and result in penalties and higher costs of operations.

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Our utility operations are subject to long-term planning 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. The electric utility sector is undergoing a period of significant change. For example, public policy has driven increases in appliance and lighting efficiency and energy efficient buildings, wider adoption and lower cost of renewable generation and distributed generation, including community solar gardens and customer-sited solar, shifts away from coal generation to decrease CO₂ emissions and increasing use of natural gas in electric generation driven by lower natural gas prices. Over time, customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources 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 which gives rise to a risk that the magnitude and timing of resource additions and growth in customer demand may not coincide, and that the preference for the types of additions may change from planning to execution. In addition, we are also 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.

We 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 credits are also needed to comply with various statutes and commission rulings associated with energy transactions. 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 settlements can vary significantly from estimated fair values recorded, and significant changes from the assumptions underlying our fair value estimates could cause earnings variability.

If we encounter market supply shortages or our suppliers are otherwise unable to meet their contractual obligations, we 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 potentially result in economic losses. Potential market supply shortages may not be fully resolved through alternative supply sources and may cause short-term disruptions in our ability to provide electric services to our customers. The impact of these cost and reliability issues depends on our operating conditions such as generation fuels mix, availability of water for cooling, availability of fuel transportation including rail shipments of coal, electric generation capacity, transmission, natural gas pipeline capacity, etc. Failure to provide service due to disruptions could also result in fines, penalties or cost disallowances through the regulatory process.

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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, Xcel Energy Inc. and its utility subsidiaries had approximately $14.5 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, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $19 million and immaterial exposure. Xcel Energy also had additional guarantees of $53 million at Dec. 31, 2017 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.

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 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 2017, 2016 and 2015 we paid $109 million, $85 million and $101 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 Item 5 for further discussion on dividend limitations.

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.

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In 2015, the 21^st 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 2^o Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5^o 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 expenditures could affect results of operations, cash flows and financial condition if such costs are not recovered through regulated rates.

Some states and localities have indicated a desire to continue to pursue climate policies even in the absence of federal mandates. All of the 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 standards under the CPP or the Paris Agreement, repeal of these policies would not impact those 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.

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 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, the NERC or the FERC for violations. Additionally, the PHMSA, the Occupational Safety and Health Administration and other federal agencies also have penalty authority. In the event of serious incidents, these agencies have become more active in pursuing penalties. Some states have the authority to impose substantial penalties in the event of non-compliance. If a serious reliability or safety incident did occur, it could have a material effect on our operations or financial results.

Macroeconomic Risks

Economic conditions impact our business.

Our operations are affected by local, national and worldwide economic conditions. Growth in our customer base is correlated with economic conditions. SPS serves a large number of petrochemical extraction and processing businesses in Texas 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 markets 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., which may impact our ability to acquire sufficient supplies. We operate in a capital intensive industry, and federal policy on trade could significantly impact the costs of the materials we use. We may be at risk for higher than anticipated inflation both with respect to our own workforce, as well as our materials and labor that we contract for with others. There may be delays before these higher costs can be recovered in rates.

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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 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. 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 they are implemented and clarified.

The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms.

A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, as well as our brand and reputation. Because our 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.

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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. While we have fuel clause 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 as compared with expenditures for fuel purchases could have an impact on our cash flows. Low fuel costs could have a positive impact on sales, though low oil 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.

Item 1B — Unresolved Staff Comments

None.

21

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

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

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2017:

Conductor Miles
345 KV	8,516
230 KV	9,608
115 KV	13,555
Less than 115 KV	24,795

SPS had 454 electric utility transmission and distribution substations at Dec. 31, 2017.

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

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 for a discussion of proceedings involving utility rates and other regulatory matters.

Item 4 — Mine Safety Disclosures

None.

22

PART II

Item 5 —Marketfor Registrant’s Common Equity, Related Stockholder Matters andIssuer Purchases 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 4 to the financial statements for further discussion of SPS’ dividend policy.

The dividends declared during 2017 and 2016 were as follows:

(Thousands of Dollars)	2017		2016
First quarter	$	26,715	$	25,645
Second quarter	25,014		19,388
Third quarter	26,166		27,498
Fourth quarter	26,753		30,870

Item 6 —Selected Financial Data

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

Item 7 —Management’s 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 of the results of operations set forth in general instructions I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Financial Review

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

23

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, as well as assumptions and other statements 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, 2017 (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 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

SPS’ net income was approximately $159 million for 2017, compared with net income of approximately $152 million for 2016. Rate increases in New Mexico and a lower ETR were partially offset by higher depreciation expense and O&M expenses.

Electric Revenues and Margins

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 electric revenues and margin:

(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 Revenues

(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

24

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

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 million, or 19.4 percent, for 2017 compared with 2016. The increase was primarily attributable to deferred depreciation expense from the 2016 Texas electric rate case and capital investments.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $6 million, or 10.0 percent, for 2017 compared with 2016. The increase was primarily due to higher property taxes in Texas.

Income Taxes — Income tax expense decreased $14 million for 2017 compared with 2016. The decrease in income tax expense was primarily due to the estimated one-time, non-cash, income tax benefit recognized in the fourth quarter related to the TCJA (see Note 6) and a net tax benefit related to the resolution 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.

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 9 to the financial statements for further discussion of market risks associated with derivatives.

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 nonperformance risk.

25

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 the fair value of the securities in the master pension trust, as well as SPS’ ability to earn a return on short-term investments of excess cash.

Commodity Price Risk — SPS is exposed to commodity price risk in its electric operations. Commodity price risk is managed by entering into short- and long-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.

Interest Rate Risk — SPS is subject to the risk of fluctuating interest rates in the normal course of business. 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, a 100-basis-point change in the benchmark rate on SPS’ variable rate debt would have no impact annual pretax interest expense, and at Dec. 31, 2016 a 100-basis-point change in the benchmark rate on SPS’ variable rate debt would impact annual pretax impact interest expense by approximately $0.5 million. See Note 9 to the financial statements for a discussion of SPS’ interest rate derivatives.

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, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $1.3 million, while a decrease in prices of 10 percent would have resulted in a decrease in credit exposure of $1.3 million. At Dec. 31, 2016, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $0.3 million, while a decrease in prices of 10 percent would have resulted in a decrease in credit exposure of $0.3 million.

SPS conducts standard credit reviews for all counterparties. 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. Distress in the financial markets could increase SPS’ credit risk.

Fair Value Measurements

SPS follows accounting and disclosure guidance on 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.

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. 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 own credit risk when determining the fair value of commodity derivative liabilities. The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair value of commodity derivative liabilities at Dec. 31, 2017.

26

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.

Item 8 — Financial Statements and Supplementary Data

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

See Note 15 to the financial statements for summarized quarterly financial data.

27

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. 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, 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	Executive Vice President, Chief Financial Officer
Feb. 23, 2018	Feb. 23, 2018

28

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the 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, 2017 and 2016, the related statements of income, comprehensive income, cash flows, and common stockholder’s equity, for each of the three years in the period ended December 31, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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, 2018

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

29

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF INCOME

(amounts in thousands of dollars)

	Year Ended Dec. 31
	2017			2016			2015
Operating revenues	$	1,918,000		$	1,850,959		$	1,787,218
Operating expenses
Electric fuel and purchased power	1,055,333			1,034,950			1,001,083
Operating and maintenance expenses	289,555			269,471			289,856
Demand side management program expenses	15,525			16,028			13,365
Depreciation and amortization	193,915			162,429			150,913
Taxes (other than income taxes)	66,863			60,800			57,536
Total operating expenses	1,621,191			1,543,678			1,512,753
Operating income	296,809			307,281			274,465
Other income (expense), net	2,359			91			(6		)
Allowance for funds used during construction — equity	9,310			9,981			7,378
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
Allowance for funds used during construction — debt	(5,384		)	(5,589		)	(4,491		)
Total interest charges and financing costs	80,849			83,082			79,549
Income before income taxes	227,629			234,271			202,288
Income taxes	68,416			82,114			75,025
Net income	$	159,213		$	152,157		$	127,263

See Notes to Financial Statements

30

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF COMPREHENSIVE INCOME

(amounts in thousands of dollars)

	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

See Notes to Financial Statements

31

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF CASH FLOWS

(amounts in thousands of dollars)

	Year Ended Dec. 31
	2017			2016			2015
Operating activities
Net income	$	159,213		$	152,157		$	127,263
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	193,870			162,957			153,241
Demand side management program amortization	1,673			1,673			1,673
Deferred income taxes	126,465			122,983			62,836
Amortization of investment tax credits	(133		)	(213		)	(213		)
Allowance for equity funds used during construction	(9,310		)	(9,981		)	(7,378		)
Provision for bad debts	5,091			6,066			4,655
Net derivative losses	63			217			268
Other	(28		)	122			(3,827		)
Changes in operating assets and liabilities:
Accounts receivable	(10,392		)	(8,868		)	(3,291		)
Accrued unbilled revenues	(10,386		)	(15,637		)	25,506
Inventories	(1,928		)	(959		)	5,686
Prepayments and other	4,267			22,651			(24,712		)
Accounts payable	11,836			13,776			(24,570		)
Net regulatory assets and liabilities	38,137			(55,689		)	26,452
Other current liabilities	3,427			5,156			(30,762		)
Pension and other employee benefit obligations	(21,679		)	(15,276		)	(9,405		)
Change in other noncurrent assets	(1,206		)	(200		)	2,352
Change in other noncurrent liabilities	(18,524		)	6,748			8,974
Net cash provided by operating activities	470,456			387,683			314,748
Investing activities
Utility capital/construction expenditures	(559,865		)	(512,522		)	(599,511		)
Allowance for equity funds used during construction	9,310			9,981			7,378
Proceeds from insurance recoveries	—			3,901			—
Investments in utility money pool arrangement	(142,000		)	(75,000		)	(92,000		)
Receipts from utility money pool arrangement	77,000			75,000			92,000
Other	(493		)	(1,174		)	3,136
Net cash used in investing activities	(616,048		)	(499,814		)	(588,997		)
Financing activities
(Repayment of) proceeds from short-term borrowings, net	(50,000		)	35,000			(22,000		)
Proceeds from issuance of long-term debt	442,338			295,985			198,496
Repayment of long-term debt, including reacquisition premiums	(271,613		)	(200,000		)	—
Borrowings under utility money pool arrangement	335,000			636,500			579,700
Repayments under utility money pool arrangement	(335,000		)	(636,500		)	(595,700		)
Capital contributions from parent	143,659			66,225			214,535
Dividends paid to parent	(108,765		)	(85,069		)	(100,544		)
Net cash provided by financing activities	155,619			112,141			274,487
Net change in cash and cash equivalents	10,027			10			238
Cash and cash equivalents at beginning of year	844			834			596
Cash and cash equivalents at end of year	$	10,871		$	844		$	834
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(75,978	)	$	(78,236	)	$	(76,474	)
Cash received (paid) for income taxes, net	41,548			61,813			(23,987		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	77,563		$	43,074		$	44,335

See Notes to Financial Statements

32

SOUTHWESTERN PUBLIC SERVICE CO.

BALANCE SHEETS

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

	Dec. 31
	2017			2016
Assets
Current assets
Cash and cash equivalents	$	10,871		$	844
Accounts receivable, net	79,581			74,190
Accounts receivable from affiliates	1,297			949
Investments in money pool arrangements	65,000			—
Accrued unbilled revenues	129,804			119,418
Inventories	40,433			38,505
Regulatory assets	31,538			38,721
Derivative instruments	15,882			5,114
Prepaid taxes	15,025			21,779
Prepayments and other	10,341			7,855
Total current assets	399,772			307,375
Property, plant and equipment, net	5,095,609			4,695,819
Other assets
Regulatory assets	362,943			346,683
Derivative instruments	18,954			22,113
Other	11,266			7,477
Total other assets	393,163			376,273
Total assets	$	5,888,544		$	5,379,467
Liabilities and Equity
Current liabilities
Short-term debt	$	—		$	50,000
Accounts payable	211,756			176,157
Accounts payable to affiliates	22,577			14,414
Regulatory liabilities	68,835			41,577
Taxes accrued	35,243			39,742
Accrued interest	23,275			19,162
Dividends payable	26,753			30,870
Derivative instruments	3,565			3,565
Other	29,641			29,703
Total current liabilities	421,645			405,190
Deferred credits and other liabilities
Deferred income taxes	574,906			989,137
Regulatory liabilities	784,564			233,454
Asset retirement obligations	28,524			28,663
Derivative instruments	19,949			23,513
Pension and employee benefit obligations	90,266			107,872
Other	8,386			24,084
Total deferred credits and other liabilities	1,506,595			1,406,723
Commitments and contingencies
Capitalization
Long-term debt	1,829,941			1,635,858
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2017 and 2016, respectively	—			—
Additional paid in capital	1,590,242			1,446,223
Retained earnings	541,588			486,763
Accumulated other comprehensive loss	(1,467		)	(1,290		)
Total common stockholder’s equity	2,130,363			1,931,696
Total liabilities and equity	$	5,888,544		$	5,379,467

See Notes to Financial Statements

33

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

(amounts in thousands of dollars, except share data)

	Common Stock Issued								Accumulated Other Comprehensive Income (Loss)			Total Common Stockholder’s Equity
	Shares	Par Value		Additional Paid In Capital		Retained Earnings
Balance at Dec. 31, 2014	100	$	—	$	1,165,463	$	395,998		$	(989	)	$	1,560,472
Net income						127,263						127,263
Other comprehensive loss									(292		)	(292		)
Common dividends declared to parent						(85,254		)				(85,254		)
Contribution of capital by parent				205,760								205,760
Balance at Dec. 31, 2015	100	$	—	$	1,371,223	$	438,007		$	(1,281	)	$	1,807,949
Net income						152,157						152,157
Other comprehensive loss									(9		)	(9		)
Common dividends declared to parent						(103,401		)				(103,401		)
Contribution of capital by parent				75,000								75,000
Balance at Dec. 31, 2016	100	$	—	$	1,446,223	$	486,763		$	(1,290	)	$	1,931,696
Net income						159,213						159,213
Other comprehensive income									83			83
Common dividends declared to parent						(104,648		)				(104,648		)
Contribution of capital by parent				144,019								144,019
Adoption of ASU No. 2018-02						260			(260		)	—
Balance at Dec. 31, 2017	100	$	—	$	1,590,242	$	541,588		$	(1,467	)	$	2,130,363

See Notes to Financial Statements

34

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 capital	1,590,242			1,446,223
Retained earnings	541,588			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

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NOTES TO FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Business and System of Accounts— 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 are the same in all material respects.

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 interest and if SPS is the primary beneficiary. SPS follows accounting guidance for variable interest entities which requires consideration of the activities 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.

Use of Estimates— In recording transactions and balances resulting from business operations, SPS uses estimates based on the best information available. Estimates are used for 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 recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions 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, 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, 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 and cash flows. See Note 12 for further discussion of regulatory assets and liabilities.

Revenue Recognition— Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is 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 date of the last meter reading are estimated and the corresponding unbilled revenue is recognized. SPS presents its revenues net of any excise or other fiduciary-type taxes or fees.

SPS participates in SPP. SPS recognizes sales to both native load 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 charges related to participating and transacting in RTOs are recorded on a net basis in cost of sales.

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.

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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, 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. 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— 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, 2.7 and 2.6 percent for the years ended Dec. 31, 2017, 2016 and 2015, respectively.

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 11 for further discussion of leases.

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 11 for further discussion of AROs.

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Income Taxes— SPS accounts for income taxes using the asset and liability method, which requires the 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 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. 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 certain regulatory assets and liabilities related to 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.

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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.

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.

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Any future 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. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 11 for further discussion of environmental costs.

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

See Note 7 for further discussion of benefit plans and other postretirement benefits.

Guarantees— SPS recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee. This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee.

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 Recognition— In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09), which provides a new framework for the 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 guidance is effective for interim and annual periods beginning after Dec. 15, 2017. SPS is implementing the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018.

Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement 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 when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. The overall 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 on 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.

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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 TCJA— 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, the FASB issued Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, 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, ASC Topic 740 requires that the effects of new tax laws on items in accumulated OCI 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 from the TCJA to be removed from accumulated OCI and reclassified to retained earnings, if elected. SPS adopted the guidance in the fourth quarter of 2017, and elected to recognize a $0.3 million increase to accumulated other comprehensive loss and retained earnings in the financial statements for the year ended Dec. 31, 2017, related to a revaluation of deferred income tax assets and liabilities for items in accumulated other comprehensive loss, at the TCJA federal tax rate.

3. Selected Balance Sheet Data

(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

(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

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4. Borrowings and Other Financing Instruments

Short-Term Borrowings

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:

(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:

(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, generally with terms of one-year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2017 and 2016, there were $3 million and $5 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.

SPS has the right to request an extension of the June 2021 termination date for two additional one-year periods. The extension requests are subject to majority bank group approval.

Other features of SPS’ credit facility include:

• The credit facility may be increased by up to $50 million.

• The credit facility has a financial covenant requiring that SPS’ debt-to-total capitalization ratio be less than or equal to 65 percent. SPS was in compliance as its debt-to-total capitalization ratio was 46 percent and 47 percent at Dec. 31, 2017 and 2016, respectively. 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 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.

• SPS was in compliance with all financial covenants on its debt agreements as of Dec. 31, 2017 and 2016.

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At Dec. 31, 2017, SPS had the following committed credit facility available (in millions):

Credit Facility (a)		Drawn (b)		Available
$	400	$	3	$	397

^(a) This credit facility matures in June 2021.

^(b) Includes letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. SPS had no direct advances on the credit facility outstanding at Dec. 31, 2017 and 2016.

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 with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines.

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 million and $15 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2017 and 2016, respectively. SPS is amortizing these financing costs over the remaining maturity periods of the related debt.

Dividend Restrictions— 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 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 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. 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, the key provisions impacting Xcel Energy (which includes SPS), generally beginning in 2018, include:

• Corporate federal tax rate reduction from 35 percent to 21 percent;

• 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 percent of taxable income);

• Repeal of the section 199 manufacturing deduction; and

• Reduced deductions for meals and entertainment as well as state and local lobbying.

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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, reductions in deferred tax assets and liabilities due to the reduction in corporate federal tax rates result in a net tax benefit. However, 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.

The fourth quarter 2017 estimated accounting impacts of the December 2017 enactment of the new tax law at SPS 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 percent 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;

• $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 statutes of limitations applicable to Xcel Energy’s federal income tax returns expire as follows:

Tax Year(s)	Expiration
2009 - 2011	June 2018
2012 - 2013	October 2018
2014	September 2018
2015	September 2019
2016	September 2020

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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, 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.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2017, 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, and in September 2017, began an audit of 2011. In the fourth quarter of 2017, Texas concluded these audits and SPS recognized the related benefit.

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

A reconciliation of the amount of unrecognized tax benefit is as follows:

(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 unrecognized 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 amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:

(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 progresses, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $1 million.

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The payable 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 payable for interest related to unrecognized tax benefits are as follows:

(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, or 2015.

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

The federal carryforward periods expire between 2021 and 2037. The state carryforward periods expire between 2021 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 for the years ending Dec. 31:

	2017		2016 (a)		2015 (a)
Federal statutory rate	35.0	%	35.0	%	35.0	%
State income tax on pretax income, net of federal tax effect	0.9	%	1.0	%	1.0	%
Increases (decreases) in tax from:
Tax reform	(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
Effective income tax rate	30.1	%	35.1	%	37.1	%

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

The components of income tax expense for the years ending Dec. 31 were:

(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

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The components of deferred income tax expense for the years ending Dec. 31 were:

(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 components of the net deferred tax liability at Dec. 31 were as follows:

(Thousands of Dollars)	2017		2016 (a)
Deferred tax liabilities:
Differences between book and tax bases of property	$	659,165	$	1,034,675
Regulatory assets	47,519		14,811
Pension expense	33,815		51,895
Other	4,604		3,267
Total deferred tax liabilities	$	745,103	$	1,104,648
Deferred tax assets:
Regulatory liabilities	115,302		(13,167		)
NOL carryforward	26,238		100,179
Deferred fuel costs	10,448		10,226
Other employee benefits	5,769		9,656
Tax credit carryforward	5,178		3,738
Other	7,262		4,879
Total deferred tax assets	$	170,197	$	115,511
Net deferred tax liability	$	574,906	$	989,137

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

7. Benefit Plans and Other Postretirement Benefits

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.

The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring fair value. The three levels in the hierarchy and examples of each level are as follows:

Level 1 — Quoted prices are available in active markets for identical assets as of the reporting date. The types of assets 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 included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.

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Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets included in Level 3 are those with inputs 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.

Insurance contracts — 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.

Pension 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’s average pay and, in some cases, social security benefits. Xcel Energy Inc.’s and SPS’ 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) 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’ operating cash flows. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2017 and 2016 were $37 million and $44 million, respectively, of which $2 million and $3 million were attributable to SPS. In 2017 and 2016, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $5 million and $8 million, respectively, 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. and SPS base the investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the historical returns achieved by the asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. Xcel Energy Inc. and SPS continually review the pension assumptions. The pension cost determination assumes a forecasted mix of investment types over the long-term.

• 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;

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• Investment returns in 2015 were below the assumed level of 7.22 percent; and

• In 2018, SPS’ expected investment-return assumption is 6.78 percent.

The assets are invested in a portfolio according to Xcel Energy Inc.’s and SPS’ return, liquidity and diversification objectives to provide 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, 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 pension assets in any year.

The following table presents the target pension asset allocations for SPS at Dec. 31 for the upcoming year:

	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	%

The 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, for each of the fair value hierarchy levels, SPS’ pension 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	$	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

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	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

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 pension benefit obligation and plan assets for SPS is 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	)

^(a)  Amounts are recognized in noncurrent liabilities on SPS’ balance sheets.

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(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

(Thousands of Dollars)	2017		2016
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
Noncurrent regulatory assets	221,801		233,857
Total	$	235,652	$	247,381

Measurement date Dec. 31, 2017 Dec. 31, 2016

	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 2018 to meet minimum funding requirements.

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

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

• $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.

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, there were no plan amendments made which affected the benefit obligation.

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

(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

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	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 all employees. The expense to these plans for SPS was approximately $3 million in 2017, 2016 and 2015.

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	%

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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.

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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 date Dec. 31, 2017 Dec. 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	%

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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

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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.

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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.

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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.

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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

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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.

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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.

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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.

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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.

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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.

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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 NO_X 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, NO_X 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.

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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.

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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 sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, 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.

Other Contingencies

See Note 10 for further discussion.

12. Regulatory Assets and Liabilities

SPS’ financial statements are prepared in accordance with the applicable accounting guidance, 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:

(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 debt	807		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

^(a)  Includes the non-qualified pension plan.

^(b)  Includes amounts recorded for future recovery of AROs.

^(c)  Includes a write-down of $23.2 million as a result of the revaluation of deferred tax gross up at the new federal tax rate at Dec. 31, 2017.

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

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The components of regulatory liabilities shown on the balance sheets of SPS at Dec. 31, 2017 and 2016 are:

(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

^(a)  Primarily relates to the revaluation of recoverable/regulated plant ADIT and $28.0 million revaluation impact of non-plant ADIT at Dec. 31, 2017.

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

At 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.

13. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2017 and 2016 were as follows:

	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	)

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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 7 for details regarding these benefit plans.

14. 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 4 for further discussion of this borrowing arrangement.

The table below contains significant affiliate transactions among the companies and related parties for the years ended Dec. 31:

(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:

	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

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15. Summarized Quarterly Financial Data (Unaudited)

	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
(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 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) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of Dec. 31, 2017, 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 change in SPS’ internal control over financial reporting has occurred during SPS’ most recent fiscal quarter that has materially affected, or is 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, 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 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 modules 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.

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

Item 9B — Other Information

None.

70

PART III

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

Item 10 — Directors, Executive Officers and Corporate Governance

Item 11 — Executive Compensation

Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

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

Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2018 Annual Meeting of Shareholders,

which is incorporated by reference.

Item 14 — Principal Accountant Fees and Services

The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm –

Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the 2018 Annual Meeting of Stockholders which

definitive Proxy Statement is expected to be filed with the SEC on or about April 3, 2018. Such information set forth under such

heading is incorporated herein by this reference hereto.

PART IV

Item 15 — Exhibits, Financial Statement Schedules

1.	Financial Statements
	Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2017.
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Statements of Income — For the three years ended Dec. 31, 2017, 2016 and 2015.
	Statements of Comprehensive Income — For the three years ended Dec. 31, 2017, 2016 and 2015.
	Statements of Cash Flows — For the three years ended Dec. 31, 2017, 2016 and 2015.
	Balance Sheets — As of Dec. 31, 2017 and 2016.
	Statements of Common Stockholder’s Equity — For the three years ended Dec. 31, 2017, 2016 and 2015.
	Statements of Capitalization — As of Dec. 31, 2017 and 2016.
2.	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2017, 2016 and 2015.
3.	Exhibits

*	Indicates incorporation by reference
+	Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors

3.01*	Amended and Restated Articles of Incorporation dated Sept. 30, 1997 (Exhibit 3.01 to Form 10-Q for the quarter ended Sept. 30, 2017 (file no. 001-03789)).
3.02*	By-Laws of SPS as Amended and Restated on Sept. 26, 2013. (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 001-03789)).
4.01*	Indenture dated Feb. 1, 1999 between SPS and The Chase Manhattan Bank (Exhibit 99.2 to Form 8-K (file no. 001-03789) dated Feb. 25, 1999).
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 Series C and Series D Notes, 6 percent due 2033 (Exhibit 4.04 to Xcel Energy Form 10-Q (file no. 001-03034) for the quarter ended Sept. 30, 2003).
4.03*	Fourth Supplemental Indenture dated Oct. 1, 2006 between SPS and The Bank of New York, as successor Trustee (Exhibit 4.01 to Form 8-K (file no. 001-03789) dated Oct. 3, 2006).

71

4.06*	Indenture dated as of Aug. 1, 2011 between SPS and U.S, Bank National Association, as Trustee  (Exhibit 4.01 to Form 8-K dated Aug. 10, 2011 (file no. 001-03789)).
4.07*	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 percent First Mortgage Bonds, Series No. 1 due 2041  (Exhibit 4.02 to Form 8-K dated Aug. 10, 2011 (file no. 001-03789)).
4.08*	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 percent First Mortgage Bonds, Series No. 3 due 2024. (Exhibit 4.02 to SPS’ Form 8-K dated June 9, 2014 (file no. 001-03789)).
4.11*	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 percent First Mortgage Bonds, Series No. 4 due 2046. (Exhibit 4.02 to Form 8-K of SPS dated Aug. 12, 2016 (file no. 001-03789)).
4.12*	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 percent First Mortgage Bonds, Series No. 5 due 2047. (Exhibit 4.02 to Form 8-K of SPS dated Aug. 9, 2017 (file no. 001-03789)).
10.01*+	Xcel Energy Inc. Nonqualified Pension Plan (2009 Restatement) (Exhibit 10.02 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.02*+	Xcel Energy Senior Executive Severance Change-in-Control Policy (2009 Amendment and Restatement) (Exhibit 10.05 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.03*+	Xcel Energy Inc. Non-Employee Directors Deferred Compensation Plan as amended and restated on Jan. 1, 2009 (Exhibit 10.08 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.04*+	Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Form U5B (file no. 001-03034) dated Nov. 16, 2000).
10.05*+	Xcel Energy Inc. Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 (Exhibit 10.17 to Form 10-K of Xcel Energy  (file no. 001-03034) for the year ended Dec. 31, 2008).
10.06*+	Amendment dated Aug. 26, 2009 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy  (Exhibit 10.06 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.07*+	Xcel Energy Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.08 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
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, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).
10.10*+	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 Definitive Proxy Statement (file no. 001-03034) filed Apr. 5, 2011).
10.11*+	Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.07 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.12*+	Second Amendment dated Oct. 26, 2011 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.18 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011).
10.13*+	First Amendment 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).
10.14*+	First Amendment 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).
10.15*+	Fourth Amendment dated Feb. 20, 2013 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.02 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended March 31, 2013).
10.16*+	First Amendment 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).
10.17*+	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).

72

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 to Form 8-K of Xcel Energy, dated May 26, 2015 (file no. 001-03034).
10.21*+	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. 2015 Omnibus Incentive Plan Form of Award Agreement. (Exhibit 10.28 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2015).
10.23*+	Xcel Energy Inc. Executive Annual Incentive Award Sub-plan pursuant to the 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).
10.24*+	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*	Second Amended and Restated Credit Agreement, dated as of June 20, 2016 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 and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Documentation Agents. (Exhibit 99.04 to Form 8-K of Xcel Energy dated June 20, 2016 (file no. 001-03034)).
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. 2015 Omnibus Incentive Plan. (Exhibit 10.27 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2016).
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.
12.01	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	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101	The 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.

73

SCHEDULE II

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

^(a)  Recovery of amounts previously written off.

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

Item 16 — Form 10-K Summary

None.

74

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, 2018	/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.
Marvin E. McDaniel, Jr.
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.

75

EX-12.01

Exhibit 12.01

SOUTHWESTERN PUBLIC SERVICES CO.

STATEMENT OF COMPUTATION OF

RATIO OF EARNINGS TO FIXED CHARGES

(amounts in thousands, except ratio)

	Year Ended Dec. 31
	2017		2016		2015		2014		2013
Earnings, as defined:
Pretax income	$	227,629	$	234,271	$	202,288	$	205,054	$	148,938
Add: Fixed charges	93,784		112,793		109,073		105,946		104,534
Total earnings, as defined	$	321,413	$	347,064	$	311,361	$	311,000	$	253,472
Fixed charges, as defined:
Interest charges	$	86,233	$	88,671	$	84,040	$	80,218	$	77,866
Interest component of leases	7,551		24,122		25,033		25,728		26,668
Total fixed charges, as defined	$	93,784	$	112,793	$	109,073	$	105,946	$	104,534
Ratio of earnings to fixed charges	3.4		3.1		2.9		2.9		2.4

EX-23.01

Exhibit 23.01

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-203664-03 on Form S-3 of our report dated February 23, 2018, relating to the financial statements and financial statement schedule of Southwestern Public Service Company appearing in this Annual Report on Form 10-K of Southwestern Public Service Company for the year ended December 31, 2017.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 23, 2018

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Ben Fowke, certify that:

1. I have reviewed this report on Form 10-K of Southwestern Public Service Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: Feb. 23, 2018

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

1

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Robert C. Frenzel, certify that:

1. I have reviewed this report on Form 10-K of Southwestern Public Service Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: Feb. 23, 2018

/s/ ROBERT C. FRENZEL

Robert C. Frenzel

Executive Vice President, Chief Financial Officer and Director

2

EX-32.01

Exhibit 32.01

OFFICER CERTIFICATION

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Southwestern Public Service Company (SPS) on Form 10-K for the year ended Dec. 31, 2017, as filed with the SEC on the date hereof (Form 10-K), each of the undersigned officers of SPS certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of SPS as of the dates and for the periods expressed in the Form 10-K.

Date: Feb. 23, 2018

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

/s/ ROBERT C. FRENZEL

Robert C. Frenzel

Executive Vice President, Chief Financial Officer and Director

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to SPS and will be retained by SPS and furnished to the SEC or its staff upon request.

1

EX-99.01

Exhibit 99.01

SPS Cautionary Factors

The Private Securities Litigation Reform Act provides a “safe harbor” for forward-looking statements to encourage such disclosures without the threat of litigation, providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement.  Forward-looking statements are made in written documents and oral presentations of SPS, Xcel Energy Inc. or any of its other subsidiaries.  These statements are based on management’s beliefs as well as assumptions and information currently available to management.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions.  In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause SPS’ actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

• Economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures;

• The risk of a significant slowdown in growth or decline in the U.S. economy, the risk of delay in growth recovery in the U.S. economy or the risk of increased cost for insurance premiums, security and other items as a consequence of past or future terrorist attacks;

• Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where SPS has a financial interest;

• Customer business conditions, including demand for their products or services and supply of labor and materials used in creating their products and services;

• Financial or regulatory accounting principles or policies imposed by the FASB, the SEC, the FERC and similar entities with regulatory oversight;

• Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, SPS, Xcel Energy Inc. or any of its other subsidiaries; or security ratings;

• Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel or natural gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; cyber incidents; or electric transmission or natural gas pipeline constraints;

• Employee workforce factors, including loss or retirement of key executives, collective-bargaining agreements with union employees, or work stoppages;

• Increased competition in the utility industry or additional competition in the markets served by SPS, Xcel Energy Inc. and its other subsidiaries;

• State and federal legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric market; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

• Environmental laws and regulations, including legislation and regulations relating to climate change, and the associated cost of compliance;

• Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options;

• Social attitudes regarding the utility and power industries;

• Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;

• Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;

• Risks associated with implementation of new technologies; and

• Other business or investment considerations that may be disclosed from time to time in SPS’ SEC filings, including “Risk Factors” in Item 1A of this Form 10-K, or in other publicly disseminated written documents.

SPS undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.  The foregoing review of factors should not be construed as exhaustive.

1

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Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 23, 2018	Jun. 30, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	SOUTHWESTERN PUBLIC SERVICE CO
Entity Central Index Key	0000092521
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Public Float			$ 0
Entity Common Stock, Shares Outstanding		100

XML

STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities
Net income	$ 159,213	$ 152,157	$ 127,263
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	193,870	162,957	153,241
Demand side management program amortization	1,673	1,673	1,673
Deferred income taxes	126,465	122,983	62,836
Amortization of investment tax credits	(133)	(213)	(213)
Allowance for equity funds used during construction	(9,310)	(9,981)	(7,378)
Provision for bad debts	5,091	6,066	4,655
Net derivative losses	63	217	268
Other	(28)	122	(3,827)
Changes in operating assets and liabilities:
Accounts receivable	(10,392)	(8,868)	(3,291)
Accrued unbilled revenues	(10,386)	(15,637)	25,506
Inventories	(1,928)	(959)	5,686
Prepayments and other	4,267	22,651	(24,712)
Accounts payable	11,836	13,776	(24,570)
Net regulatory assets and liabilities	38,137	(55,689)	26,452
Other current liabilities	3,427	5,156	(30,762)
Pension and other employee benefit obligations	(21,679)	(15,276)	(9,405)
Change in other noncurrent assets	(1,206)	(200)	2,352
Change in other noncurrent liabilities	(18,524)	6,748	8,974
Net cash provided by operating activities	470,456	387,683	314,748
Investing activities
Utility capital/construction expenditures	(559,865)	(512,522)	(599,511)
Allowance for equity funds used during construction	9,310	9,981	7,378
Proceeds from insurance recoveries	0	3,901	0
Investments in utility money pool arrangement	(142,000)	(75,000)	(92,000)
Receipts from utility money pool arrangement	77,000	75,000	92,000
Other	(493)	(1,174)	3,136
Net cash used in investing activities	(616,048)	(499,814)	(588,997)
Financing activities
(Repayment of) proceeds from short-term borrowings, net	(50,000)	35,000	(22,000)
Proceeds from issuance of long-term debt	442,338	295,985	198,496
Repayment of long-term debt, including reacquisition premiums	(271,613)	(200,000)	0
Borrowings under utility money pool arrangement	335,000	636,500	579,700
Repayments under utility money pool arrangement	(335,000)	(636,500)	(595,700)
Capital contributions from parent	143,659	66,225	214,535
Dividends paid to parent	(108,765)	(85,069)	(100,544)
Net cash provided by financing activities	155,619	112,141	274,487
Net change in cash and cash equivalents	10,027	10	238
Cash and cash equivalents at beginning of period	844	834	596
Cash and cash equivalents at end of period	10,871	844	834
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(75,978)	(78,236)	(76,474)
Cash paid for income taxes, net	41,548	61,813	(23,987)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 77,563	$ 43,074	$ 44,335

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STATEMENTS OF COMMON STOCKHOLDER'S EQUITY - USD ($) $ in Thousands	Total	Common stock	Additional Paid In Capital	Retained Earnings	AOCI Attributable to Parent
Beginning Balance at Dec. 31, 2014	$ 1,560,472	$ 0	$ 1,165,463	$ 395,998	$ (989)
Beginning Balance (in shares) at Dec. 31, 2014		100
Comprehensive income:
Net income	127,263			127,263
Other comprehensive income	(292)				(292)
Common dividends declared to parent	(85,254)			(85,254)
Contribution of capital by parent	205,760		205,760
Ending Balance at Dec. 31, 2015	1,807,949	$ 0	1,371,223	438,007	(1,281)
Ending Balance (in shares) at Dec. 31, 2015		100
Comprehensive income:
Net income	152,157			152,157
Other comprehensive income	(9)				(9)
Common dividends declared to parent	(103,401)			(103,401)
Contribution of capital by parent	75,000		75,000
Ending Balance at Dec. 31, 2016	$ 1,931,696	$ 0	1,446,223	486,763	(1,290)
Ending Balance (in shares) at Dec. 31, 2016	100	100
Comprehensive income:
Net income	$ 159,213			159,213
Other comprehensive income	83				83
Common dividends declared to parent	(104,648)			(104,648)
Contribution of capital by parent	144,019		144,019
Adoption of ASU No. 2018-02	0			260	(260)	[1]
Ending Balance at Dec. 31, 2017	$ 2,130,363	$ 0	$ 1,590,242	$ 541,588	$ (1,467)
Ending Balance (in shares) at Dec. 31, 2017	100	100

[1] 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.

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STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement [Abstract]
Operating revenues	$ 1,918,000	$ 1,850,959	$ 1,787,218
Operating expenses
Electric fuel and purchased power	1,055,333	1,034,950	1,001,083
Operating and maintenance expenses	289,555	269,471	289,856
Demand side management program expenses	15,525	16,028	13,365
Depreciation and amortization	193,915	162,429	150,913
Taxes (other than income taxes)	66,863	60,800	57,536
Total operating expenses	1,621,191	1,543,678	1,512,753
Operating income	296,809	307,281	274,465
Other income (expense), net	2,359	91	(6)
Allowance for funds used during construction — equity	9,310	9,981	7,378
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
Public Utilities, Allowance For Funds Used During Construction, Capitalized Cost Of Debt	(5,384)	(5,589)	(4,491)
Total interest charges and financing costs	80,849	83,082	79,549
Income before income taxes	227,629	234,271	202,288
Income taxes	68,416	82,114	75,025
Net income	$ 159,213	$ 152,157	$ 127,263

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STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Interest charges and financing costs
Other financing costs	$ 2,491	$ 3,055	$ 3,158

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BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents	$ 10,871	$ 844
Accounts receivable, net	79,581	74,190
Accounts receivable from affiliates	1,297	949
Investments in money pool arrangements	65,000	0
Accrued unbilled revenues	129,804	119,418
Inventories	40,433	38,505
Regulatory assets	31,538	38,721
Derivative instruments	15,882	5,114
Prepaid taxes	15,025	21,779
Prepayments and other	10,341	7,855
Total current assets	399,772	307,375
Property, plant and equipment, net	5,095,609	4,695,819
Other assets
Regulatory assets	362,943	346,683
Derivative instruments	18,954	22,113
Other	11,266	7,477
Total other assets	393,163	376,273
Total assets	5,888,544	5,379,467
Current liabilities
Short-term debt	0	50,000
Accounts payable	211,756	176,157
Accounts payable to affiliates	22,577	14,414
Regulatory liabilities	68,835	41,577
Taxes accrued	35,243	39,742
Accrued interest	23,275	19,162
Dividends payable	26,753	30,870
Derivative instruments	3,565	3,565
Other	29,641	29,703
Total current liabilities	421,645	405,190
Deferred credits and other liabilities
Deferred income taxes	574,906	989,137
Regulatory liabilities	784,564	233,454
Asset retirement obligations	28,524	28,663
Derivative instruments	19,949	23,513
Pension and employee benefit obligations	90,266	107,872
Other	8,386	24,084
Total deferred credits and other liabilities	1,506,595	1,406,723
Commitments and contingencies
Capitalization
Long-term debt	1,829,941	1,635,858
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2017 and 2016, respectively	0	0
Additional paid in capital	1,590,242	1,446,223
Retained earnings	541,588	486,763
Accumulated other comprehensive loss	(1,467)	(1,290)
Total common stockholder’s equity	2,130,363	1,931,696
Total liabilities and equity	$ 5,888,544	$ 5,379,467

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BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Capitalization, Long-term Debt and Equity [Abstract]
Common stock, shares authorized (in shares)	200	200
Common stock, par value (in dollars per share)	$ 1.00	$ 1.00
Common stock, shares outstanding (in shares)	100	100

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STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Comprehensive income:
Net income	$ 159,213	$ 152,157	$ 127,263
Other comprehensive income (loss)
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	83	(9)	(292)
Comprehensive income	$ 159,296	$ 152,148	$ 126,971

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STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative instruments:
Reclassification of losses to net income, tax	$ 24	$ 80	$ 97
Amortization of losses (gains) included in net periodic benefit cost, tax	$ 26	$ (84)	$ (260)

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STATEMENTS OF CAPITALIZATION - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Schedule of Capitalization, Long-term Debt [Line Items]
Unamortized discount (premium), net	$ (1,746)	$ 365
Unamortized Debt Issuance Expense	(18,313)	(14,507)
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	0	0
Additional paid in capital	1,590,242	1,446,223
Retained earnings	541,588	486,763
Accumulated other comprehensive loss	(1,467)	(1,290)
Total common stockholder’s equity	2,130,363	1,931,696
First Mortgage Bonds, Series due: | Series Due June 15, 2024
Schedule of Capitalization, Long-term Debt [Line Items]
Principal outstanding	350,000	350,000
First Mortgage Bonds, Series due: | Series Due Aug. 15, 2041
Schedule of Capitalization, Long-term Debt [Line Items]
Principal outstanding	400,000	400,000
First Mortgage Bonds, Series due: | Series Due Aug. 15, 2046
Schedule of Capitalization, Long-term Debt [Line Items]
Principal outstanding	300,000	300,000
First Mortgage Bonds, Series due: | Series Due August 15, 2047
Schedule of Capitalization, Long-term Debt [Line Items]
Principal outstanding	450,000	0
Unsecured Senior Notes | Senior G Due Dec. 1, 2018
Schedule of Capitalization, Long-term Debt [Line Items]
Principal outstanding	0	250,000
Unsecured Senior Notes | Senior C and D Due Oct. 1, 2033
Schedule of Capitalization, Long-term Debt [Line Items]
Principal outstanding	100,000	100,000
Unsecured Senior Notes | Senior F Due Oct. 1, 2036
Schedule of Capitalization, Long-term Debt [Line Items]
Principal outstanding	$ 250,000	$ 250,000

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STATEMENTS OF CAPITALIZATION (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Common Stockholder's Equity
Common stock, shares authorized (in shares)	200	200
Common stock, par value (in dollars per share)	$ 1.00	$ 1.00
Common stock, shares outstanding (in shares)	100	100
First Mortgage Bonds, Series due: | Series Due June 15, 2024
Schedule of Capitalization, Long-term Debt [Line Items]
Debt Instrument, Maturity Date	Jun. 15, 2024	Jun. 15, 2024
Debt instrument, Interest Rate, Stated Percentage	3.30%	3.30%
First Mortgage Bonds, Series due: | Series Due Aug. 15, 2041
Schedule of Capitalization, Long-term Debt [Line Items]
Debt Instrument, Maturity Date	Aug. 15, 2041	Aug. 15, 2041
Debt instrument, Interest Rate, Stated Percentage	4.50%	4.50%
First Mortgage Bonds, Series due: | Series Due Aug. 15, 2046
Schedule of Capitalization, Long-term Debt [Line Items]
Debt Instrument, Maturity Date	Aug. 15, 2046	Aug. 15, 2046
Debt instrument, Interest Rate, Stated Percentage	3.40%	3.40%
Unsecured Senior Notes | Series Due August 15, 2047
Schedule of Capitalization, Long-term Debt [Line Items]
Debt Instrument, Maturity Date	Aug. 15, 2047
Debt instrument, Interest Rate, Stated Percentage	3.70%
Unsecured Senior Notes | Senior G Due Dec. 1, 2018
Schedule of Capitalization, Long-term Debt [Line Items]
Debt Instrument, Maturity Date	Dec. 01, 2018	Dec. 01, 2018
Debt instrument, Interest Rate, Stated Percentage	8.75%	8.75%
Unsecured Senior Notes | Senior C and D Due Oct. 1, 2033
Schedule of Capitalization, Long-term Debt [Line Items]
Debt Instrument, Maturity Date	Oct. 01, 2033	Oct. 01, 2033
Debt instrument, Interest Rate, Stated Percentage	6.00%	6.00%
Unsecured Senior Notes | Senior F Due Oct. 1, 2036
Schedule of Capitalization, Long-term Debt [Line Items]
Debt Instrument, Maturity Date	Oct. 01, 2036	Oct. 01, 2036
Debt instrument, Interest Rate, Stated Percentage	6.00%	6.00%

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Business and System of Accounts— 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 are the same in all material respects.

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 interest and if SPS is the primary beneficiary. SPS follows accounting guidance for variable interest entities which requires consideration of the activities 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.

Use of Estimates— In recording transactions and balances resulting from business operations, SPS uses estimates based on the best information available. Estimates are used for 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 recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions 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, 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, 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 and cash flows. See Note 12 for further discussion of regulatory assets and liabilities.

Revenue Recognition— Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is 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 date of the last meter reading are estimated and the corresponding unbilled revenue is recognized. SPS presents its revenues net of any excise or other fiduciary-type taxes or fees.

SPS participates in SPP. SPS recognizes sales to both native load 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 charges related to participating and transacting in RTOs are recorded on a net basis in cost of sales.

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, 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. 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— 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, 2.7 and 2.6 percent for the years ended Dec. 31, 2017, 2016 and 2015, respectively.

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 11 for further discussion of leases.

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 11 for further discussion of AROs.

Income Taxes— SPS accounts for income taxes using the asset and liability method, which requires the 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 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. 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 certain regulatory assets and liabilities related to 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.

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 future 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. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 11 for further discussion of environmental costs.

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

See Note 7 for further discussion of benefit plans and other postretirement benefits.

Guarantees— SPS recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee. This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee.

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.

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Accounting Pronouncements

12 Months Ended

Dec. 31, 2017

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Accounting Pronouncements

Accounting Pronouncements

Recently Issued

Revenue Recognition— In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09), which provides a new framework for the 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 guidance is effective for interim and annual periods beginning after Dec. 15, 2017. SPS is implementing the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018.

Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement 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 when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. The overall 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 on 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.

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 TCJA— 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, the FASB issued Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, 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, ASC Topic 740 requires that the effects of new tax laws on items in accumulated OCI 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 from the TCJA to be removed from accumulated OCI and reclassified to retained earnings, if elected. SPS adopted the guidance in the fourth quarter of 2017, and elected to recognize a $0.3 million increase to accumulated other comprehensive loss and retained earnings in the financial statements for the year ended Dec. 31, 2017, related to a revaluation of deferred income tax assets and liabilities for items in accumulated other comprehensive loss, at the TCJA federal tax rate.

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Selected Balance Sheet Data

12 Months Ended

Dec. 31, 2017

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(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

(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

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Borrowings and Other Financing Instruments

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Borrowings and Other Financing Instruments

Borrowings and Other Financing Instruments

Short-Term Borrowings

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:

(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:

(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, generally with terms of one-year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2017 and 2016, there were $3 million and $5 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.

SPS has the right to request an extension of the June 2021 termination date for two additional one-year periods. The extension requests are subject to majority bank group approval.

Other features of SPS’ credit facility include:

• The credit facility may be increased by up to $50 million.

• The credit facility has a financial covenant requiring that SPS’ debt-to-total capitalization ratio be less than or equal to 65 percent. SPS was in compliance as its debt-to-total capitalization ratio was 46 percent and 47 percent at Dec. 31, 2017 and 2016, respectively. 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 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.

• SPS was in compliance with all financial covenants on its debt agreements as of Dec. 31, 2017 and 2016.

At Dec. 31, 2017, SPS had the following committed credit facility available (in millions):

Credit Facility (a)		Drawn (b)		Available
$	400	$	3	$	397

^(a) This credit facility matures in June 2021.

^(b) Includes letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. SPS had no direct advances on the credit facility outstanding at Dec. 31, 2017 and 2016.

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 with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines.

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 million and $15 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2017 and 2016, respectively. SPS is amortizing these financing costs over the remaining maturity periods of the related debt.

Dividend Restrictions— 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 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 ratio (excluding short-term debt) was 53.8 percent at Dec. 31, 2017 and $542 million in retained earnings was not restricted.

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Preferred Stock

12 Months Ended

Dec. 31, 2017

Equity [Abstract]

Preferred Stock

Preferred Stock

SPS has authorized the issuance of preferred stock.

Preferred Shares Authorized	Par Value		Preferred Shares Outstanding
10,000,000	$	1.00	None

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Income Taxes

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

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, the key provisions impacting Xcel Energy (which includes SPS), generally beginning in 2018, include:

• Corporate federal tax rate reduction from 35 percent to 21 percent;

• 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 percent 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, reductions in deferred tax assets and liabilities due to the reduction in corporate federal tax rates result in a net tax benefit. However, 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.

The fourth quarter 2017 estimated accounting impacts of the December 2017 enactment of the new tax law at SPS 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 percent 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;

• $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 statutes of limitations applicable to Xcel Energy’s federal income tax returns expire as follows:

Tax Year(s)	Expiration
2009 - 2011	June 2018
2012 - 2013	October 2018
2014	September 2018
2015	September 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, 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.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2017, 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, and in September 2017, began an audit of 2011. In the fourth quarter of 2017, Texas concluded these audits and SPS recognized the related benefit.

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

A reconciliation of the amount of unrecognized tax benefit is as follows:

(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 unrecognized 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 amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:

(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 progresses, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $1 million.

The payable 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 payable for interest related to unrecognized tax benefits are as follows:

(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, or 2015.

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

The federal carryforward periods expire between 2021 and 2037. The state carryforward periods expire between 2021 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 for the years ending Dec. 31:

	2017		2016 (a)		2015 (a)
Federal statutory rate	35.0	%	35.0	%	35.0	%
State income tax on pretax income, net of federal tax effect	0.9	%	1.0	%	1.0	%
Increases (decreases) in tax from:
Tax reform	(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
Effective income tax rate	30.1	%	35.1	%	37.1	%

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

The components of income tax expense for the years ending Dec. 31 were:

(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

The components of deferred income tax expense for the years ending Dec. 31 were:

(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 components of the net deferred tax liability at Dec. 31 were as follows:

(Thousands of Dollars)	2017		2016 (a)
Deferred tax liabilities:
Differences between book and tax bases of property	$	659,165	$	1,034,675
Regulatory assets	47,519		14,811
Pension expense	33,815		51,895
Other	4,604		3,267
Total deferred tax liabilities	$	745,103	$	1,104,648
Deferred tax assets:
Regulatory liabilities	115,302		(13,167		)
NOL carryforward	26,238		100,179
Deferred fuel costs	10,448		10,226
Other employee benefits	5,769		9,656
Tax credit carryforward	5,178		3,738
Other	7,262		4,879
Total deferred tax assets	$	170,197	$	115,511
Net deferred tax liability	$	574,906	$	989,137

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

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Benefit Plans and Other Postretirement Benefits

12 Months Ended

Dec. 31, 2017

Retirement Benefits [Abstract]

Benefit Plans and Other Postretirement Benefits

Benefit Plans and Other Postretirement Benefits

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.

The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring fair value. The three levels in the hierarchy and examples of each level are as follows:

Level 1 — Quoted prices are available in active markets for identical assets as of the reporting date. The types of assets 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 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 included in Level 3 are those with inputs 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.

Insurance contracts — 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.

Pension 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’s average pay and, in some cases, social security benefits. Xcel Energy Inc.’s and SPS’ 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) 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’ operating cash flows. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2017 and 2016 were $37 million and $44 million, respectively, of which $2 million and $3 million were attributable to SPS. In 2017 and 2016, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $5 million and $8 million, respectively, 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. and SPS base the investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the historical returns achieved by the asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. Xcel Energy Inc. and SPS continually review the pension assumptions. The pension cost determination assumes a forecasted mix of investment types over the long-term.

• 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; and

• In 2018, SPS’ expected investment-return assumption is 6.78 percent.

The assets are invested in a portfolio according to Xcel Energy Inc.’s and SPS’ return, liquidity and diversification objectives to provide 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, 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 pension assets in any year.

The following table presents the target pension asset allocations for SPS at Dec. 31 for the upcoming year:

	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	%

The 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, for each of the fair value hierarchy levels, SPS’ pension 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	$	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, 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

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 pension benefit obligation and plan assets for SPS is 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	)

^(a)  Amounts are recognized in noncurrent liabilities on SPS’ balance sheets.

(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

(Thousands of Dollars)	2017		2016
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
Noncurrent regulatory assets	221,801		233,857
Total	$	235,652	$	247,381

Measurement date Dec. 31, 2017 Dec. 31, 2016

	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 2018 to meet minimum funding requirements.

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

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

• $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.

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, there were no plan amendments made which affected the benefit obligation.

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

(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 all employees. The expense to these plans for SPS was approximately $3 million in 2017, 2016 and 2015.

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 date Dec. 31, 2017 Dec. 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

XML

Other Income, Net

12 Months Ended

Dec. 31, 2017

Other Income and Expenses [Abstract]

Other Income, Net

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	)

XML

Fair Value of Financial Assets and Liabilities

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value of Financial Assets and Liabilities

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.

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Rate Matters

12 Months Ended

Dec. 31, 2017

Public Utilities, General Disclosures [Abstract]

Rate Matters

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.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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 NO_X 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, NO_X 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 sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, 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.

Other Contingencies

See Note 10 for further discussion.

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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2017

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

Regulatory Assets and Liabilities

SPS’ financial statements are prepared in accordance with the applicable accounting guidance, 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:

(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 debt	807		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

^(a)  Includes the non-qualified pension plan.

^(b)  Includes amounts recorded for future recovery of AROs.

^(c)  Includes a write-down of $23.2 million as a result of the revaluation of deferred tax gross up at the new federal tax rate at Dec. 31, 2017.

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

The components of regulatory liabilities shown on the balance sheets of SPS at Dec. 31, 2017 and 2016 are:

(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

^(a)  Primarily relates to the revaluation of recoverable/regulated plant ADIT and $28.0 million revaluation impact of non-plant ADIT at Dec. 31, 2017.

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

At 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.

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Other Comprehensive Income

12 Months Ended

Dec. 31, 2017

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2017 and 2016 were as follows:

	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 7 for details regarding these benefit plans.

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Related Party Transactions

12 Months Ended

Dec. 31, 2017

Related Party Transactions [Abstract]

Related Party Transactions

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 4 for further discussion of this borrowing arrangement.

The table below contains significant affiliate transactions among the companies and related parties for the years ended Dec. 31:

(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:

	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

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Summarized Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Data (Unaudited)

Summarized Quarterly Financial Data (Unaudited)

	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
(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

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Schedule II, Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2017

Valuation and Qualifying Accounts [Abstract]

Schedule II, Valuation and Qualifying Accounts

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

^(a)  Recovery of amounts previously written off.

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

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Business and System of Accounts

Business and System of Accounts— 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 are the same in all material respects.

Variable Interest Entities

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 interest and if SPS is the primary beneficiary. SPS follows accounting guidance for variable interest entities which requires consideration of the activities 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.

Use of Estimates

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

Regulatory Accounting

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, 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, 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 and cash flows. See Note 12 for further discussion of regulatory assets and liabilities.

Revenue Recognition

Revenue Recognition— Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is 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 date of the last meter reading are estimated and the corresponding unbilled revenue is recognized. SPS presents its revenues net of any excise or other fiduciary-type taxes or fees.

SPS participates in SPP. SPS recognizes sales to both native load 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 charges related to participating and transacting in RTOs are recorded on a net basis in cost of sales.

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.

Conservation Programs

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

The costs incurred for some DSM programs are deferred as permitted by the applicable regulatory jurisdiction. For those programs, costs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. 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

Property, Plant and Equipment and Depreciation— 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, 2.7 and 2.6 percent for the years ended Dec. 31, 2017, 2016 and 2015, respectively.

Leases

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 11 for further discussion of leases.

AFUDC

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.

Asset Retirement Obligations

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 11 for further discussion of AROs.

Income Taxes

Income Taxes— SPS accounts for income taxes using the asset and liability method, which requires the 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 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. 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 certain regulatory assets and liabilities related to 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

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.

Fair Value Measurements

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

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 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

Inventory— All inventory is recorded at average cost.

Renewable Energy Credits

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 — 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— 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 future 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. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 11 for further discussion of environmental costs.

Benefit Plans and Other Postretirement Benefits

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

See Note 7 for further discussion of benefit plans and other postretirement benefits.

Guarantees

Guarantees— SPS recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee. This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee.

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

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

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.

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Selected Balance Sheet Data (Tables)

12 Months Ended

Dec. 31, 2017

Balance Sheet Related Disclosures [Abstract]

Accounts Receivable, Net

(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

Inventories

(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

Property, Plant and Equipment, Net

(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

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Borrowings and Other Financing Instruments (Tables)

12 Months Ended

Dec. 31, 2017

Borrowings and Other Financing Instruments [Abstract]

Credit Facilities

At Dec. 31, 2017, SPS had the following committed credit facility available (in millions):

Credit Facility (a)		Drawn (b)		Available
$	400	$	3	$	397

^(a) This credit facility matures in June 2021.

^(b) Includes letters of credit.

Money Pool

Borrowings and Other Financing Instruments [Abstract]

Short-Term Borrowings

Money pool borrowings for SPS were as follows:

(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

Borrowings and Other Financing Instruments [Abstract]

Short-Term Borrowings

Commercial paper outstanding for SPS was as follows:

(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

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Preferred Stock (Tables)

12 Months Ended

Dec. 31, 2017

Equity [Abstract]

Preferred Stock

SPS has authorized the issuance of preferred stock.

Preferred Shares Authorized	Par Value		Preferred Shares Outstanding
10,000,000	$	1.00	None

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Summary of Statute of Limitations Applicable to Open Tax Years

SPS is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statutes of limitations applicable to Xcel Energy’s federal income tax returns expire as follows:

Tax Year(s)	Expiration
2009 - 2011	June 2018
2012 - 2013	October 2018
2014	September 2018
2015	September 2019
2016	September 2020

Reconciliation of Unrecognized Tax Benefits

A reconciliation of the amount of unrecognized tax benefit is as follows:

(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 unrecognized 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

Tax Benefits Associated with NOL and Tax Credit Carryforwards

The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:

(Millions of Dollars)	Dec. 31, 2017			Dec. 31, 2016
NOL and tax credit carryforwards	$	(5.9	)	$	(5.9	)

Interest Payable related to Unrecognized Tax Benefits

The payable 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 payable for interest related to unrecognized tax benefits are as follows:

(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	)	$	—

NOL and Tax Credit Carryforwards

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

Schedule of Effective Income Tax Rate Reconciliation

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 for the years ending Dec. 31:

	2017		2016 (a)		2015 (a)
Federal statutory rate	35.0	%	35.0	%	35.0	%
State income tax on pretax income, net of federal tax effect	0.9	%	1.0	%	1.0	%
Increases (decreases) in tax from:
Tax reform	(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
Effective income tax rate	30.1	%	35.1	%	37.1	%

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

Schedule of Components of Income Tax Expense (Benefit)

The components of income tax expense for the years ending Dec. 31 were:

(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

The components of deferred income tax expense for the years ending Dec. 31 were:

Schedule of Deferred Tax Assets and Liabilities

The components of the net deferred tax liability at Dec. 31 were as follows:

(Thousands of Dollars)	2017		2016 (a)
Deferred tax liabilities:
Differences between book and tax bases of property	$	659,165	$	1,034,675
Regulatory assets	47,519		14,811
Pension expense	33,815		51,895
Other	4,604		3,267
Total deferred tax liabilities	$	745,103	$	1,104,648
Deferred tax assets:
Regulatory liabilities	115,302		(13,167		)
NOL carryforward	26,238		100,179
Deferred fuel costs	10,448		10,226
Other employee benefits	5,769		9,656
Tax credit carryforward	5,178		3,738
Other	7,262		4,879
Total deferred tax assets	$	170,197	$	115,511
Net deferred tax liability	$	574,906	$	989,137

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

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Benefit Plans and Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2017

Benefit Plans and Other Postretirement Benefits [Abstract]

Projected Benefit Payments for the Pension and Postretirement Benefit Plans

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

Pension Plan [Member]

Benefit Plans and Other Postretirement Benefits [Abstract]

Target Asset Allocations and Plan Assets Measured at Fair Value

The following table presents the target pension asset allocations for SPS at Dec. 31 for the upcoming year:

	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	%

The following tables present, for each of the fair value hierarchy levels, SPS’ pension 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	$	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, 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

Change in Projected Benefit Obligation

A comparison of the actuarially computed pension benefit obligation and plan assets for SPS is 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

Change in Fair Value of Plan Assets

(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

Funded Status of Plans

(Thousands of Dollars)	2017			2016
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(82,650	)	$	(103,206	)

^(a)  Amounts are recognized in noncurrent liabilities on SPS’ balance sheets.

Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost

(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

Amounts Not Yet Recognized as Components of Net Periodic Benefit Costs Recorded on the Balance Sheet Based Upon Expected Recovery in Rates

(Thousands of Dollars)	2017		2016
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
Noncurrent regulatory assets	221,801		233,857
Total	$	235,652	$	247,381

Schedule of Assumptions Used

Measurement date Dec. 31, 2017 Dec. 31, 2016

	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

	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

Components of Net Periodic Benefit Costs

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

(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

Other Postretirement Benefits Plan [Member]

Benefit Plans and Other Postretirement Benefits [Abstract]

Target Asset Allocations and Plan Assets Measured at Fair Value

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

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	%

Change in Projected Benefit Obligation

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

Change in Fair Value of Plan Assets

(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

Funded Status of Plans

(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.

Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost

(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	)

Amounts Not Yet Recognized as Components of Net Periodic Benefit Costs Recorded on the Balance Sheet Based Upon Expected Recovery in Rates

(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	)

Schedule of Assumptions Used

	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

Measurement date Dec. 31, 2017 Dec. 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	%

Effects of One-Percent Change in Assumed Health Care Cost Trend Rate

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		)

Components of Net Periodic 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	)

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Other Income, Net (Tables)

12 Months Ended

Dec. 31, 2017

Other Income and Expenses [Abstract]

Other Income, 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	)

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Fair Value of Financial Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Gross Notional Amounts of Commodity 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.

Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Loss

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	)

Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level

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.

Changes in Level 3 Commodity Derivatives

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

Carrying Amount and 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

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Rate Matters (Tables)

12 Months Ended

Dec. 31, 2017

Public Utilities, General Disclosures [Abstract]

Texas 2017 Rate Case [Table Text Block]

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.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Estimated Minimum Purchases Under Fuel Contracts

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

Estimated Future Payments for Capacity and Energy Pursuant to Purchased Power Agreements

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

Future Commitments Under Operating Leases

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.

Asset Retirement Obligations

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.

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2017

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets

The components of regulatory assets shown on the balance sheets of SPS at Dec. 31, 2017 and 2016 are:

(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 debt	807		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

^(a)  Includes the non-qualified pension plan.

^(b)  Includes amounts recorded for future recovery of AROs.

^(c)  Includes a write-down of $23.2 million as a result of the revaluation of deferred tax gross up at the new federal tax rate at Dec. 31, 2017.

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

Regulatory Liabilities

The components of regulatory liabilities shown on the balance sheets of SPS at Dec. 31, 2017 and 2016 are:

(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

^(a)  Primarily relates to the revaluation of recoverable/regulated plant ADIT and $28.0 million revaluation impact of non-plant ADIT at Dec. 31, 2017.

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

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Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2017

Stockholders' Equity Note [Abstract]

Changes in Accumulated Other Comprehensive Income (Loss), Net of Tax

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2017 and 2016 were as follows:

	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 out of Accumulated Other Comprehensive Loss

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 7 for details regarding these benefit plans.

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2017

Related Party Transactions [Abstract]

Related Party Transactions

The table below contains significant affiliate transactions among the companies and related parties for the years ended Dec. 31:

(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:

	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

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Summarized Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Data (Unaudited)

	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
(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

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Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Conservation Programs [Abstract]
Maximum number of months following end of annual period in which revenues are earned to be included in incentive programs	24 months
Property, Plant and Equipment [Abstract]
Depreciation expense expressed as a percentage of average depreciable property	2.80%	2.70%	2.60%
Cash and Cash Equivalents [Abstract]
Maximum number of months of remaining maturity at time of purchase to consider investments in certain instruments as cash equivalents	3 months

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Accounting Pronouncements Adoption of New Accounting Pronouncements (Details) - Accounting Standards Update 2018-02 $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)
Retained Earnings
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of tax effects from AOCI to retained earnings	$ 0.3
AOCI Attributable to Parent
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of tax effects from AOCI to retained earnings	$ (0.3)

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Selected Balance Sheet Data (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounts receivable, net
Accounts receivable	$ 85,929	$ 80,569
Less allowance for bad debts	(6,348)	(6,379)
Accounts receivable, net	$ 79,581	$ 74,190

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Public Utilities, Inventory [Line Items]
Inventories	$ 40,433	$ 38,505
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	26,218	25,453
Fuel
Public Utilities, Inventory [Line Items]
Inventories	$ 14,215	$ 13,052

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 7,117,246	$ 6,622,516
Less accumulated depreciation	(2,021,637)	(1,926,697)
Property, plant and equipment, net	5,095,609	4,695,819
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	6,765,371	6,362,189
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 351,875	$ 260,327

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Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Short-term Debt [Line Items]
Amount outstanding at period end	$ 0	$ 50,000
Money Pool
Short-term Debt [Line Items]
Borrowing limit	100,000	100,000	$ 100,000
Amount outstanding at period end	0	0	0
Average amount outstanding	13,000	28,000	21,000
Maximum amount outstanding	$ 100,000	$ 100,000	$ 100,000
Weighted average interest rate, computed on a daily basis (percentage)	1.12%	0.67%	0.40%
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	$ 400,000	$ 400,000	$ 400,000
Amount outstanding at period end	0	50,000	15,000
Average amount outstanding	69,000	43,000	100,000
Maximum amount outstanding	$ 176,000	$ 140,000	$ 246,000
Weighted average interest rate, computed on a daily basis (percentage)	1.13%	0.67%	0.46%
Weighted average interest rate at period end (percentage)		0.95%	0.60%

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Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 0	$ 50,000
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 3,000	$ 5,000
Letter of Credit | Letter of Credit
Line of Credit Facility [Line Items]
Term of letters of credit (in years)	1 year

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Borrowings and Other Financing Instruments, Credit Facility (Details) - Credit Facility		12 Months Ended
		Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Line of Credit Facility [Line Items]
Debt Instrument, Maturity Date		Jun. 30, 2021
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased		$ 50,000,000
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed		65.00%
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)		46.00%	47.00%
Line Of Credit Facility Minimum Threshhold Percentage Of Subsidiary Assets To Consolidated Assets Required To Initiate Cross Default Provisions		15.00%
Line of Credit Facility, Minimum Amount of Indebtedness in Default to Initiate Cross Default Provisions		$ 75,000,000
Credit facility	[1]	400,000,000
Drawn	[2]	3,000,000
Available		397,000,000
Direct advances on the credit outstanding		$ 0	$ 0
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		2
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		1 year

[1] This credit facility matures in June 2021.

[2] Includes letters of credit.

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Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Deferred Finance Costs, Noncurrent, Net	$ 18	$ 15
Equity to total capitalization ratio (excluding short-term debt), low end of range	45.00%
Equity to total capitalization ratio (excluding short-term debt), high end of range	55.00%
Equity to total capitalization ratio (excluding short-term debt)	53.80%
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 542
First Mortgage Bonds, Series due: | Series Due Aug. 15, 2046
Debt Instrument [Line Items]
Interest Rate, Stated Percentage (in hundredths)	3.40%	3.40%
Debt Instrument, Maturity Date	Aug. 15, 2046	Aug. 15, 2046
SPS | First Mortgage Bonds, Series due: | Series Due August 15, 2047
Debt Instrument [Line Items]
Face Amount	$ 450
Interest Rate, Stated Percentage (in hundredths)	3.70%
Debt Instrument, Maturity Date	Aug. 15, 2047
SPS | First Mortgage Bonds, Series due: | Series Due Aug. 15, 2046
Debt Instrument [Line Items]
Face Amount		$ 300
Interest Rate, Stated Percentage (in hundredths)		3.40%
Debt Instrument, Maturity Date		Aug. 15, 2046

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Preferred Stock (Details)	Dec. 31, 2017 $ / shares shares
Equity [Abstract]
Preferred stock, shares authorized (in shares)	10,000,000
Preferred stock, par value (in dollars per share) | $ / shares	$ 1.00
Preferred stock, shares outstanding (in shares)	0

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Income Taxes (Details) - USD ($)	1 Months Ended	3 Months Ended		12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Sep. 30, 2015	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2012	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015	Dec. 31, 2014
Income Tax Examination [Line Items]
Tax Cuts and Jobs Act of 2017, Corporate Federal Tax Rate	21.00%
Tax Cuts and Jobs Act of 2017, Net Operating Loss Deduction Limitation, Percent of Taxable income	80.00%
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Liability, Provisional Income Tax (Expense) Benefit, Gross				$ 559,000,000
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Provisional Income Tax Expense (Benefit)				8,000,000
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Net Income Reduction				$ 2,000,000
Consolidated Appropriations Act of 2016 [Abstract]
Excise Tax Delay				2 years
Unrecognized Tax Benefits, Interest on Income Taxes Accrued											$ (900,000)		$ 0	$ (100,000)
Interest Income (Expense) related to unrecognized tax benefits				$ 1,400,000	$ (900,000)		$ 100,000
Unrecognized Tax Benefits, Interest Receivable (Payable) on Income Taxes Accrued										$ (500,000)	900,000		0
Unrecognized Tax Benefits, Income Tax Penalties Accrued										0	0		0
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions										2,300,000	4,500,000
Unrecognized tax benefit — Temporary tax positions										2,000,000	24,200,000
Total unrecognized tax benefit	$ 4,300,000			28,700,000	24,700,000		13,200,000			4,300,000	28,700,000		$ 24,700,000	$ 13,200,000
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at Jan. 1				28,700,000	24,700,000		13,200,000
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions				900,000	1,400,000		4,200,000
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions				(600,000)	0		(600,000)
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions				1,300,000	3,900,000		9,000,000
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions				(19,900,000)	(1,300,000)		(1,100,000)
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities				(6,100,000)	0		0
Balance at Dec. 31	$ 4,300,000			$ 4,300,000	$ 28,700,000		$ 24,700,000
Tax Benefits Associated With NOL And Tax Credit Carryforwards [Abstract]
NOL and tax credit carryforwards										(5,900,000)	(5,900,000)
Decrease in Unrecognized Tax Benefits is Reasonably Possible										1,000,000
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent				35.00%	35.00%	[1]	35.00%	[1]
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent				0.90%	1.00%	[1]	1.00%	[1]
Effective Income Tax Rate Reconciliation, Tax Cuts and Jobs Act of 2017, Change in Tax Rate, Percent				(3.50%)	0.00%	[1]	0.00%	[1]
Effective Income Tax Rate Reconciliation Change In Unrecognized Tax Benefits, Percent				(1.00%)	0.80%	[1]	0.50%	[1]
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items, Percent				(0.70%)	(0.50%)	[1]	(0.30%)	[1]
Effective Income Tax Rate Reconciliation, Other Regulatory Items, Percent				(0.80%)	(1.00%)	[1]	(0.80%)	[1]
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent				0.20%	(0.20%)	[1]	1.70%	[1]
Effective Income Tax Rate Reconciliation, Percent				30.10%	35.10%	[1]	37.10%	[1]
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)				$ (20,858,000)	$ (40,853,000)		$ (1,327,000)
Current State and Local Tax Expense (Benefit)				(12,725,000)	(2,929,000)		2,448,000
Current Change In Unrecognized Tax Expense (Benefit)				(24,333,000)	3,126,000		11,281,000
Deferred Federal Income Tax Expense (Benefit)				89,934,000	116,404,000		67,640,000
Deferred State and Local Income Tax Expense (Benefit)				14,437,000	7,757,000		5,399,000
Deferred Change In Unrecognized Tax Expense (Benefit)				22,094,000	(1,178,000)		(10,203,000)
Deferred investment tax credits				(133,000)	(213,000)		(213,000)
Income Tax Expense (Benefit)				68,416,000	82,114,000		75,025,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred tax expense (benefit) excluding selected items				(414,231,000)	128,393,000		63,453,000
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities				540,744,000	(5,416,000)		(780,000)
Other Comprehensive Income (Loss), Tax				(48,000)	6,000		163,000
Deferred Income Tax Expense (Benefit)				126,465,000	$ 122,983,000		$ 62,836,000
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment										659,165,000	1,034,675,000	[2]
Deferred Tax Liabilities, Regulatory Assets										47,519,000	14,811,000	[2]
Deferred Tax Liabilities, Compensation and Benefits, Employee Benefits										33,815,000	51,895,000	[2]
Deferred Tax Liabilities, Other										4,604,000	3,267,000	[2]
Deferred Tax Liabilities, Gross										745,103,000	1,104,648,000	[2]
Deferred Tax Assets, Gross [Abstract]
Deferred Tax Assets Regulatory Liabilities										115,302,000	(13,167,000)	[2]
Deferred Tax Assets, Operating Loss Carryforwards										26,238,000	100,179,000	[2]
Deferred Tax Assets Unbilled Revenue Fuel Costs										10,448,000	10,226,000	[2]
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Employee Benefits										5,769,000	9,656,000	[2]
Deferred Tax Assets, Tax Credit Carryforwards										5,178,000	3,738,000	[2]
Deferred Tax Assets, Other										7,262,000	4,879,000	[2]
Deferred Tax Assets, Net of Valuation Allowance										170,197,000	115,511,000	[2]
Deferred Tax Liabilities, Net										574,906,000	989,137,000	[2]
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Year(s) under examination			2012 and 2013						2010 and 2011
Tax years under examination, Concluded		2012 and 2013
Year of carryback claim under examination									2009
Potential Tax Adjustments				$ 14,000,000
Earliest year subject to examination				2009
Operating Loss Carryforwards										115,000,000	275,000,000
Tax Credit Carryforward, Amount										5,000,000	4,000,000
Carryforward expiration date range, low				2021
Carryforward expiration date range, high				2037
State and Local Jurisdiction
Tax Audits [Abstract]
Earliest year subject to examination				2009
Operating Loss Carryforwards										$ 40,000,000	$ 60,000,000
Carryforward expiration date range, low				2021
Carryforward expiration date range, high				2036
Consolidated Appropriations Act of 2016; 2015, 2016, 2017 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent										50.00%
Consolidated Appropriations Act of 2016; 2016 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Production Tax Credit Rate, Percent										100.00%
Consolidated Appropriations Act of 2016; 2017 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Production Tax Credit Rate, Percent										80.00%
Consolidated Appropriations Act of 2016; 2018 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Production Tax Credit Rate, Percent										60.00%
Consolidated Appropriations Act of 2016; 2019 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Production Tax Credit Rate, Percent										40.00%
Investment Tax Credit Rate, Percent										30.00%
Consolidated Appropriations Act of 2016; 2020 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Investment Tax Credit Rate, Percent										26.00%
Consolidated Appropriations Act of 2016; 2021 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Investment Tax Credit Rate, Percent										22.00%
Consolidated Appropriations Act of 2016; After 2021 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Investment Tax Credit Rate, Percent										10.00%
Plant Related Regulatory Liability [Member]
Income Tax Examination [Line Items]
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Liability, Provisional Income Tax (Expense) Benefit				$ 426,000,000
Non-Plant Related Regulated Liability [Member]
Income Tax Examination [Line Items]
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Liability, Provisional Income Tax (Expense) Benefit				28,000,000
Non-Plant Related Regulatory Asset [Member]
Income Tax Examination [Line Items]
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Asset, Provisional Income Tax Expense (Benefit)				$ 45,000,000

[1] The prior periods included in this footnote have been reclassified to conform to current year presentation.

[2] The prior period included in this footnote has been reclassified to conform to current year presentation.

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Benefit Plans and Other Postretirement Benefits, Employees Represented by Local Labor Unions (Details)	Dec. 31, 2017 Employee
Employees Represented by Local Labor Unions Under Collective Bargaining Agreements Receiving Benefits [Abstract]
Approximate percent of employees receiving benefits who are represented by local labor unions under collective bargaining agreements (as a percent)	68.00%
Number of bargaining employees receiving benefits under several collective bargaining agreements	791

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Benefit Plans and Other Postretirement Benefits Benefit Plans and Other Postretirement Benefits, Fair Value Hierarchy (Details)	12 Months Ended
	Dec. 31, 2017
Commingled funds | Maximum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	90 days
Real estate funds | Minimum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	45 days
Real estate funds | Maximum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	90 days

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Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Plan [Member]
Pension Benefits [Abstract]
Total benefit obligation	$ 515,879	$ 483,601	$ 467,394
Net benefit cost recognized for financial reporting	$ 14,872	$ 17,446	$ 20,303
Expected average long-term rate of return on assets (as a percent)	6.78%	6.78%	7.22%
Expected average long-term rate of return on assets for next fiscal year (as a percent)	6.78%
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	100.00%	100.00%
Pension Plan [Member] | Domestic and international equity securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	34.00%	36.00%
Pension Plan [Member] | Long-duration fixed income and interest rate swap securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	31.00%	31.00%
Pension Plan [Member] | Short-to-intermediate fixed income securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	19.00%	15.00%
Pension Plan [Member] | Alternative investments
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	14.00%	16.00%
Pension Plan [Member] | Cash
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	2.00%	2.00%
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation	$ 2,000	$ 3,000
Minimum number of years historical achieved weighted average annual returns used to determine investment return assumptions (in years)	20 years
Xcel Energy Inc. | Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation	$ 37,000	44,000
Net benefit cost recognized for financial reporting	$ 5,000	$ 8,000

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Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) - Pension Plan [Member] - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 433,229	$ 380,395	$ 378,913
Plan asset investments measured at net asset value	142,808	123,595
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	184,519	178,136
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	105,902	78,664
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Cash equivalents
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	26,934	29,237
Plan asset investments measured at net asset value	0	0
Cash equivalents | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	26,934	29,237
Cash equivalents | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Cash equivalents | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	68,103	62,899
Plan asset investments measured at net asset value	0	0
U.S. equity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	68,103	62,899
U.S. equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. equity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	38,583	46,403
Plan asset investments measured at net asset value	26,427	21,931
Non U.S. equity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	12,156	24,472
Non U.S. equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. equity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. corporate bond funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	54,830	41,226
Plan asset investments measured at net asset value	0	0
U.S. corporate bond funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	54,830	41,226
U.S. corporate bond funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. corporate bond funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Emerging market equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	41,706	24,637
Plan asset investments measured at net asset value	41,706	24,637
Emerging market equity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Emerging market equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Emerging market equity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Emerging market debt funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	32,030	20,399
Plan asset investments measured at net asset value	22,063	10,574
Emerging market debt funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	9,967	9,825
Emerging market debt funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Emerging market debt funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Commodity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		2,876
Plan asset investments measured at net asset value		2,876
Commodity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Commodity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Commodity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Private equity investments
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	11,168	12,098
Plan asset investments measured at net asset value	11,168	12,098
Private equity investments | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Private equity investments | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Private equity investments | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Real estate
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	25,896	23,232
Plan asset investments measured at net asset value	25,896	23,232
Real estate | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Real estate | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Real estate | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Other commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	16,119	28,247
Plan asset investments measured at net asset value	15,476	28,247
Other commingled funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	643	0
Other commingled funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Other commingled funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Government securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	57,578	38,105
Plan asset investments measured at net asset value	0	0
Government securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Government securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	57,578	38,105
Government securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	41,041	36,293
Plan asset investments measured at net asset value	0	0
U.S. corporate bonds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	41,041	36,293
U.S. corporate bonds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	6,717	5,818
Plan asset investments measured at net asset value	0	0
Non U.S. corporate bonds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	6,717	5,818
Non U.S. corporate bonds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Mortgage-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		821
Plan asset investments measured at net asset value		0
Mortgage-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Mortgage-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		821
Mortgage-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Asset-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		389
Plan asset investments measured at net asset value		0
Asset-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Asset-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		389
Asset-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
U.S. equities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	15,157	10,477
Plan asset investments measured at net asset value	0	0
U.S. equities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	15,157	10,477
U.S. equities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. equities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	(2,633)	(2,762)
Plan asset investments measured at net asset value	72	0
Other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	(3,271)	0
Other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	566	(2,762)
Other | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 0	$ 0

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Benefit Plans and Other Postretirement Benefits, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) $ in Thousands		1 Months Ended	12 Months Ended
		Jan. 31, 2018 USD ($) Plan	Dec. 31, 2017 USD ($) Plan	Dec. 31, 2016 USD ($) Plan	Dec. 31, 2015 USD ($) Plan
Subsequent Event | Xcel Energy Inc.
Cash Flows [Abstract]
Number of pension plans to which contributions were made | Plan		4
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation at Dec. 31			$ 478,843	$ 453,317
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		$ 515,879	483,601	467,394
Service cost			9,758	9,761	$ 11,006
Interest cost			19,710	21,259	20,184
Plan amendments			(984)	0
Actuarial loss			31,218	25,053
Transfer to other plan			0	(3,305)
Benefit payments			(27,424)	(36,561)
Obligation at Dec. 31			515,879	483,601	467,394
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		433,229	380,395	378,913
Actual return on plan assets			56,756	23,306
Employer contributions			23,502	18,088
Transfer to other plan			0	(3,351)
Benefit payments			(27,424)	(36,561)
Fair value of plan assets at Dec. 31			433,229	380,395	378,913
Funded Status of Plans at Dec. 31 [Abstract]
Funded status	[1]		(82,650)	(103,206)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery Rates [Abstract]
Net loss			237,024	247,381
Prior service credit			(1,372)	0
Total			235,652	247,381
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
Current regulatory assets			13,851	13,524
Noncurrent regulatory assets			221,801	233,857
Total			$ 235,652	$ 247,381
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)			3.63%	4.13%
Expected average long-term increase in compensation level (as a percent)			3.75%	3.75%
Mortality table			RP-2014	RP-2014
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period			$ 24,000	$ 18,000	12,000
Components of Net Periodic Benefit Cost (Credit) [Abstract]
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			0	0	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
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)			4.13%	4.66%	4.11%
Expected average long-term increase in compensation level (as a percent)			3.75%	4.00%	3.75%
Expected average long-term rate of return on assets (as a percent)			6.78%	6.78%	7.22%
Allocated costs for pension plans sponsored by Xcel Energy Services Inc.			$ 8,000	$ 4,000	$ 5,000
Expected average long-term rate of return on assets for next fiscal year (as a percent)			6.78%
Number of years fair market value of plan assets is adjusted using calculated value method (in years)			5 years
Annual adjustment rate used in calculated value method (as a percent)			20.00%
Pension Plan [Member] | Xcel Energy Inc.
Cash Flows [Abstract]
Number of pension plans to which contributions were made | Plan			4	4	4
Total contributions to Xcel Energy's pension plans during the period			$ 162,000	$ 125,000	$ 90,000
Pension Plan [Member] | Subsequent Event
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period		8,000
Pension Plan [Member] | Subsequent Event | Xcel Energy Inc.
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period		$ 150,000

[1] Amounts are recognized in noncurrent liabilities on SPS’ balance sheets.

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Benefit Plans and Other Postretirement Benefits, Defined Contribution Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Contribution Plans [Abstract]
Contributions to 401(k) and other defined contribution plans	$ 3	$ 3	$ 3

XML

Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) - Other Postretirement Benefits Plan [Member]	Dec. 31, 2017	Dec. 31, 2016
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	100.00%	100.00%
Domestic and international equity securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	24.00%	25.00%
Short-to-intermediate fixed income securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	60.00%	57.00%
Alternative investments
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	9.00%	13.00%
Cash
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	7.00%	5.00%

XML

Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) - Other Postretirement Benefits Plan [Member] - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 44,039	$ 42,297	$ 42,684
Plan assets at net asset value	0	5,258
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	20,223	16,597
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	23,816	20,442
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Cash equivalents
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	2,787	1,966
Plan assets at net asset value	0	0
Cash equivalents | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	2,787	1,966
Cash equivalents | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Cash equivalents | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Insurance contracts
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	4,716	4,519
Plan assets at net asset value	0	0
Insurance contracts | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Insurance contracts | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	4,716	4,519
Insurance contracts | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	7,032	5,208
Plan assets at net asset value	0	0
U.S. equity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	7,032	5,208
U.S. equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. equity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S fixed income funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	3,245	2,593
Plan assets at net asset value	0	0
U.S fixed income funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	3,245	2,593
U.S fixed income funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S fixed income funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Emerging market debt funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	3,836	2,911
Plan assets at net asset value	0	0
Emerging market debt funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	3,836	2,911
Emerging market debt funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Emerging market debt funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Other commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		5,258
Plan assets at net asset value		5,258
Other commingled funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Other commingled funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Other commingled funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Government securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	5,480	3,611
Plan assets at net asset value	0	0
Government securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Government securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	5,480	3,611
Government securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	5,995	5,962
Plan assets at net asset value	0	0
U.S. corporate bonds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	5,995	5,962
U.S. corporate bonds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	2,027	1,653
Plan assets at net asset value	0	0
Non U.S. corporate bonds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	2,027	1,653
Non U.S. corporate bonds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Asset-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	2,218	1,810
Plan assets at net asset value	0	0
Asset-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Asset-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	2,218	1,810
Asset-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Mortgage-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	3,276	2,748
Plan assets at net asset value	0	0
Mortgage-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Mortgage-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	3,276	2,748
Mortgage-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. equities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	3,323	3,919
Plan assets at net asset value	0	0
Non U.S. equities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	3,323	3,919
Non U.S. equities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. equities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	104	139
Plan assets at net asset value	0	0
Other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	104	139
Other | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 0	$ 0

XML

Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) - Other Postretirement Benefits Plan [Member] - USD ($)		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		$ 41,860,000	$ 40,864,000
Service cost		875,000	775,000	$ 954,000
Interest cost		1,659,000	1,821,000	1,745,000
Medicare subsidy reimbursements		14,000	31,000
Plan participant's contributions		637,000	653,000
Actuarial loss		4,688,000	1,293,000
Benefit payments		(2,764,000)	(3,577,000)
Obligation at Dec. 31		46,969,000	41,860,000	40,864,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		42,297,000	42,684,000
Actual return on plan assets		3,686,000	1,978,000
Plan participant's contributions		637,000	653,000
Employer contributions		183,000	559,000
Benefit payments		(2,764,000)	(3,577,000)
Fair value of plan assets at Dec. 31		44,039,000	42,297,000	42,684,000
Funded Status of Plans at Dec. 31 [Abstract]
Funded status	[1]	(2,930,000)	437,000
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery Rates [Abstract]
Net loss		(8,620,000)	(12,595,000)
Prior service credit		(2,229,000)	(2,630,000)
Total		(10,849,000)	(15,225,000)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost (Credit) Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
Current regulatory liabilities		(827,000)	(1,004,000)
Noncurrent regulatory liabilities		(10,022,000)	(14,221,000)
Total		$ (10,849,000)	$ (15,225,000)
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)		3.62%	4.13%
Mortality table		RP 2014	RP 2014
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65		7.00%	5.50%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65		5.50%	5.50%
Ultimate health care trend assumption rate (as a percent)		4.50%
Period until ultimate trend rate is reached (in years)		5 years
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]
One-percent increase in APBO		$ 4,559,000
One-percent decrease in APBO		(3,858,000)
One-percent increase in service and interest components		266,000
One-percent decrease in service and interest components		(225,000)
Cash Flows [Abstract]
Expected contribution to postretirement health care plans during 2018		0
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		875,000	$ 775,000	954,000
Interest cost		1,659,000	1,821,000	1,745,000
Expected return on plan assets		(2,355,000)	(2,377,000)	(2,540,000)
Amortization of prior service cost		(401,000)	(401,000)	(401,000)
Amortization of net loss		(618,000)	(583,000)	(639,000)
Net periodic pension cost		$ (840,000)	$ (765,000)	$ (881,000)
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)		4.13%	4.65%	4.08%
Expected average long-term rate of return on assets (as a percent)		5.80%	5.80%	5.80%
Xcel Energy Inc.
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year		$ 20,000,000	$ 18,000,000	$ 18,000,000
Expected contribution to postretirement health care plans during 2018		$ 12,000,000

[1] Amounts are recognized in noncurrent liabilities and noncurrent assets on SPS’ balance sheet as of Dec. 31, 2017 and 2016

XML

Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details) $ in Thousands	Dec. 31, 2017 USD ($)
Pension Plan [Member]
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2018	$ 30,475
2019	28,755
2020	29,621
2021	29,721
2022	30,712
2023-2027	155,784
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2018	3,277
2019	3,189
2020	3,229
2021	3,351
2022	3,384
2023-2027	14,773
Expected Medicare Part D Subsidies [Abstract]
2018	22
2019	19
2020	21
2021	25
2022	30
2023-2027	141
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
2018	3,255
2019	3,170
2020	3,208
2021	3,326
2022	3,354
2023-2027	$ 14,632

XML

Other Income, Net (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Income and Expenses [Abstract]
Interest income	$ 2,407	$ 129	$ 129
Other nonoperating income	0	5	11
Insurance Policy Expense (Income), Net	(48)	(43)	(40)
Other Nonoperating Expense	0	0	(106)
Other income (expense), net	$ 2,359	$ 91	$ (6)

XML

Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) MWh in Thousands, $ in Millions		Dec. 31, 2017 USD ($) MWh Counterparty	Dec. 31, 2016 MWh
Credit Concentration Risk
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		8
Credit Concentration Risk | Municipal or Cooperative Entities or Other Utilities [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		7
Credit Concentration Risk | No Investment Grade Ratings from External Credit Rating Agencies [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		5
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 7.8
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		20.00%
Credit Concentration Risk | External Credit Rating, Investment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		2
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 10.6
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		28.00%
Credit Concentration Risk | External Credit Rating, Non Investment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		1
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 0.1
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		1.00%
Interest Rate Swap
Interest Rate Derivatives [Abstract]
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months | $		$ (0.1)
Electric Commodity (in megawatt hours)
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract]
Derivative, Nonmonetary Notional Amount | MWh	[1]	4,251	2,685

[1] Amounts are not reflective of net positions in the underlying commodities.

XML

Fair Value of Financial Assets and Liabilities, Financial Impact of Qualifying Cash Flow Hedges (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Income (Loss) [Roll Forward]
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)

XML

Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges	$ 0	$ 0	$ 0
Recognized gains (losses) from fair value hedges or related hedged transactions	0	0	0
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Interest Rate Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net	(100,000)	(200,000)	(300,000)
Other Derivative Instruments | Electric Commodity
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	500,000	3,000,000	(3,100,000)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	$ (800,000)	$ (2,100,000)	$ 1,600,000

XML

Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($)	Dec. 31, 2017		Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative Asset, Collateral, Obligation to Return Cash, Offset	$ 0		$ 0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0		0
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	15,882,000		5,114,000
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	18,954,000		22,113,000
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	3,565,000		3,565,000
Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	19,949,000		23,513,000
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	12,723,000		1,955,000
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(1,994,000)	[1]	(1,299,000)	[2]
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	12,723,000		1,955,000
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(1,994,000)	[1]	(1,299,000)	[2]
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(1,994,000)	[1]	(1,299,000)	[2]
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(1,994,000)	[1]	(1,299,000)	[2]
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	14,717,000		3,254,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	14,717,000		3,254,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	1,994,000		1,299,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	1,994,000		1,299,000
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,159,000	[3]	3,159,000	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	18,954,000	[3]	22,113,000	[4]
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	3,565,000	[3]	3,565,000	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	19,949,000	[3]	23,513,000	[4]
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	14,717,000		3,254,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	14,717,000		3,254,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	1,994,000		1,299,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 1,994,000		$ 1,299,000

[1] 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.

[2] 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.

[3] 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.

[4] 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.

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Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) (Details) - Commodity Contract - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of period	$ 1,955,000	$ 5,060,000	$ 15,884,000
Purchases	41,176,000	7,616,000	23,425,000
Settlements	(55,758,000)	(41,923,000)	(31,703,000)
Gains (losses) recognized as regulatory assets	25,350,000	31,202,000	(2,546,000)
Balance at end of period	12,723,000	1,955,000	5,060,000
Transfers into Level 3	0	0	0
Transfers out of Level 3	$ 0	$ 0	$ 0

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Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 1,829,941	$ 1,635,858
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 2,001,992	$ 1,741,502

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Rate Matters (Details) $ in Millions		1 Months Ended			12 Months Ended
	Feb. 16, 2018	Feb. 28, 2018	Oct. 31, 2017 USD ($) MW	Nov. 30, 2016 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Appeal of the Texas 2015 Electric Rate Case Decision
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount								$ 42.0
Texas 2017 Electric Rate Case [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount					$ 55.0
Public Utilities, Requested Rate Increase (Decrease), Percentage					5.80%
Public Utilities, Number of Months in Test Year					12 months
Public Utilities, Number of Months in Test Year which are Estimated					3 months
Public Utilities, Requested Return on Equity, Percentage					10.25%
Public Utilities, Requested Rate Base, Amount					$ 1,900.0
Public Utilities, Requested Equity Capital Structure, Percentage					53.97%
Public Utilities, Incremental revenue request					$ 69.0
Appeal of the New Mexico 2016 Electric Rate Case Decision
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 41.0
Public Utilities, Requested Rate Increase (Decrease), Percentage				10.90%
Public Utilities, Requested Return on Equity, Percentage				10.10%
Public Utilities, Requested Rate Base, Amount				$ 832.0
Public Utilities, Requested Equity Capital Structure, Percentage				53.97%
New Mexico 2017 Electric Rate Case [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 43.0
Public Utilities, Requested Return on Equity, Percentage			10.25%
Public Utilities, Requested Rate Base, Amount			$ 885.0
Public Utilities, Requested Equity Capital Structure, Percentage			53.97%
Public Utilities, Decline in MW Sales from Wholesale Customers | MW			380
Public Utility Commission of Texas (PUCT) | Appeal of the Texas 2015 Electric Rate Case Decision
Rate Matters [Abstract]
Public Utilities, Approved Rate Decrease, Net of Rate Case Expenses							$ 4.0
Southwest Power Pool (SPP)
Rate Matters [Abstract]
Public Utilities, Billed Charges For Transmission Service Upgrades						$ 13.0
Southwest Power Pool (SPP) | SPP Open Access Transmission Tariff Upgrade Costs
Rate Matters [Abstract]
Public Utilities, Monthly Billed Charges For Transmission Service Upgrades					0.5
Transmission Cost Recovery Factory (TCRF) Rider [Member] | Texas 2017 Electric Rate Case [Member]
Rate Matters [Abstract]
Public Utilities, Rider Conversion to Base Rates					$ (14.0)
Subsequent Event | New Mexico 2017 Electric Rate Case [Member]
Rate Matters [Abstract]
Public Utilities, Revised Requested Equity Capital Structure, Percentage		58.00%
SPS | Subsequent Event | Texas 2017 Electric Rate Case [Member]
Rate Matters [Abstract]
Public Utilities, Revised Requested Equity Capital Structure, Percentage	58.00%

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Commitments and Contingencies, Capital Commitments (Details) - Capital Commitments	12 Months Ended
	Dec. 31, 2017 kV MW
TUCO to Yoakum to Hobbs Plant Transmission Line
Capital Commitments [Abstract]
Voltage capacity for transmission line (in kV)	345
Hobbs Plant to China Draw Transmission Line
Capital Commitments [Abstract]
Voltage capacity for transmission line (in kV)	345
New Mexico and Texas Wind Projects [Member]
Capital Commitments [Abstract]
Public Utilities, Facility Generating Capacity | MW	1,000

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Commitments and Contingencies, Fuel Contracts (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)
Coal
Fuel Contracts [Abstract]
2018	$ 172
2019	106
2020	64
2021	20
2022	21
Thereafter	0
Total	383
Natural Gas Supply
Fuel Contracts [Abstract]
2018	11
2019	0
2020	0
2021	0
2022	0
Thereafter	0
Total	11
Natural Gas Storage and Transportation
Fuel Contracts [Abstract]
2018	29
2019	32
2020	32
2021	27
2022	21
Thereafter	50
Total	$ 191
Minimum
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date	2018
Maximum
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date	2029

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Commitments and Contingencies, Purchased Power Agreements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Long-term Contract for Purchase of Electric Power [Line Items]
Purchase Power Agreement Expiration Date	2033
Capacity
Purchased Power Agreements (PPAs) [Abstract]
Payments for capacity	$ 58	$ 57	$ 57
Estimated Future Payments Under PPAs [Abstract]
2018	58
2019	20
2020	12
2021	12
2022	13
Thereafter	18
Total	$ 133

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Commitments and Contingencies, Leases (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Leased Assets [Line Items]
Operating Lease Purchase Power Agreement Expiration Date		2033
Operating Leases, Future Minimum Payments Due [Abstract]
2018		$ 57
2019		56
2020		56
2021		56
2022		56
Thereafter		604
Office Space and Other Equipment
Operating Leases [Abstract]
Total expenses under operating lease obligations		58	$ 57	$ 55
Operating Leases, Future Minimum Payments Due [Abstract]
2018		5
2019		5
2020		5
2021		5
2022		5
Thereafter		61
Purchased Power Agreements
Operating Leases [Abstract]
Payments for capacity for PPAs under operating lease obligations		51	$ 51	$ 49
Operating Leases, Future Minimum Payments Due [Abstract]
2018	[1],[2]	52
2019	[1],[2]	51
2020	[1],[2]	51
2021	[1],[2]	51
2022	[1],[2]	51
Thereafter	[1],[2]	$ 543

[1] Amounts do not include PPAs accounted for as executory contracts.

[2] PPA operating leases contractually expire through 2033.

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Commitments and Contingencies, Variable Interest Entities (Details) - MW	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Purchased Power Agreements [Abstract]
VIE Purchase Power Agreement Expiration Date	2041
Independent Power Producing Entities
Purchased Power Agreements [Abstract]
Generating capacity (in MW)	897	897
Harrington Station Power Plant
Fuel Contracts [Abstract]
Coal Supply Agreement Expiration Date	2022
Tolk Station Power Plant
Fuel Contracts [Abstract]
Coal Supply Agreement Expiration Date	2022

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Commitments and Contingencies Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) - Other MGP, Landfill, or Disposal Sites $ in Millions	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Site Contingency [Line Items]
Number of identified MGP sites under current investigation and/or remediation	1
Accrual for Environmental Loss Contingencies	$ 0.1	$ 0.1

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Commitments and Contingencies, Environmental Contingencies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)	Dec. 31, 2015 Period
Implementation of the National Ambient Air Quality Standard for Sulfur Dioxide
Environmental Requirements [Abstract]
Number of Phases Under a Consent Decree Which the EPA is Requiring States to Evaluate Areas for Attainment	3
National Ambient Air Quality Standards for Ozone
Environmental Requirements [Abstract]
Number of Hours Measured for Standard | Period		8
Former Level of Air Quality Concentrations (in parts per billion)		75
Revised Level of Air Quality Concentrations (in parts per billion)		70
Harrington Units 1 and 2 | Implementation of the National Ambient Air Quality Standard for Sulfur Dioxide
Environmental Requirements [Abstract]
Number of Years Unclassifiable Areas Will Be Monitored	3 years
Harrington Units 1 and 2 | Capital Commitments | Regional Haze Rules
Environmental Requirements [Abstract]
Liability for Estimated Cost to Comply with Regulation	$ 400
Tolk Units 1 and 2 | Capital Commitments | Regional Haze Rules
Environmental Requirements [Abstract]
Liability for Estimated Cost to Comply with Regulation	$ 600

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Commitments and Contingencies, Asset Retirement Obligations (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017		Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 28,663,000	[1]	$ 27,233,000
Liabilities Incurred	0		0
Liabilities settled	0		0
Accretion	1,537,000		1,451,000
Cash flow revisions	(1,676,000)	[2]	(21,000)
Ending balance	28,524,000	[3]	28,663,000	[1]
Electric Plant Steam Production Asbestos
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	19,070,000	[1]	17,981,000
Accretion	1,155,000		1,089,000
Cash flow revisions	(1,676,000)	[2]	0
Ending balance	18,549,000	[3]	19,070,000	[1]
Electric Plant Steam Production Ash Containment
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	1,593,000	[1]	1,513,000
Accretion	85,000		80,000
Cash flow revisions	0	[2]	0
Ending balance	1,678,000	[3]	1,593,000	[1]
Electric Plant Electric Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	6,799,000	[1]	6,559,000
Accretion	249,000		240,000
Cash flow revisions	0	[2]	0
Ending balance	7,048,000	[3]	6,799,000	[1]
Electric Plant Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	1,201,000	[1]	1,180,000
Accretion	48,000		42,000
Cash flow revisions	0	[2]	(21,000)
Ending balance	$ 1,249,000	[3]	$ 1,201,000	[1]

[1] There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2016.

[2] In 2017, an asbestos ARO was revised for changes in timing of estimated cash flows.

[3] There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2017.

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Commitments and Contingencies, Removal Costs (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 197	$ 209

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Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 31,538		$ 38,721
Regulatory Asset, Noncurrent		362,943		346,683
Past expenditures not currently earning a return		64,000		65,000
Revaluation of Regulatory Assets for New Federal Tax Rate [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$ 23,000
Pension and Retiree Medical Obligations
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Various
Regulatory Asset, Current	[1]	$ 12,752		13,986
Regulatory Asset, Noncurrent	[1]	$ 223,038		234,171
Excess deferred taxes - TCJA
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Various
Regulatory Asset, Current		$ 0		0
Regulatory Asset, Noncurrent		$ 44,685		0
Net AROs
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Plant lives
Regulatory Asset, Current	[2]	$ 0		0
Regulatory Asset, Noncurrent	[2]	$ 24,201		24,352
Recoverable Deferred Taxes on AFUDC Recorded in Plant
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Plant lives
Regulatory Asset, Current		$ 0	[3]	0
Regulatory Asset, Noncurrent		$ 23,888	[3]	44,258
Losses on Reacquired Debt
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Term of related debt
Regulatory Asset, Current		$ 807		127
Regulatory Asset, Noncurrent		$ 22,664		1,617
Renewable Resources and Environmental Initiatives
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		One to three years
Regulatory Asset, Current		$ 1,600		3,580
Regulatory Asset, Noncurrent		$ 1,301		2,900
Conservation Programs
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		One to two years
Regulatory Asset, Current	[4]	$ 2,674		3,754
Regulatory Asset, Noncurrent	[4]	$ 733		2,431
Other Regulatory Assets
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Various
Regulatory Asset, Current		$ 13,705		17,274
Regulatory Asset, Noncurrent		$ 22,433		$ 36,954

[1] (a) Includes the non-qualified pension plan.

[2] (b) Includes amounts recorded for future recovery of AROs.

[3] (c) Includes a write-down of $23.2 million as a result of the revaluation of deferred tax gross up at the new federal tax rate at Dec. 31, 2017.

[4] (d) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

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Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 68,835		$ 41,577
Regulatory Liability, Noncurrent		$ 784,564		233,454
Excess deferred taxes - TCJA
Regulatory Liabilities [Line Items]
Regulatory liability, remaining amortization period		Various
Regulatory Liability, Current		$ 0	[1]	0
Regulatory Liability, Noncurrent		563,662	[1]	0
Revaluation of Non-plant ADIT		$ 28,000
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory liability, remaining amortization period		Plant lives
Regulatory Liability, Current		$ 0		0
Regulatory Liability, Noncurrent		$ 196,875		208,638
Revenue Subject to Refund
Regulatory Liabilities [Line Items]
Regulatory liability, remaining amortization period		One to two years
Regulatory Liability, Current		$ 6,825		5,093
Regulatory Liability, Noncurrent		$ 6,503		3,602
Gain From Asset Sales
Regulatory Liabilities [Line Items]
Regulatory liability, remaining amortization period		Various
Regulatory Liability, Current		$ 0		0
Regulatory Liability, Noncurrent		$ 2,476		2,530
Deferred Electric Energy Costs
Regulatory Liabilities [Line Items]
Regulatory liability, remaining amortization period		Less than one year
Regulatory Liability, Current		$ 48,460		32,451
Regulatory Liability, Noncurrent		$ 0		0
Contract Valuation Adjustments
Regulatory Liabilities [Line Items]
Regulatory liability, remaining amortization period		Term of related contract
Regulatory Liability, Current	[2]	$ 12,723		1,955
Regulatory Liability, Noncurrent	[2]	$ 0		0
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Regulatory liability, remaining amortization period		Various
Regulatory Liability, Current		$ 827		2,078
Regulatory Liability, Noncurrent		$ 15,048		$ 18,684

[1] (a) Primarily relates to the revaluation of recoverable/regulated plant ADIT and $28.0 million revaluation impact of non-plant ADIT at Dec. 31, 2017.

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

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Other Comprehensive Income (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period		$ 1,931,696
(Gains) losses reclassified from net accumulated other comprehensive loss		83	$ 139
Adoption of ASU No. 2018-02		0
Accumulated other comprehensive loss at end of period		2,130,363	1,931,696
AOCI Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period		(1,290)	(1,281)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax			(148)
(Gains) losses reclassified from net accumulated other comprehensive loss		83	139
Net current period other comprehensive income (loss)		83	(9)
Adoption of ASU No. 2018-02	[1]	(260)
Accumulated other comprehensive loss at end of period		(1,467)	(1,290)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period		(612)	(464)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax			(148)
(Gains) losses reclassified from net accumulated other comprehensive loss		44	0
Net current period other comprehensive income (loss)		44	(148)
Adoption of ASU No. 2018-02	[1]	(123)
Accumulated other comprehensive loss at end of period		(691)	(612)
Gains and Losses on Cash Flow Hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period		(678)	(817)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax			0
(Gains) losses reclassified from net accumulated other comprehensive loss		39	139
Net current period other comprehensive income (loss)		39	139
Adoption of ASU No. 2018-02	[1]	(137)
Accumulated other comprehensive loss at end of period		$ (776)	$ (678)

[1] 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.

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Other Comprehensive Income - Reclassification out of AOCI (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		$ (227,629)	$ (234,271)	$ (202,288)
Tax benefit		68,416	82,114	$ 75,025
(Gains) losses reclassified from net accumulated other comprehensive loss		83	139
Accumulated Defined Benefit Plans Adjustment, Net Gain (Loss) Attributable to Parent [Member] | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	[1]	69	0
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
(Gains) losses reclassified from net accumulated other comprehensive loss		44	0
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member] | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		69	0
Reclassification from AOCI, Current Period, Tax		(25)	0
(Gains) losses reclassified from net accumulated other comprehensive loss		44	0
Gains and Losses on Cash Flow Hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
(Gains) losses reclassified from net accumulated other comprehensive loss		39	139
Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		63	219
Tax benefit		(24)	(80)
Total, net of tax		39	139
Gains and Losses on Cash Flow Hedges | Interest Rate Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest charges	[2]	$ 63	$ 219

[1] Included in the computation of net periodic pension and postretirement benefit costs. See Note 7 for details regarding these benefit plans.

[2] Included in interest charges.

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Related Party Transactions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating revenues [Abstract]
Electric	$ 2	$ 56	$ 0
Operating expenses [Abstract]
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	0	189	156
Interest income	0	0	$ 6
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	1,297	949
Accounts payable	22,577	14,414
NSP-Minnesota
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	964	935
Accounts payable	0	0
NSP-Wisconsin
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	7	0
Accounts payable	0	333
PSCo
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0	0
Accounts payable	279	745
Other Subsidiaries of Xcel Energy Inc.
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	326	14
Accounts payable	$ 22,298	$ 13,336

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Summarized Quarterly Financial Data (Unaudited) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 426,509	$ 551,623	$ 479,796	$ 460,072	$ 464,749	$ 554,926	$ 440,445	$ 390,839
Operating income	41,498	122,407	74,489	58,415	62,964	122,362	68,386	53,569	$ 296,809	$ 307,281	$ 274,465
Net income	$ 31,015	$ 67,781	$ 35,362	$ 25,055	$ 29,077	$ 68,346	$ 32,211	$ 22,523	$ 159,213	$ 152,157	$ 127,263

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Schedule II, Valuation and Qualifying Accounts (Details) - Allowance for Bad Debts - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1		$ 6,379	$ 5,888	$ 5,839
Charged to costs and expenses		5,091	6,066	4,655
Charged to other accounts	[1]	1,169	907	1,036
Deductions from reserves	[2]	6,291	6,482	5,642
Balance at Dec. 31		$ 6,348	$ 6,379	$ 5,888

[1] Recovery of amounts previously written off.

[2] Deductions relate primarily to bad debt write-offs.