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~~2018



¨	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~~001-03789		75-0575400
~~State or other jurisdiction of incorporation or organization~~(Commission File Number)		(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~~

(Registrant, State of incorporation or Organization, Address of Principal Executive Officers and Telephone Number)

SOUTHWESTERN PUBLIC SERVICE COMPANY

(a New Mexico company)

790 South Buchanan Street

Amarillo, Texas 79101

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,”~~filer”, “accelerated ~~filer,”~~filer”, “smaller reporting ~~company,”~~company”, and “emerging growth company” in Rule 12b-2 of the Exchange ~~Act~~



Act. ¨Large accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨ Smaller Reporting Company ¨ Emerging growth company¨		~~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~~22, 2019, 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~~2019 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about April ~~3, 2018.~~1, 2019. 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
	FORWARD LOOKING STATEMENTS	4
	WHERE TO FIND MORE INFORMATION	4
	COMPANY OVERVIEW	54
	ELECTRIC UTILITY OPERATIONS	5
	~~Public Utility Regulation~~Electric Operating Statistics	5
	Energy Sources	6
	Capacity and Demand	6
~~Energy Sources and Related Transmission Initiatives~~	6
~~Fuel Supply and Costs~~Public Utility Regulation	7
	~~Fuel Sources~~GENERAL	7
	~~Renewable Energy Sources~~ENVIRONMENTAL MATTERS	8
	~~Wholesale Commodity Marketing Operations~~EMPLOYEES	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	128
Item 1B —	Unresolved Staff Comments	2113
Item 2 —	Properties	2213
Item 3 —	Legal Proceedings	2213
Item 4 —	Mine Safety Disclosures	2213

PART II	PART II	2314
Item 5 —	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	2314
Item 6 —	Selected Financial Data	2314
Item 7 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2314
Item 7A —	Quantitative and Qualitative Disclosures About Market Risk	2516
Item 8 —	Financial Statements and Supplementary Data	2716
Item 9 —	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	7040
Item 9A —	Controls and Procedures	7040
Item 9B —	Other Information	7041

PART III	PART III	7141
Item 10 —	Directors, Executive Officers and Corporate Governance	7141
Item 11 —	Executive Compensation	7141
Item 12 —	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	7141
Item 13 —	Certain Relationships and Related Transactions, and Director Independence	7141
Item 14 —	Principal Accountant Fees and Services	7141

PART IV	PART IV	7141
Item 15 —	Exhibits, Financial Statement Schedules	7141
Schedule II	Valuation and Qualifying Accounts	43
Item 16 - —	Form 10-K Summary	7743

SIGNATURES		7544

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

PART I

Item l — Business

~~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
NPRM	Notice of Proposed Rulemaking
PHMSA	Pipeline and Hazardous Materials Safety Administration
PUCT	Public Utility Commission of Texas
SEC	Securities and Exchange Commission
TCEQ	Texas Commission on Environmental Quality

Electric and Resource Adjustment Clauses
DCRF	Distribution cost recovery factor
DSM	Demand side management
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~~ARAM	~~Administrative law judge~~
~~APBO~~	~~Accumulated postretirement benefit obligation~~Average rate assumption method
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~~Corps	~~Certificate~~U.S. Army Corps of ~~convenience and necessity~~Engineers
CPP	Clean Power Plan
CSAPR	Cross-State Air Pollution Rule
CWIP	Construction work in progress
EGU	Electric generating unit


ELG
~~ERCOT~~	~~Electric Reliability Council of Texas~~Effluent limitations guidelines
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
FTR	Financial transmission right
GAAP	Generally accepted accounting principles



GHG	Greenhouse gas
IM	Integrated Marketplace
IPP	Independent power ~~producers~~
~~IRC~~	~~Internal Revenue Code~~producing entity
ITC	Investment tax credit
~~MISO~~MGP	~~Midcontinent Independent System Operator, Inc.~~Manufactured gas plant
Moody’s	Moody’s Investor Services
NAAQS	National Ambient Air Quality Standard
Native load	Customer demand of retail and wholesale customers whereby a utility has an obligation to serve under statute or long-term contract.
NAV	Net asset value
NOL	Net operating loss
NOx	Nitrogen oxide
NTC	Notifications to construct
O&M	Operating and maintenance
~~OCI~~OATT	~~Other comprehensive income~~Open Access Transmission Tariff
~~PJM~~Paris Agreement	~~PJM Interconnection, LLC~~Establishes a framework for GHG mitigation actions by all countries (“nationally determined contributions”)
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
ROFR	Right-of-first-refusal
RPS	Renewable portfolio standards
RTO	Regional Transmission Organization
~~SIP~~SERP	~~State implementation~~Supplemental executive retirement 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
VIE	Variable interest entity

Measurements
KV	Kilovolts
KWh	Kilowatt hours
MMBtu	Million British thermal units
MW	Megawatts
MWh	Megawatt hours
ppb	Parts per billion

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, 2018 (including risk factors listed from time to time by SPS in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K hereto), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: changes in environmental laws and regulations; climate change and other weather, natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; ability to recover costs from customers; reductions in our credit ratings and the costs of maintaining certain contractual relationships; actions of credit rating agencies; general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of SPS to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; tax laws; operational safety; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices; costs of potential regulatory penalties; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; fuel costs; and employee work force and third party contractor factors.

Where To Find More Information

SPS is a wholly owned subsidiary of Xcel Energy Inc., and Xcel Energy’s website address is www.xcelenergy.com. Xcel Energy makes available, free of charge through its website, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the SEC. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically at http://www.sec.gov.

COMPANY OVERVIEW

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 customersconducts business in Texas and New ~~Mexico. Approximately 71 percent of SPS’ retail electric operating revenues were derived from operations in Texas during 2017~~Mexico 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~~generates, purchases, transmits, distributes 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.sells electricity.





		SPS
		Electric customers	0.4 million
		Earnings contribution	15% to 20%
		Total assets	$6.7 billion
		Electric generating capacity	4,406 MW

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

ELECTRIC UTILITY OPERATIONS

Electric Operating Statistics



	Year Ended Dec. 31
	2018			2017			2016
Electric sales (Millions of KWh)
Residential	3,645			3,356			3,478
Large C&I	11,214			10,721			10,518
Small C&I	5,041			4,701			4,708
Public authorities and other	550			527			555
Total retail	20,450			19,305			19,259
Sales for resale	10,060			7,759			8,689
Total energy sold	30,510			27,064			27,948

Number of customers at end of period
Residential	308,884			306,248			305,076
Large C&I	232			221			219
Small C&I	77,269			77,351			77,319
Public authorities and other	6,322			6,316			6,377
Total retail	392,707			390,136			388,991
Wholesale	7			7			8
Total customers	392,714			390,143			388,999

Electric revenues (Millions of Dollars)
Residential	$	361.5		$	367.2		$	343.5
Large C&I	457.2			516.8			462.6
Small C&I	364.0			376.0			322.6
Public authorities and other	44.1			48.0			44.9
Total retail	1,226.8			1,308.0			1,173.6
Wholesale	427.9			388.7			414.8
Other electric revenues	278.5			221.3			262.6
Total electric revenues	$	1,933.2		$	1,918.0		$	1,851.0

KWh sales per retail customer	52,074			49,483			49,510
Revenue per retail customer	$	3,124		$	3,353		$	3,017
Residential revenue per KWh		9.92	¢		10.94	¢		9.88	¢
Large C&I revenue per KWh	4.08			4.82			4.40
Small C&I revenue per KWh	7.22			8.00			6.85
Total retail revenue per KWh	6.00			6.78			6.09
Wholesale revenue per KWh	4.25			5.01			4.77

Energy Sources 2018

*Distributed generation from the Solar*Rewards^® program is not included (approximately 13 million KWh for 2018).

Energy Source Statistics

In 2018, of SPS’ total energy generation, 49% was owned and 51% was purchased. In 2017, 47% was owned and 53% was purchased.

Renewable Sources

SPS’ renewable energy portfolio includes wind and solar power from PPAs. As of Dec. 31, 2018, SPS was in compliance with its applicable RPS. Renewable percentages will vary year over year based on local weather, system demand and transmission constraints.

SPS

Renewable energy as a percentage of SPS’ total:



	2018		2017
Wind	19.1	%	21.2	%
Solar	2.0		2.8
Renewable	21.1	%	24.0	%

Wind — SPS has 18 PPAs with facilities ranging from under one MW to 250 MW.

SPS had approximately 1,565 MW and 1,500 MW of wind energy on its system at the end of 2018 and 2017, respectively.

Average cost per MWh of wind energy under the IPP contracts and QF tariffs were approximately $26 and $27 for 2018 and 2017, respectively.

In 2018, SPS began construction on the Sagamore and Hale County wind farms. Refer to the SPS Public Utility Regulation (Wind Development) section for further information.

Non-Renewable Sources

Delivered cost per MMBtu of each significant category of fuel consumed for owned electric generation and the percentage of total fuel requirements represented by each category of fuel:



	Coal				Natural Gas
	Cost		Percent		Cost		Percent

2018	$	2.04	56	%	$	2.24	44	%
2017	2.18		74		3.39		26

Weighted average cost per MMBtu of all fuels for owned electric generation were $2.13 in 2018 and $2.50 in 2017.

See Items 1A and 7 for further information.

Coal — Inventory maintained (in days):



Normal	Dec. 31, 2018 Actual	Dec. 31, 2017 Actual ^(a)
35 - 50	44	52


^(a)	Milder weather, purchase commitments and low power and natural gas prices impacted coal inventory levels.

Coal requirements were 5.1 million tons in 2018 and 5.5 million tons in 2017. Coal supply as a percentage of requirements for 2019 is 4.1 million tons or 64% of contracted coal supply. The general coal purchasing objective is to contract for approximately 75% of year one requirements, 40% of year two requirements and 20% of year three requirements.

Contracted coal transportation as a percentage of requirements in 2019 and 2020 is 100%.

Natural Gas — Natural gas supplies, transportation and storage services for power plants are procured to provide an adequate supply of fuel. Remaining requirements are procured through a liquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to natural gas indices. Natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes or payments in lieu of delivery.

Contracts and commitments at Dec. 31:



(Millions of Dollars)	Gas Supply		Gas Transportation and Storage ^(a)
2018	$	20	$	152
2017	11		191
Year of Expiration	One year or less		2019 - 2033


^(a)	For incremental supplies, there are limited on-site fuel storage facilities, with a primary reliance on the spot market.

Capacity and Demand

Uninterrupted system peak demand for SPS for the last two years, is as follows:



System Peak Demand (in MW)
2018		2017
4,648	July 19	4,374	July 26

The peak demand typically occurs in the summer. The increase in peak load from 2017 to 2018 is partly due to warmer weather in 2018.

SPS

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 PUCT 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.~~rates in Texas.

EECRF — Recovers costs ~~associated with providing~~for energy efficiency programs in Texas.

EE rider — Recovers costs ~~associated with providing~~for energy efficiency programs in New Mexico.

FPPCAC — Adjusts monthly to recover the actual fuel and purchased power ~~costs.~~costs in New Mexico.

PCRF — ~~Allows recovery of certain~~Recovers purchased power costs ~~in Texas that are~~ not included in ~~base rates.~~rates in Texas.

RPS — Recovers deferred costs ~~associated with~~for 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.~~rates in Texas.

~~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. SO~~₂ ~~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~~4% 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.

~~Capacity and Demand~~

~~Uninterrupted system peak demand for SPS for each~~ Wholesale customers also pay the jurisdictional allocation 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.~~

production costs.

Energy Sources and ~~Related~~ Transmission ~~Initiatives~~

Service Providers

SPS expects to use ~~existing~~ electric generating stations, power purchases, DSM and new generation options to meet its system capacity requirements. In addition, ~~SPS~~it has evaluated water supply issues at ~~its~~the 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~~expected. SPS installed a horizontal water well that ~~could~~may 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~~it sought a decrease to the remaining life of the facility in ~~its current~~the 2017 Texas and New Mexico rate case ~~proceedings (see Note 10).~~

proceedings.

Purchased Power— — SPS ~~has contracts to purchase~~purchases 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.~~ charges.

SPS also makes short-term purchases to meet system load and energy requirements to replace owned 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~~ Development— In ~~March 2017, SPS filed proposals with~~2018, the NMPRC and ~~the~~ PUCT approved SPS’ proposal to ~~build, own and operate 1,000~~add 1,230 MW of new wind generation, ~~through two wind farms for a cost~~including ownership of ~~approximately $1.6 billion. In addition, the proposal includes a PPA for 230 MW of wind.~~1,000 MW.

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

~~An investment cap of $1,675 per KW, which is equal to 102.5 percent of the estimated construction costs;~~

~~SPS customers would receive a credit to their bills if actual capacity factors fall below 48 percent;~~

~~SPS customers would receive 100 percent of the federal PTC; and~~

SPS can file a HTY rate case and include projected capital additions for the wind farms five months beyond the end of the test year. Interim rates would also be made effective 30 days after filing which will allow SPS to closely match the start of cost recovery for that wind farm with the in service date.

~~On Feb. 9,~~March 2018, the ~~Hearing Examiner issued~~NMPRC approved SPS’ petition to build and own Sagamore, 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 Sagamore522 MW wind project in New Mexico ~~are scheduled~~which is expected to be placed into service in ~~service by mid-2019 and year-end 2020, respectively.~~

~~Lubbock Power & Light’s (LP&L’s) Request for Participation in ERCOT —~~ 2020. In ~~September 2017, LP&L filed its application with~~May 2018, the PUCT approved SPS’ petition to build and ~~proposed to transition~~own Hale County, a ~~portion of its load to ERCOT no later than June 2021. As a result of LP&L’s proposal, approximately $18 million~~478 MW wind project 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 FeeTexas which is expected to be ~~determined by the PUCT.~~

~~In February 2018, SPS, LP&L, the PUCT Staff and various other parties filed a stipulation that provides~~placed into service in 2019. Both projects qualify for 100% of PTCs. SPS’ ~~customers with an Interconnection Switching Fee of approximately $24 million to compensate them~~capital investment 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 decisionthese wind projects 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.~~to be approximately $1.6 billion.

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~~The PUCT subsequently issued an order finding that SPS does not possess an exclusive right to construct and operate transmission ~~facilities within its service area.~~facilities. 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~~In September 2018, the ~~case.~~

~~Fuel Supply and Costs~~

~~The following table shows~~District Court affirmed 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.

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.

PUCT’s ROFR order. 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.

~~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 initiatedfiled 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.additional appeal.

~~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

~~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.

Wholesale and Commodity Marketing Operations

GENERAL

Seasonality

~~The demand~~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.~~

information.

Competition

SPS is a vertically integrated utility subject to traditional cost-of-service ~~regulation. However,~~regulation by state public utilities commissions. SPS is subject to ~~different~~ public policies that promote competition and ~~the~~ development of energy markets. SPS’ industrial and large commercial customers have the ability ~~to own or operate facilities~~ to generate their own electricity. In addition, customers may have the option of substituting other fuels ~~such as natural gas, steam~~ or ~~chilled water for heating, cooling and manufacturing purposes, or the option of~~ relocating their facilities to a lower cost region.

Customers ~~also~~ have the opportunity to supply their own power with distributed generation including, but not limited to, 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 Texas and New Mexico, have policies designed to promote the development of solar and other distributed energy resources through ~~significant~~ incentive ~~policies; with~~policies. With these incentives and federal tax subsidies, distributed generating resources are potential competitors to SPS’ electric service business.

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 No. 1000 seeks to establish competition for construction and operation of certain new electric transmission facilities. State utilities commissions have also created resource planning programs that promote competition for electricity generation resources used to provide service to retail customers.

SPS has franchise agreements with ~~certain~~ cities subject to periodic ~~renewal. If~~renewal, however, a city ~~elected not to renew the franchise agreement, it~~ could seek alternative means ~~for its citizens~~ to access electric power or gas, such as municipalization.

While facing these challenges, SPS believes its rates and services are competitive with alternatives currently ~~available alternatives.~~available.

ENVIRONMENTAL MATTERS

SPS’ facilities are regulated by federal and state environmental ~~agencies. These~~ agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. SPS has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. SPS’ facilities have been designed and constructed to operate in compliance with applicable environmental ~~standards.~~standards and related monitoring and reporting requirements. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or what effect future laws or regulations may have upon SPS’ operations. ~~See Notes 10~~SPS may be required to incur capital expenditures in the future to comply with requirements for remediation of MGP and ~~11 to~~other legacy sites. The scope and timing of these expenditures cannot be determined until more information is obtained regarding the ~~financial statements~~need for ~~further discussion.~~remediation at legacy sites.

SPS must comply with emissions budgets that require the purchase of emission allowances from other utilities.

There are significant present and future environmental regulations to encourage ~~the~~ use of clean energy technologies and regulate emissions of ~~GHGs to address climate change.~~GHGs. SPS has undertaken ~~a number of~~numerous 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~~SPS has already made ~~to reduce GHG emissions,~~ or if they require additional initiatives or emission reductions, ~~then their requirements~~substantial costs may be incurred. The EPA, as an alternative to the CPP, has proposed a new regulation that, if adopted, would ~~potentially impose additional substantial costs.~~ require implementation of heat rate improvement projects at our coal-fired power plants. It is not known what those costs might be until a final rule is adopted and state plans are developed to implement a final regulation.

SPS believes, based on prior state commission practice, ~~it would recover~~ the cost of these initiatives or replacement generation would be recoverable through rates.

SPS is committed to addressing climate change and potential climate change regulation through efforts to reduce its GHG emissions in a balanced, cost-effective manner. Starting in 2011, SPS began reporting GHG emissions under the EPA’s mandatory GHG Reporting Program.

EMPLOYEES

As of Dec. 31, ~~2017,~~2018, SPS had ~~1,169~~1,151 full-time employees and ~~one~~no part-time ~~employee,~~employees, of which ~~791~~775 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~~Risks that may adversely affect the business, financial condition, ~~and~~ results of operations or cash flows are ~~further~~ described below. These risks should be carefully considered together with the other information set forth in this report and in future reports that Xcel Energy files with the SEC.

Oversight of Risk and Related Processes

A key accountability of 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~~procedures 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~~assume inappropriate risk to meet goals, and determines how to prevent inappropriate risk-taking.

At a threshold level, SPS has ~~developed~~ a robust compliance program and promotes a culture of compliance, including tone at the ~~top, which mitigates risk.~~top. 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.~~

legal.

Management communicates regularly with the Board of Directors and key stakeholders regarding risk. Senior management presents and communicates a periodic risk assessment ~~of key risks~~ to the Board of Directors. The presentation and the discussion of the key risks provides ~~the Board of Directors with~~ information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability. ~~Management also provides information to~~Oversight of cybersecurity risks by the ~~Board~~Operations, Nuclear, Environmental and Safety Committee includes receiving independent outside assessments of ~~Directors in presentations~~cybersecurity maturity and ~~communications over the course~~assessment of ~~the year.~~

plans.

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~~, CO~~₂and other GHGs, particulates, cooling water intakes, water discharges and ash management. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.

~~We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.~~

~~Climate change can create physical and financial risk. Physical risks from climate change can include changes in weather conditions, changes in precipitation and extreme weather events.~~

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

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

Climate change may impact a region’s economic health, which could impact our revenues. Our financial performance is tied to the health of the regional economies we serve. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHGor additional environmental regulation could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.

~~Financial Risks~~

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

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

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

Adverse regulatory rulings or the imposition of additional regulations could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including debt payments.

~~Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.~~

We cannot be assured that any of our current ratings will remain in effect for any given period of time, or that a rating will not be lowered or withdrawn entirely by a rating agency. Significant events including a major disallowance of costs, significantly lower returns on equity or equity ratios or impacts of tax policy changes, among others, may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies. Any downgrade could lead to higher borrowing costs and could impact our ability to access capital markets. Also, we may enter into certain procurement and derivative contracts that require the posting of collateral or settlement of applicable contracts if credit ratings fall below investment grade.

~~We are subject to capital market and interest rate risks.~~

Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital markets are global in nature and are impacted by numerous issues and events throughout the world economy. Capital market disruption events, and resulting broad financial market distress could prevent us from issuing short term commercial paper, issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates.

Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. Changes in interest rates may also impact the fair value of the debt securities in the master pension trust, as well as our ability to earn a return on short-term investments of excess cash.

~~We are subject to credit risks.~~

Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and local economies in the geographic areas we serve, including local unemployment rates.

Credit risk also includes the risk that various counterparties that owe us money or product will become insolvent and/or breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we could incur losses.

We may at times have direct credit exposure in our short-term wholesale and commodity trading activity to various financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, such as SPP, MISO and ERCOT, in which any credit losses are socialized to all market participants.

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

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

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

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

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

~~Federal tax law may significantly impact our business.~~

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

Operational Risks

Our ~~natural gas and~~ electric transmission and distribution and gas operations involve numerous risks that may result in accidents and other operating risks and costs.

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

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

operations and cash flows.

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.

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,~~efficiency, 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~~

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 CO~~₂ ~~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~~Decreasing use per customer driven by appliance and lighting efficiency and the availability of cost-effective distributed generation ~~puts~~places downward pressure on ~~load~~sales growth. This ~~could~~may 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.

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 could impact our cash flows. Low fuel costs have a positive impact on sales, however low oil and natural gas prices could negatively impact oil and gas production activities and subsequently our sales volumes and revenue.

A significant disruption in supply could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Significantly higher energy or fuel costs relative to sales commitments 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 could cause disruptions in our ability to provide electric services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process.

We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, ~~in which we operate,~~ emission allowances and/or ~~renewable energy credits~~RECs are also needed to comply with various statutes and commission ~~rulings associated with energy transactions.~~rulings. As a result we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily ~~basis (mark-to-market accounting).~~basis. 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.

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,~~2018, Xcel Energy Inc. and its utility subsidiaries had approximately ~~$14.5~~$15.8 billion of long-term debt and ~~$1.3~~$1.4 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,~~2018, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately ~~$19~~$17.8 million and immaterial exposure. Xcel Energy also had additional guarantees of ~~$53~~$51 million at Dec. 31, ~~2017~~2018 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 2018, 2017 ~~2016~~ and ~~2015~~2016 we paid ~~$109~~$131.0 million, ~~$85~~$108.8 million and ~~$101~~$85.1 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~~Note 5 to the financial statements for further ~~discussion~~information.

Financial Risks

Our profitability depends on ~~dividend limitations.~~

~~Public Policy Risks~~

our ability to recover costs from our customers and changes in regulation may impair our ability to recover costs from our customers.

We ~~may be~~are subject to ~~legislative~~comprehensive regulation by federal and state utility regulatory ~~responses to climate change, with which compliance could be difficult~~agencies, including siting and ~~costly.~~construction of facilities, customer service and the rates that we can charge customers.

~~Increased public awareness and concern regarding climate change may result in more state, regional and/or federal requirements to reduce or mitigate the effects~~The profitability 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~~operations is dependent on ~~our system. International agreements could have an impact to the extent they lead to future federal or state regulations.~~

~~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~~^oCelsius. 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 of providing energy and utility services and earn a return on our capital investment. Our rates are generally regulated and based on an analysis of our costs incurred ~~to comply with any regulatory requirements~~ in a ~~timely manner. If~~test year. We are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates we are allowed to charge may or may not match our costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital. In a continued low interest rate environment there has been pressure pushing down ROE. There can also be no assurance that our regulatory commissions will judge all of our costs to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery.

Changes in the long-term cost-effectiveness or changes to the operating conditions of our assets may result in early retirements of utility facilities and while regulation typically provides relief for these types of changes, there is no assurance that regulators ~~do not~~would allow ~~us to recover~~full recovery of all remaining costs leaving all or a ~~part~~portion of these asset costs stranded. Higher than expected inflation or tariffs 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 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 materially affect our ability to meet our financial obligations, including debt payments.

Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.

We cannot be assured that our current ratings will remain in effect, or that a rating will not be lowered or withdrawn by a rating agency. Significant events including a disallowance of costs, significantly lower returns on equity or equity ratios or impacts of tax policy changes may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies. Any downgrade could lead to higher borrowing costs and could impact our ability to access capital markets. Also, we may enter into contracts that require the posting of collateral or settlement of applicable contracts if credit ratings fall below investment ~~or the O&M costs incurred~~grade.

We are subject to ~~comply with the mandates, it~~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 and impacted by issues and events throughout the world. Capital market disruption events, and financial market distress could prevent us from issuing short-term commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates.

Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. Changes in interest rates may also impact the fair value of the debt securities in the pension funds, as well as our ability to earn a return on short-term investments of excess cash.

We are subject to credit risks.

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 fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results ~~of operations.~~could be adversely affected and incur losses.

~~Increased risks~~

We may at times have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of ~~regulatory penalties~~other counterparties. We may also have some indirect credit exposure due to participation in organized markets, such as SPP, PJM Interconnection, LLC, Midcontinent Independent System Operator, Inc. and Electric Reliability Council of Texas, in which any credit losses are socialized to all market participants.

We have additional indirect credit exposures to financial institutions in the form of letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could ~~negatively~~be in default under the contract.

Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.

We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. Estimates and assumptions may change. In addition, the Pension Protection Act changed the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and related contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year due to high retirements or employees leaving SPS could trigger settlement accounting and could require SPS to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid.

Increasing costs associated with health care plans may adversely affect our results of operations, financial conditions or cash flows.

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 condition and cash flows. Changes in industry standards utilized 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.

~~The Energy Act increased civil penalty authority~~SPS collects through regulated rates estimated federal, state and local tax payments. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Changes to tax depreciable lives and the value of various tax credits may change the economics of resources and our resource selections. There could be timing delays before regulated rates provide for ~~violation~~realization 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.~~tax changes in revenues. In addition, ~~NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject~~certain IRS tax policies such as the requirement 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 eventutilize normalization may impact our ability to economically deliver certain types of ~~serious incidents, these agencies have become more active in pursuing penalties. Some states have the authority~~resources relative 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.~~

market prices.

Macroeconomic Risks

Economic conditions impact our business.

Our operations are affected by local, national and worldwide economic conditions. Growth in ~~our customer base is~~customers and sales are 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~~additional bad ~~debt.~~debt expense.

Further, worldwide economic activity ~~has an impact on~~impacts the demand for basic commodities ~~needed~~necessary 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~~cost of ~~the~~ materials we use. We ~~may~~could be at risk for higher ~~than anticipated inflation both with respect to our own workforce, as well as our~~costs for materials and ~~labor that we contract for with others.~~our workforce. There may be delays before these ~~higher~~additional costs can be recovered in rates.

Our operations could be impacted by war, acts of terrorism, and 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.~~operations or cash flows. The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have already incurred increased costs for security and capital expenditures in response to these risks. 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~~facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility or an event ~~(such as~~(e.g., 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~~a disruption of work ~~force such as may be caused by flu or other epidemic)~~force) 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 results of operations, 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.

or cash flows.

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~~(e.g., information ~~about~~regarding 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~~causing the release of customer information, all of which could expose us to liability.

Our generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third party service providers’ operations, could also negatively impact our business.

Our supply chain for procurement of digital equipment may expose software or hardware to these risks and could result in a breach or significant costs of remediation. In addition, such an event would likely receive ~~regulatory scrutiny at both the~~ federal and state ~~level.~~regulatory scrutiny. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. These potential cyber security incidents and ~~corresponding~~ regulatory action could result in a material decrease in revenues and may causesignificant additional costs (e.g., penalties, third party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.

We maintain security measures ~~designed~~ to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including the resulting disability, or failures of assets or unauthorized access to assets or information. If our technology systems ~~were to fail or be breached,~~ or those of our third-party service providers were to fail or be breached, we may be unable to fulfill critical business ~~functions, including effectively maintaining certain internal controls over financial reporting.~~functions. 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.

Public Policy Risks

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

Legislative and regulatory responses related to climate change and new interpretations of existing laws create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. Such regulations could impose substantial costs on our system.

We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and 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, financial condition or cash flows if such costs are not recovered through regulated rates.

Although the United States has not adopted any international or federal GHG emission reduction targets, many states and localities may continue to pursue climate policies in the absence of federal mandates. 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 or international standards being discussed, the lack of federal action does not adversely impact these state-endorsed actions and plans.

If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.

Increased risks of regulatory penalties could negatively impact our business.

The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. The FERC can impose penalties of up to $1.3 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Additionally, the PHMSA, Occupational Safety and Health Administration and other federal agencies 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. If a serious reliability or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows.

Environmental Risks

We are subject to environmental laws and regulations, with which compliance could be difficult and costly.

We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements. Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Environmental regulations may also lead to shutdown of existing facilities. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate (i.e., clean-up) sites where our past activities, or the activities of other parties, caused environmental contamination.

We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or the O&M costs incurred to comply with the requirements.

In addition, existing environmental laws or regulations may be revised, and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.

We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.

Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events.

Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues. Extreme weather conditions in general require system backup, costs and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers.

Severe weather impacts our service territories, primarily when thunderstorms, 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. Periods of extreme temperatures could impact our ability to meet demand. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations. Drought conditions also contribute to the increase in wildfire risk from our electric generation facilities. While we carry liability insurance, given an extreme event, if SPS was found to be liable for wildfire damages, amounts that potentially exceed our coverage could negatively impact our results of operations, financial condition or cash flows. Drought or water depletion could adversely impact our ability to provide electricity to customers and increase the price paid for energy. We may not recover all costs related to mitigating these physical and financial risks.

Climate change may impact a region’s economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.

Item 1B — Unresolved Staff Comments

None.

~~None.~~

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



SPS Station, Location and Unit	Fuel	Installed	MW ^(a)
Steam:
Cunningham-Hobbs, NM, 2 Units	Natural Gas	1957 - 1965	251
Harrington-Amarillo, TX, 3 Units	Coal	1976 - 1980	1,018
Jones-Lubbock, TX, 2 Units	Natural Gas	1971 - 1974	486
Maddox-Hobbs, NM, 1 Unit	Natural Gas	1967	112
Nichols-Amarillo, TX, 3 Units	Natural Gas	1960 - 1968	457
Plant X-Earth, TX, 4 Units	Natural Gas	1952 - 1964	411
Tolk-Muleshoe, TX, 2 Units	Coal	1982 - 1985	1,067
Combustion Turbine:
Cunningham-Hobbs, NM, 2 Units	Natural Gas	1998	209
Jones-Lubbock, TX, 2 Units	Natural Gas	2011 - 2013	334
Maddox-Hobbs, NM, 1 Unit	Natural Gas	1963 - 1976	61
		Total	4,406


^(a)~~Carlsbad Unit 5 was retired on Dec. 31, 2017.~~	Summer 2018 net dependable capacity.

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, ~~2017:~~2018:



Conductor Miles
345 KV	~~8,516~~9,028
230 KV	~~9,608~~9,675
115 KV	~~13,555~~14,493
Less than 115 KV	~~24,795~~25,820

SPS had ~~454~~459 electric utility transmission and distribution substations at Dec. 31, ~~2017.~~2018.

Natural gas utility mains at Dec. 31, 2018:



Miles
Transmission	20
Distribution	—

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

~~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, Item 1 and Item 7 for ~~a discussion of proceedings involving utility rates and other regulatory matters.~~

further information.

Item 4 — Mine Safety Disclosures

None.

~~None.~~

PART II

Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

SPS is a wholly owned subsidiary of Xcel Energy Inc. and there is no market for its common equity securities. ~~SPS has dividend restrictions imposed by FERC rules and state regulatory commissions:~~

Dividends are subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only.

The most restrictive dividend limitation for SPS is imposed by its state regulatory commissions. SPS’ state regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy Inc. by requiring an equity-to-total capitalization ratio (excluding short-term debt) between 45.0 percent and 55.0 percent. In addition, SPS may not pay a dividend that would cause it to lose its investment grade bond rating. SPS’ equity-to-total capitalization ratio (excluding short-term debt) was 53.8 percent at Dec. 31, 2017 and $542 million in retained earnings was not restricted.

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

information.

The dividends declared during ~~2017~~2018 and ~~2016~~2017 were as follows:


(Thousands of Dollars)	2017		2016
(Millions of Dollars)					2018		2017
First quarter	$	26,715	$	25,645	$	33.4	$	26.7
Second quarter	25,014		19,388		30.7		25.0
Third quarter	26,166		27,498		40.1		26.2
Fourth quarter	26,753		30,870		45.2		26.8

Item 6 — Selected Financial Data

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

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

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

Non-GAAP Financial ~~Review~~

Measures

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

~~Forward-Looking Statements~~

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including the TCJA’s impact to SPS and its customers,GAAP, as well as ~~assumptions~~certain non-GAAP financial measures such as, electric margin and ~~other statements identified~~ongoing earnings. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from measures calculated and presented in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would”accordance with GAAP. SPS’ management uses non-GAAP measures for financial planning and ~~similar expressions. Actual results may vary materially. Forward-looking statements speak only as~~analysis, for reporting 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~~the Board of Directors, in determining performance-based compensation, and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.

Electric Margins

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

Earnings Adjusted for Certain Items (Ongoing Earnings)

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

Management believes these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of SPS.

Results of Operations

SPS’ net income was approximately ~~$159~~$213.3 million for ~~2017,~~2018, compared with net income of approximately ~~$152~~$159.2 million for ~~2016. Rate increases~~2017. The increase was primarily due to higher electric margins reflecting favorable weather and sales growth and a rate increase in New Mexico, AFUDC related to the Hale County wind project and a lower ~~ETR~~interest charges. Increases were partially offset by higher depreciation ~~expense and O&M expenses.~~

expense.

Electric ~~Revenues and Margins~~

Margin

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Changes in fuel or purchased power costs can impact earnings as the fuel and purchased power cost recovery mechanisms of the Texas and New Mexico jurisdictions may not allow for complete recovery of all expenses. ~~The following tables details the electric~~Electric revenues and ~~margin:~~margin before and after the impact of the TCJA:


(Millions of Dollars)	2017			2016			2018			2017
Electric revenues	$	1,918		$	1,851
Electric fuel and purchased power	(1,055		)	(1,035		)
Electric revenues before TCJA impact							$	1,988.1		$	1,918.0
Electric fuel and purchased power before TCJA impact							(1,050.1		)	(1,055.3		)
Electric margin before TCJA impact							$	938.0		$	862.7
TCJA impact (offset as a reduction in income tax)							(48.3		)	—
Electric margin	$	863		$	816		$	889.7		$	862.7

The following tables summarize the components of the changes in electric ~~revenues and electric~~ margin for the year ended Dec. ~~31:~~31, 2018:

Electric ~~Revenues~~

Margin

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

~~Electric Margin~~


(Millions of Dollars)	2017 vs. 2016			2018 vs. 2017
Retail rate increases (Texas and New Mexico)	$	62
Wholesale transmission revenue (net of costs)				$	21.6
Estimated impact of weather				19.9
Non-fuel riders				12.7
Demand revenue	12			8.7
Renewable energy credits	7
Sales growth				8.3
Retail rate increase (New Mexico)				3.1
Firm wholesale	(20		)	(10.8		)
Estimated impact of weather	(7		)
Fuel handling and procurement	(5		)
Wholesale transmission revenue, net of costs	(3		)
Other, net	1
Other (net)				11.8
Total increase in electric margin before TCJA impact				$	75.3
TCJA impact (offset as a reduction in income tax)				(48.3		)
Total increase in electric margin	$	47		$	27.0

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~~$15.7 million, or ~~19.4 percent,~~8.1%, 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.~~2018. The increase was primarily due to ~~higher property taxes in Texas.~~increased capital investments.

AFUDC, Equity and Debt— AFUDC increased by $13.3 million for 2018. The increase was primarily due to the Hale County Wind Project.

Income Taxes — Income tax expense decreased ~~$14~~$29.5 million for ~~2017~~2018 compared with ~~2016.~~the same period in 2017. The decrease in income tax expense was primarily due to ~~the estimated one-time, non-cash, income~~a lower federal tax ~~benefit recognized in the fourth quarter related~~rate due to the TCJA, ~~(see Note 6)~~an increase in plant-related regulatory difference related to ARAM (net of deferrals), and 2018 non-plant excess accumulated deferred income tax amortization.

This was partially offset by higher pretax earnings, a net tax benefit related to the resolution of appeals/audits in 2017, and the estimated one-time, non-cash, income tax expense related to the impacts of tax reform in 2017. The ETR was ~~30.1 percent~~15.4% for ~~2017,~~2018 compared with ~~35.1 percent~~30.1% for ~~2016.~~2017. The lower ETR in ~~2017~~2018 was primarily due to the adjustments referenced above.

Regulation

FERC and State Regulation — The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, asset transactions and mergers, accounting practices and certain other activities of SPS, including enforcement of NERC mandatory electric reliability standards. State and local agencies have jurisdiction over many of SPS’ activities, including regulation of retail rates and environmental matters.

Xcel Energy, which includes SPS, attempts to mitigate the risk of regulatory penalties through formal training on prohibited practices and a compliance function that reviews interaction with the markets under FERC and Commodity Futures Trading Commission jurisdictions. 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. Decisions by these regulators can significantly impact SPS’ results of operations.

Tax Reform — Regulatory Proceedings

In December 2017, the TCJA was signed into law, enacting significant changes to the Internal Revenue Code, including a reduction of the corporate income tax rate from 35% to 21% and a resulting reduction in deferred tax assets and liabilities. As a result of IRS requirements and past regulatory treatment of income taxes in the determination of regulated rates, the impacts of TCJA are primarily recognized as a regulatory liability. Treatment of these tax benefits, (e.g., degree to which benefits will be used to refund currently effective rates and/or used to mitigate other costs and potential future rate increases) is subject to regulatory approval. Concluded and ongoing regulatory TCJA proceedings:



Utility Service	Approval Date	Additional Information
Electric	December 2018	Texas— In December 2018, the PUCT approved a rate settlement which fully reflects the TCJA cost impacts and results in no change in customer rates or refunds and SPS’ actual capital structure, which SPS has informed the parties it intends to be up to a 57% equity ratio to offset the negative impacts on its credit metrics and potentially its credit ratings.
Electric	TBD	New Mexico— In September 2018, the NMPRC issued its final order in SPS’ 2017 electric rate case, which included a $10 million refund of the 2018 impact of the TCJA. SPS subsequently filed an appeal with the NMSC, including the order to refund retroactive TCJA savings. The NMSC granted a temporary stay to delay the implementation of the retroactive TCJA refund until a decision on the appeal occurs. On Feb. 15, 2019, SPS and the NMPRC filed a Joint Motion to Dismiss with the NMSC, requesting they remand the case back to the NMPRC to provide them the opportunity to revise its rate case order in accordance with the motion. This would require the NMPRC to replace the order issued in September 2018 and eliminate the retroactive TCJA refund. The revised NMPRC order would be subject to further administrative or judicial review.

See Note 7 to the financial statements for further information.

Pending and Recently Concluded Regulatory Proceedings



Mechanism	Utility Service	Amount Requested (in millions)	Filing Date	Approval	Additional Information
SPS (PUCT)
Rate Case	Electric	$54	August 2017	Received	In 2017, SPS filed a retail electric, non-fuel base rate increase case in Texas, which included an ROE of 9.5%. In December 2018, PUCT issued a final order approving a settlement, which results in no overall change to SPS’ revenues after adjusting for the impact of the TCJA and the lower costs of long-term debt. In November 2018, SPS filed an application with PUCT requesting permission to recover $5.4 million in unbilled TCRF revenue from January 23, 2018 through June 9, 2018. Timing of a final order on this matter is uncertain.
SPS (NMPRC)
Rate Case	Electric	$41	November 2016	Pending	In 2017, SPS filed a notice of appeal to the New Mexico Supreme Court. A decision is not expected until the second half of 2019.
Rate Case	Electric	$43	October 2017	Received/Pending	In September 2018, the NMPRC approved a revenue increase of approximately $8 million, effective Sept. 27, 2018, based on a ROE of 9.1% and a 51% equity ratio. The NMPRC also ordered a refund of $10 million associated with the TCJA impacts (retroactive Jan. 1, 2018 - Sept. 27, 2018). SPS recorded a regulatory liability for this amount in the third quarter of 2018. SPS subsequently filed an appeal of the order. The NMSC subsequently granted a temporary stay to delay the implementation of the retroactive TCJA refund until a decision on the appeal occurs. On Feb. 15, 2019, SPS and the NMPRC filed a Joint Motion to Dismiss with the NMSC, requesting they remand the case back to the NMPRC to provide them the opportunity to revise its rate case order in accordance with the motion. This would require the NMPRC to replace the order issued in September 2018 with the following: eliminating the retroactive refund associated with the TCJA, approving a ROE of 9.56% and approving an equity ratio of 53.97%. Annual revenue increase based on terms of the settlement agreement would be $12.5 million ($8 million from original order plus $4.5 million for changes in ROE and equity ratio). New rates would be effective as of the date provided by the revised NMPRC order (not retrospective to Sept. 26, 2018), which is expected in the second quarter of 2019. The revised NMPRC order would be subject to further administrative or judicial review.

See Rate Matters within Note 10 to the financial statements for further information.

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

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

See Note 98 to the financial statements for further ~~discussion of market risks associated with derivatives.~~

information.

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

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

investments.

Commodity Price Risk — SPS is exposed to commodity price risk in its electric operations. Commodity price risk is managed by entering into ~~short-~~long- and ~~long-term~~short-term physical purchase and sales contracts for electric capacity, energy and energy-related products. Commodity price risk is also managed through the use of financial derivative instruments.

SPS’ risk management policy allows it to manage commodity price risk ~~within each rate-regulated operation~~ per commission approved hedge plans.

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

Interest Rate Risk — SPS is subject to ~~the risk of fluctuating~~ interest ~~rates in the normal course of business.~~rate risk. SPS’ risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.

~~At Dec. 31, 2017, 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~~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.~~ $0.4 million in 2018 and no impact in 2017.

See Note 98 to the financial statements for ~~a discussion of SPS’ interest rate derivatives.~~

further information.

Credit Risk — SPS is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. SPS maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.

At Dec. 31, 2018, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $1.5 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $1.5 million. At Dec. 31, 2017, a ~~10 percent~~10% 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~~10% 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~~counterparties and employ credit risk ~~control mechanisms when appropriate,~~controls, such as letters of credit, parental guarantees, ~~standardized~~ master netting agreements and termination ~~provisions that allow for offsetting of positive and negative exposures.~~provisions. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase SPS’ credit risk.

Fair Value Measurements

SPS ~~follows accounting~~uses derivative contracts such as futures, forwards, interest rate swaps, options and ~~disclosure guidance on~~FTRs to manage commodity price and interest rate risk. Derivative contracts, with the exception of those designated as normal purchase-normal sale contracts, are reported at fair value. SPS’ investments held in rabbi trusts, pension and other postretirement funds are also subject to fair value measurements that contains a hierarchy for inputs used in measuring fair value and requires disclosure of the observability of the inputs used in these measurements. See Note 9 to the financial statements for further discussion of the fair value hierarchy and the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.

accounting.

Commodity Derivatives — SPS continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the ~~transactions set forth in the contracts.~~transactions. Given ~~this assessment and~~ the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, ~~2017. SPS also assesses the impact of its own~~2018.

Adjustments to fair value for credit risk ~~when determining the fair value~~ of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are recorded as other comprehensive income or deferred as regulatory assets and liabilities. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. The impact of discounting commodity derivative liabilities for credit risk was immaterial ~~to the fair value of commodity derivative liabilities~~ at Dec. 31, ~~2017.~~

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

2018.

Item 8 — Financial Statements and Supplementary Data

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

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

Management Report on Internal Controls Over Financial Reporting

The management of SPS is responsible for establishing and maintaining adequate internal control over financial reporting. SPS’ internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s and SPS’ management and board of directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

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

SPS management assessed the effectiveness of SPS’ internal control over financial reporting as of Dec. 31, ~~2017.~~2018. 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,~~2018, 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~~22, 2019		Feb. ~~23, 2018~~22, 2019

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~~2018 and ~~2016,~~2017, the related statements of income, comprehensive income, cash flows and, common ~~stockholder’s~~stockholder's equity for each of the three years in the period ended December 31, ~~2017,~~2018, 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~~2018 and ~~2016,~~2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2017,~~2018, 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~~22, 2019

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

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF INCOME

(amounts in ~~thousands of dollars)~~millions)


	Year Ended Dec. 31									Year Ended Dec. 31
	2017			2016			2015			2018			2017			2016

Operating revenues	$	1,918,000		$	1,850,959		$	1,787,218		$	1,933.2		$	1,918.0		$	1,851.0

Operating expenses
Electric fuel and purchased power	1,055,333			1,034,950			1,001,083			1,043.5			1,055.3			1,035.0
Operating and maintenance expenses	289,555			269,471			289,856			282.7			285.4			265.5
Demand side management program expenses	15,525			16,028			13,365			17.7			15.5			16.0
Depreciation and amortization	193,915			162,429			150,913			209.6			193.9			162.4
Taxes (other than income taxes)	66,863			60,800			57,536			68.0			67.0			60.8
Total operating expenses	1,621,191			1,543,678			1,512,753			1,621.5			1,617.1			1,539.7

Operating income	296,809			307,281			274,465			311.7			300.9			311.3

Other income (expense), net	2,359			91			(6		)
Other expense, net										(3.0		)	(1.8		)	(3.9		)
Allowance for funds used during construction — equity	9,310			9,981			7,378			19.1			9.3			10.0

Interest charges and financing costs
Interest charges — includes other financing costs of $2,491, $3,055 and $3,158, respectively	86,233			88,671			84,040
Interest charges — includes other financing costs of $2.9, $2.5 and $3.1, respectively										84.5			86.2			88.7
Allowance for funds used during construction — debt	(5,384		)	(5,589		)	(4,491		)	(8.9		)	(5.4		)	(5.6		)
Total interest charges and financing costs	80,849			83,082			79,549			75.6			80.8			83.1

Income before income taxes	227,629			234,271			202,288			252.2			227.6			234.3
Income taxes	68,416			82,114			75,025			38.9			68.4			82.1
Net income	$	159,213		$	152,157		$	127,263		$	213.3		$	159.2		$	152.2

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF COMPREHENSIVE INCOME

(amounts in ~~thousands of dollars)~~millions)


	Year Ended Dec. 31								Year Ended Dec. 31
	2017		2016			2015			2018		2017		2016
Net income	$	159,213	$	152,157		$	127,263		$	213.3	$	159.2	$	152.2

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		)
Amortization of losses (gains) included in net periodic benefit cost (net of tax of $0, $0, and $(0.1), respectively)									—		0.1		(0.1		)

Derivative instruments:
Reclassification of losses to net income, net of tax of $24, $80, and $97, respectively	39		139			172
Reclassification of losses to net income (net of tax of $0, $0.1, and $0.1, respectively)									0.1		—		0.1

Other comprehensive income (loss)	83		(9		)	(292		)
Other comprehensive income									0.1		0.1		—
Comprehensive income	$	159,296	$	152,148		$	126,971		$	213.4	$	159.3	$	152.2

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF CASH FLOWS

(amounts in ~~thousands of dollars)~~millions)


	Year Ended Dec. 31									Year Ended Dec. 31
	2017			2016			2015			2018			2017			2016
Operating activities
Net income	$	159,213		$	152,157		$	127,263		$	213.3		$	159.2		$	152.2
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	193,870			162,957			153,241			210.0			193.9			163.0
Demand side management program amortization	1,673			1,673			1,673			1.7			1.7			—
Deferred income taxes	126,465			122,983			62,836			22.1			126.5			123.0
Amortization of investment tax credits	(133		)	(213		)	(213		)
Allowance for equity funds used during construction	(9,310		)	(9,981		)	(7,378		)	(19.1		)	(9.3		)	(10.0		)
Provision for bad debts	5,091			6,066			4,655			4.9			5.1			6.1
Net derivative losses	63			217			268			0.1			0.1			0.2
Other	(28		)	122			(3,827		)
Changes in operating assets and liabilities:
Accounts receivable	(10,392		)	(8,868		)	(3,291		)	(19.5		)	(10.4		)	(8.9		)
Accrued unbilled revenues	(10,386		)	(15,637		)	25,506			15.3			(10.4		)	(15.6		)
Inventories	(1,928		)	(959		)	5,686			(16.0		)	(1.9		)	(1.0		)
Prepayments and other	4,267			22,651			(24,712		)	0.5			4.3			22.7
Accounts payable	11,836			13,776			(24,570		)	(6.6		)	11.8			13.8
Net regulatory assets and liabilities	38,137			(55,689		)	26,452			38.2			38.1			(55.7		)
Other current liabilities	3,427			5,156			(30,762		)	11.6			3.4			5.2
Pension and other employee benefit obligations	(21,679		)	(15,276		)	(9,405		)	(16.0		)	(21.7		)	(15.3		)
Change in other noncurrent assets	(1,206		)	(200		)	2,352
Change in other noncurrent liabilities	(18,524		)	6,748			8,974
Other, net										5.8			(19.9		)	8.1
Net cash provided by operating activities	470,456			387,683			314,748			446.3			470.5			387.8

Investing activities
Utility capital/construction expenditures	(559,865		)	(512,522		)	(599,511		)	(1,020.9		)	(550.6		)	(502.5		)
Allowance for equity funds used during construction	9,310			9,981			7,378
Proceeds from insurance recoveries	—			3,901			—			—			—			3.9
Investments in utility money pool arrangement	(142,000		)	(75,000		)	(92,000		)	(285.0		)	(142.0		)	(75.0		)
Receipts from utility money pool arrangement	77,000			75,000			92,000			350.0			77.0			75.0
Other	(493		)	(1,174		)	3,136			—			(0.5		)	(1.3		)
Net cash used in investing activities	(616,048		)	(499,814		)	(588,997		)	(955.9		)	(616.1		)	(499.9		)

Financing activities
(Repayment of) proceeds from short-term borrowings, net	(50,000		)	35,000			(22,000		)
Proceeds from (repayments of) short-term borrowings, net										42.0			(50.0		)	35.0
Proceeds from issuance of long-term debt	442,338			295,985			198,496			295.0			442.3			296.0
Repayment of long-term debt, including reacquisition premiums	(271,613		)	(200,000		)	—			—			(271.6		)	(200.0		)
Borrowings under utility money pool arrangement	335,000			636,500			579,700			595.0			335.0			636.5
Repayments under utility money pool arrangement	(335,000		)	(636,500		)	(595,700		)	(595.0		)	(335.0		)	(636.5		)
Capital contributions from parent	143,659			66,225			214,535			336.8			143.7			66.2
Dividends paid to parent	(108,765		)	(85,069		)	(100,544		)	(131.0		)	(108.8		)	(85.1		)
Net cash provided by financing activities	155,619			112,141			274,487			542.8			155.6			112.1

Net change in cash and cash equivalents	10,027			10			238			33.2			10.0			—
Cash and cash equivalents at beginning of year	844			834			596			10.8			0.8			0.8
Cash and cash equivalents at end of year	$	10,871		$	844		$	834		$	44.0		$	10.8		$	0.8

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(75,978	)	$	(78,236	)	$	(76,474	)	$	(71.2	)	$	(76.0	)	$	(78.2	)
Cash received (paid) for income taxes, net	41,548			61,813			(23,987		)
Cash (paid) received for income taxes, net										(10.6		)	41.5			61.8
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	77,563		$	43,074		$	44,335		$	71.5		$	85.1		$	49.5
Inventory transfer additions in PPE										22.5			13.7			22.6
Allowance for equity funds used during construction										19.1			9.3			10.0

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.

BALANCE SHEETS

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


	Dec. 31						Dec. 31
	2017			2016			2018			2017
Assets
Current assets
Cash and cash equivalents	$	10,871		$	844		$	44.0		$	10.8
Accounts receivable, net	79,581			74,190			90.7			79.6
Accounts receivable from affiliates	1,297			949			10.5			1.3
Investments in money pool arrangements	65,000			—			—			65.0
Accrued unbilled revenues	129,804			119,418			114.5			129.8
Inventories	40,433			38,505			33.9			40.4
Regulatory assets	31,538			38,721			26.0			31.5
Derivative instruments	15,882			5,114			17.8			15.9
Prepaid taxes	15,025			21,779			14.2			15.0
Prepayments and other	10,341			7,855			10.7			10.4
Total current assets	399,772			307,375			362.3			399.7

Property, plant and equipment, net	5,095,609			4,695,819			5,946.4			5,095.6

Other assets
Regulatory assets	362,943			346,683			366.2			362.9
Derivative instruments	18,954			22,113			15.8			19.0
Other	11,266			7,477			5.1			11.3
Total other assets	393,163			376,273			387.1			393.2
Total assets	$	5,888,544		$	5,379,467		$	6,695.8		$	5,888.5

Liabilities and Equity
Current liabilities
Short-term debt	$	—		$	50,000		$	42.0		$	—
Accounts payable	211,756			176,157			191.8			211.8
Accounts payable to affiliates	22,577			14,414			19.9			22.6
Regulatory liabilities	68,835			41,577			85.8			68.8
Taxes accrued	35,243			39,742			41.6			35.2
Accrued interest	23,275			19,162			25.8			23.3
Dividends payable	26,753			30,870			45.2			26.8
Derivative instruments	3,565			3,565			3.6			3.6
Other	29,641			29,703			28.3			29.6
Total current liabilities	421,645			405,190			484.0			421.7

Deferred credits and other liabilities
Deferred income taxes	574,906			989,137			619.1			574.9
Regulatory liabilities	784,564			233,454			780.9			784.6
Asset retirement obligations	28,524			28,663			32.4			28.5
Derivative instruments	19,949			23,513			16.4			20.0
Pension and employee benefit obligations	90,266			107,872			92.4			90.3
Other	8,386			24,084			7.9			8.3
Total deferred credits and other liabilities	1,506,595			1,406,723			1,549.1			1,506.6

Commitments and contingencies
Capitalization
Long-term debt	1,829,941			1,635,858			2,126.1			1,829.9
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2017 and 2016, respectively	—			—
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2018 and 2017, respectively							—			—
Additional paid in capital	1,590,242			1,446,223			1,932.3			1,590.2
Retained earnings	541,588			486,763			605.7			541.6
Accumulated other comprehensive loss	(1,467		)	(1,290		)	(1.4		)	(1.5		)
Total common stockholder’s equity	2,130,363			1,931,696			2,536.6			2,130.3
Total liabilities and equity	$	5,888,544		$	5,379,467		$	6,695.8		$	5,888.5

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

(amounts in ~~thousands of dollars,~~millions, except share data)


	Common Stock Issued								Accumulated Other Comprehensive Income (Loss)				Total Common Stockholder’s Equity			Common Stock Issued											Accumulated Other Comprehensive Income (Loss)			Total Common Stockholder’s Equity
	Shares	Par Value		Additional Paid In Capital		Retained Earnings						Shares					Par Value			Additional Paid In Capital			Retained Earnings
Balance at Dec. 31, 2014	100	$	—	$	1,165,463	$	395,998			$	(989	)			$	1,560,472
Balance at Dec. 31, 2015																100		$	—		$	1,371.2		$	438.0		$	(1.3	)	$	1,807.9

Net income																								152.2						152.2
Common dividends declared to parent																								(103.5		)				(103.5		)
Contribution of capital by parent																					75.0									75.0
Balance at Dec. 31, 2016																100		$	—		$	1,446.2		$	486.7		$	(1.3	)	$	1,931.6

Net income						127,263							127,263											159.2						159.2
Other comprehensive loss									(292		)		(292		)												0.1			0.1
Common dividends declared to parent						(85,254		)					(85,254		)									(104.6		)				(104.6		)
Contribution of capital by parent				205,760									205,760								144.0									144.0
Balance at Dec. 31, 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
Adoption of ASU No. 2018-02																								0.3			(0.3		)	—
Balance at Dec. 31, 2017																100		$	—		$	1,590.2		$	541.6		$	(1.5	)	$	2,130.3

Net income						159,213							159,213											213.3						213.3
Other comprehensive income									83				83														0.1			0.1
Common dividends declared to parent						(104,648		)					(104,648		)									(149.2		)				(149.2		)
Contribution of capital by parent				144,019									144,019								342.1									342.1
Adoption of ASU No. 2018-02						260			(260		)		—
Balance at Dec. 31, 2017	100	$	—	$	1,590,242	$	541,588		$	(1,467	)		$	2,130,363
Balance at Dec. 31, 2018																100		$	—		$	1,932.3		$	605.7		$	(1.4	)	$	2,536.6

See Notes to Financial Statements

~~SOUTHWESTERN PUBLIC SERVICE CO.~~

~~STATEMENTS OF CAPITALIZATION~~

~~(amounts in thousands of dollars, except share data)~~

Dec. 31
2017 2016
Long-Term Debt
First Mortgage Bonds, Series due:
   June 15, 2024, 3.3% $ 350,000
$ 350,000
   Aug. 15, 2041, 4.5% 400,000
400,000
   Aug. 15, 2046, 3.4% 300,000
300,000
   Aug. 15, 2047, 3.7% 450,000
—
Unsecured Senior G Notes, due Dec. 1, 2018, 8.75% —
250,000
Unsecured Senior C and D Notes, due Oct. 1, 2033, 6% 100,000
100,000
Unsecured Senior F Notes, due Oct. 1, 2036, 6% 250,000
250,000
Unamortized (discount) premium (1,746 ) 365
Unamortized debt expense (18,313 ) (14,507 )
Total long-term debt $ 1,829,941
$ 1,635,858

Common Stockholder’s Equity
Common stock — 200 shares authorized of $1.00 par value,
100 shares outstanding at Dec. 31, 2017 and 2016, respectively
$ —
$ —
Additional paid in 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~~

NOTES TO FINANCIAL STATEMENTS


1.	Summary of Significant Accounting Policies

~~Business and System of Accounts~~General — 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.~~commissions.

~~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~~evaluated the impact of events occurring after Dec. 31, 2018 up to the date of issuance of these financial statements. These statements contain all necessary adjustments and ~~if SPS is the primary beneficiary. SPS follows accounting guidance for variable interest entities which requires consideration of the activities~~disclosures resulting from that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether SPS is a variable interest entity’s primary beneficiary. See Note 11 for further discussion of variable interest entities.

evaluation.

Use of Estimates — ~~In recording transactions and balances resulting from business operations,~~ SPS uses estimates based on the best information ~~available.~~available in recording transactions and balances resulting from business operations. Estimates are used ~~for~~on items such ~~items~~ as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. ~~The recorded~~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,~~other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and

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

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

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

See Note 124 for further ~~discussion~~information.

Income Taxes— SPS accounts for income taxes using the asset and liability method, which requires 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.

Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of regulatory assets and ~~liabilities.~~

~~Revenue Recognition— Revenues~~liabilities related to ~~the sale of energy~~income taxes.

Deferred tax assets are ~~generally recorded when service~~reduced by a valuation allowance if it is ~~rendered~~more likely than not that some portion or ~~energy is delivered to customers. However, the determination~~all of the ~~energy sales~~deferred tax asset will not be realized.

SPS follows the applicable accounting guidance to ~~individual customers~~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 ~~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~~technical merits of the ~~last meter reading~~position.

Recognition of changes in uncertain tax positions are ~~estimated and the corresponding unbilled revenue is recognized. SPS presents its revenues net~~reflected as a component of ~~any excise or other fiduciary-type taxes or fees.~~

income tax.

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

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

Certain rate rider mechanisms qualify as alternative revenue programs under generally accepted accounting principles. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, revenue is recognized equal to the revenue requirement, including return on rate base items, for the qualified mechanisms. The mechanisms are revised periodically for differences between the total amount collected under the riders and the revenue recognized, which may increase or decrease the level of revenue collected from customers.

~~Conservation Programs~~ — SPS has implemented programs in its jurisdictions to assist customers in conserving energy and reducing peak demand on the electric system. These programs include commercial motor, air conditioner and lighting upgrades,files consolidated federal income tax returns as well as ~~residential rebates~~consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for ~~participation~~state income taxes paid by Xcel Energy Inc. in ~~air conditioner interruption~~connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.

See Notes 4 and ~~home weatherization.~~

~~The costs incurred~~7 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.

further information.

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~~2.9% in 2018, 2.8% in 2017, and ~~2.6 percent for the years ended Dec. 31, 2017, 2016 and 2015, respectively.~~2.7% in 2016.

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

~~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.

information.

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

See Note 1110 for further ~~discussion of AROs.~~

information.

~~Income Taxes~~Benefit Plans and Other Postretirement Benefits— SPS ~~accounts~~maintains pension and postretirement benefit plans for ~~income taxes using~~eligible employees. Recognizing the ~~asset~~cost of providing benefits and ~~liability method, which~~measuring the projected benefit obligation of these plans requires ~~the recognition of deferred tax assets~~management to make various assumptions and ~~liabilities for the expected future tax consequences of events that have been included in the financial statements. SPS defers income taxes for all temporary differences between pretax financial~~estimates.

Certain unrecognized actuarial gains and ~~taxable income,~~losses and between the book and tax bases of assets and liabilities. SPS uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.

The effects of SPS’ tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability which will be refundable to utility customers over the remaining life of the related assets. A tax rate increase would result in the establishment of a similar regulatory asset. Taxunrecognized prior service costs or credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of certaindeferred as regulatory assets and liabilities, ~~related to~~rather than recorded as other comprehensive income, ~~taxes, which are summarized in Note 12.~~

Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations.

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

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

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

~~See Note 6 for further discussion of income taxes.~~

~~Types of and Accounting for Derivative Instruments~~— SPS uses derivative instruments in connection with its utility commodity price and interest rate activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the balance sheets at fair value as derivative instruments. This includes certain instruments used to mitigate market risk for the utility operations including transmission in organized markets. The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory ~~asset or liability. The classification as a regulatory asset or liability is based on expected recovery of derivative instrument settlements through fuel and purchased energy cost~~ recovery mechanisms.

Interest rate hedging transactions are recorded as a component of interest expense. For further information on derivatives entered to mitigate market risk associated with transmission in organized markets, see Note 9.

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

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

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

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

~~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 SO~~₂ 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.

information.

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

Estimated remediation ~~costs, 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~~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.~~expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 10 for further information.

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

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

SPS participates in SPP. SPS recognizes sales to both native load and other end use customers on a gross basis in electric revenues and cost of sales. Revenues and charges for short term wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other revenues and charges related to participating and transacting in RTOs are recorded on a net basis in cost of sales.

See Note 116 for further ~~discussion~~information.

Cash and Cash Equivalents— SPS considers investments in instruments with a remaining maturity of ~~environmental costs.~~

three months or less at the time of purchase, to be cash equivalents.

~~Benefit Plans~~Accounts Receivable and ~~Other Postretirement Benefits~~Allowance for Bad Debts— Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. SPS establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers. As of Dec. 31, 2018 and 2017, the allowance for bad debts was $5.6 million and $6.3 million, respectively.

Inventory— Inventory is recorded at average cost. As of Dec. 31, 2018, materials and supplies and fuel inventory were $25.7 million and $8.2 million, respectively. As of Dec. 31, 2017, materials and supplies and fuel inventory were $26.2 million and $14.2 million, respectively.

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

See Notes 8 and 9 for further information.

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

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

See Note 8 for further information.

Other Utility Items

AFUDC— AFUDC represents the cost of ~~providing benefits~~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 ~~measuring~~interest charges (for debt capital). AFUDC amounts capitalized are included in SPS’ rate base for establishing utility rates.

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

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 76 for further ~~discussion of benefit plans and other postretirement benefits.~~

information.

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

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

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

RECs — Cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. SPS reduces recoverable fuel costs for the ~~fair market value~~cost of RECs and records that cost as a regulatory asset when the ~~obligation that has been assumed~~amount is recoverable 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.~~future rates.

Sales of RECs are recorded in electric revenues on a gross basis. The ~~obligation recognized is reduced over the term~~cost of ~~the guarantee as SPS is released from risk~~these RECs and amounts credited to customers under ~~the guarantee. See Note 11 for specific details of issued guarantees.~~

margin-sharing mechanisms are recorded in electric fuel and purchased power expense.

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

Leases —In 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which requires balance sheet recognition of right-of-useassets and lease liabilities for most leases. Adoptionwill occur on Jan. 1, 2019 utilizing the package of transition practical expedients provided by the new standard, including carrying forward prior conclusions of whether agreements existing before the adoption date contain leases, and whether existing leases are operating or capital/finance leases. SPS expects to utilize other expedients offered by the new standard and Leases, Topic 842 (ASU No. 2018-11), including elections to not recognize short term leases on the balance sheet for certain classes of assets and to implement the standard on a prospective basis. SPS’ implementation of the new guidance is substantially complete, and is expected to result in the recognition of right-of-use assets and lease liabilities in the first quarter of 2019 for operating leases for the use of real estate, equipment and certain natural gas generating facilities operated under PPAs. The implementation isnot expected to have a significant impact on SPS’ financial statements, other than first-time recognition of these operating leases on the balance sheet.

Recently Adopted

Revenue Recognition— — In ~~May~~ 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 ~~(ASU~~(ASU No. 2014-09), which provides a new framework for the recognition of revenue. AsSPS implemented 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~~on Jan. 1, 2018. Results for reporting periods beginning after Dec. 31, 2017 are presented in accordance with Topic 606, while prior period results have not been adjusted and continue to be reported in accordance with prior accounting guidance. The implementation did not have a material impact on SPS’ financial statements, other than increased disclosures regarding revenues related to contracts with ~~customers effective Jan. 1, 2018.~~customers.

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~~eliminated the available-for-sale classification for marketable equity securities and also ~~replaces~~replaced the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. ~~Under~~SPS implemented 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~~on Jan. 1, 2018 and the adoption ~~will~~impacts were 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 — I~~n March~~In 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~~portion of pension cost may be presented as a component of operating ~~income in the income statement. Also under the guidance,~~income. In addition, only the service cost ~~component~~portion of pension cost is eligible for capitalization. As a result of ~~application of~~regulatory accounting ~~principles for rate regulated entities,~~treatment, 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~~are limited to changes in classification of non-service costs in the statement of income. ~~This~~

SPS implemented the new guidance ~~is effective~~on Jan. 1, 2018. As a result, $4.1 million and $4.0 million of pension costs were retrospectively reclassified from operating and maintenance expenses to other expense, net on the income statement for ~~interim~~2017 and ~~annual reporting~~2016, respectively. SPS used benefit cost amounts disclosed for prior periods ~~beginning after Dec. 15, 2017.~~as the basis for retrospective application.

~~Recently Adopted~~3. Property, Plant and Equipment

Major classes of property, plant and equipment:

~~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.



(Millions of Dollars)	Dec. 31, 2018			Dec. 31, 2017
Property, plant and equipment
Electric plant	$	7,227.7		$	6,765.3
CWIP	847.3			351.9
Total property, plant and equipment	8,075.0			7,117.2
Less accumulated depreciation	(2,128.6		)	(2,021.6		)
	$	5,946.4		$	5,095.6


3.4.	~~Selected Balance Sheet Data~~Regulatory Assets and Liabilities

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

(Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016
Accounts receivable, net
Accounts receivable $ 85,929
$ 80,569
Less allowance for bad debts (6,348 ) (6,379 )
$ 79,581
$ 74,190
Components of regulatory assets:

(Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016
Inventories
Materials and supplies $ 26,218
$ 25,453
Fuel 14,215
13,052
$ 40,433
$ 38,505

(Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016
Property, plant and equipment, net
Electric plant $ 6,765,371
$ 6,362,189
Construction work in progress 351,875
260,327
Total property, plant and equipment 7,117,246
6,622,516
Less accumulated depreciation (2,021,637 ) (1,926,697 )
$ 5,095,609
$ 4,695,819



(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2018				Dec. 31, 2017
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations	9	Various	$	12.6	$	222.1	$	12.7	$	223.0
Excess deferred taxes - TCJA	7	Various	—		55.9		—		44.7
Recoverable deferred taxes on AFUDC recorded in plant		Plant lives	—		27.9		—		23.9
Net AROs ^(a)	1, 10	Plant lives	—		25.7		—		24.2
Losses on reacquired debt		Term of related debt	0.8		21.9		0.8		22.7
Conservation programs ^(b)	1	One to two years	0.7		0.6		2.7		0.7
Other		Various	11.9		12.1		15.3		23.7
Total regulatory assets			$	26.0	$	366.2	$	31.5	$	362.9


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


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

Components of regulatory liabilities:



(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2018				Dec. 31, 2017
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Deferred income tax adjustments and TCJA refunds ^(a)	7	Various	$	2.2	$	569.8	$	—	$	568.6
Plant removal costs	1, 10	Plant lives	—		187.7		—		196.9
Revenue subject to refund		One to two years	11.3		8.1		6.8		6.5
Gain from asset sales		Various	—		2.4		—		2.5
Deferred electric energy costs		Less than one year	56.5		—		48.5		—
Contract valuation adjustments ^(b)	1, 8	Less than one year	14.7		—		12.7		—
Other		Various	1.1		12.9		0.8		10.1
Total regulatory liabilities			$	85.8	$	780.9	$	68.8	$	784.6


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


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

At Dec. 31, 2018 and 2017, approximately $48 million and $64 million, respectively, of SPS’ regulatory assets represented past expenditures not earning a return. Amounts primarily related to formula rates, losses on reacquired debt and certain rate case expenditures.

5. Borrowings and Other Financing Instruments

Short-Term Borrowings

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:


										Three Months Ended Dec. 31, 2018				Year Ended Dec. 31
(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2017			Twelve Months Ended Dec. 31, 2016			Twelve Months Ended Dec. 31, 2015						2018				2017				2016
Borrowing limit	$	100		$	100		$	100		Three Months Ended Dec. 31, 2018	$	100			$	100			$	100			$	100
Amount outstanding at period end	—			—			—			—				—				—				—
Average amount outstanding	13			28			21			14				29				13				28
Maximum amount outstanding	100			100			100			74				100				100				100
Weighted average interest rate, computed on a daily basis	1.12		%	0.67		%	0.40		%	2.13		%		1.96		%		1.12		%		0.67		%
Weighted average interest rate at end of period	N/A			N/A			N/A			N/A				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:


										Three Months Ended Dec. 31, 2018				Year Ended Dec. 31
(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2017			Twelve Months Ended Dec. 31, 2016			Twelve Months Ended Dec. 31, 2015						2018				2017				2016
Borrowing limit	$	400		$	400		$	400		Three Months Ended Dec. 31, 2018	$	400			$	400			$	400			$	400
Amount outstanding at period end	—			50			15			42				42				—				50
Average amount outstanding	69			43			100			20				30				69				43
Maximum amount outstanding	176			140			246			100				144				176				140
Weighted average interest rate, computed on a daily basis	1.13		%	0.67		%	0.46		%	2.45		%		2.27		%		1.13		%		0.67		%
Weighted average interest rate at end of period	NA			0.95			0.60			2.80				2.80				NA				0.95

Letters of Credit — SPS may use letters of credit, ~~generally~~typically with terms of one-year, to provide financial guarantees for certain operating obligations. At Dec. 31, ~~2017~~2018 and ~~2016,~~2017, there were $3$2 million and $5$3 million of letters of credit outstanding, respectively, under the credit facility. ~~The contract amounts of these letters of credit~~Amounts approximate their fair ~~value and are subject to fees.~~value.

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~~Features of SPS’ credit ~~facility include:~~facility:

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


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


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

The credit facility has a ~~financial covenant requiring~~cross-default provision that SPS will be in default on its borrowings under the facility if SPS or any of its future significant subsidiaries whose total assets exceed 15% of SPS’ ~~debt-to-total capitalization ratio be less than or equal to 65 percent. SPS was~~total assets default on indebtedness in ~~compliance as its debt-to-total capitalization ratio was 46 percent and 47 percent at Dec. 31, 2017 and 2016, respectively.~~ an aggregate principal amount exceeding $75 million.

If SPS does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender.

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

Dec. 31, 2018, SPS was in compliance with all financial ~~covenants on its debt agreements as of Dec. 31, 2017 and 2016.~~covenants.

~~At Dec. 31, 2017,~~ SPS had the following committed credit ~~facility~~facilities available ~~(in millions):~~as of Dec. 31, 2018.


Credit Facility ^(a)	Credit Facility ^(a)	Drawn ^(b)		Available		Drawn ^(b)	Available
$	400	$	3	$	397
$400						$44	$356


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


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

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. SPS had no direct advances on the ~~credit~~ facility outstanding at Dec. 31, ~~2017~~2018 and ~~2016.~~

2017.

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

Long term debt obligations for SPS as of Dec. 31:

~~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.~~



(Millions of Dollars)	Maturity Range	Interest Rate Range 2018	Interest Rate Range 2017	2018			2017
Mortgage bonds	2024 - 2048	3.30% - 4.50%	3.30% - 4.50%	$	1,800		$	1,500
Unsecured senior notes	2033 - 2036	6.00%	6.00% - 8.75%	350			350
Unamortized discount				(4		)	(2		)
Unamortized debt issuance cost				(20		)	(18		)
Current maturities				—			—
Total long term debt				$	2,126		$	1,830

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

Deferred Financing Costs — Deferred financing costs of approximately ~~$18~~$20 million and ~~$15~~$18 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, ~~2017~~2018 and ~~2016,~~2017, respectively. SPS is amortizing these financing costs over the remaining maturity periods of the related debt.

2018 financings:



Amount	Financing Instrument	Interest Rate		Maturity Date
$300 million	First mortgage bonds	4.40	%	Nov 15, 2048

2017 financings:



Amount	Financing Instrument	Interest Rate		Maturity Date
$450 million	First mortgage bonds	3.70	%	Aug 15, 2047

Capital Stock — SPS has the following preferred stock:



	Preferred Stock Authorized (Shares)	Par Value of Preferred Stock	Preferred Stock Outstanding (Shares)2018 and 2017
SPS	10,000,000	1.00	0

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

~~The~~SPS’ state regulatory commission imposes the most restrictive dividend ~~limitation for SPS is imposed by its state regulatory commissions. SPS’ state regulatory commissions indirectly limit the amount~~limitations.

Requirements and actuals as of ~~dividends that SPS can pay Xcel Energy Inc. by requiring an equity-to-total capitalization ratio (excluding short-term debt) between 45.0 percent and 55.0 percent. In addition,~~Dec. 31, 2018:



Equity to Total Capitalization Ratio - Required Range				Equity to Total Capitalization Ratio - Actual ^(a)
Low		High		2018
45.0	%	55.0	%	54.4	%


^(a)	SPS excludes short-term debt.



	Unrestricted Retained Earnings			Total Capitalization			Limit on Total Capitalization
	2018			2018			2018
SPS^(a)	$	605.7	million	$	4.7	billion	N/A

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

6. Revenues

Revenue is classified by the type of goods/services rendered and market/customer type. SPS’ ~~equity ratio (excluding short-term debt) was 53.8 percent at Dec. 31, 2017 and $542 million in retained earnings was not restricted.~~operating revenues (subsequent to adoption of the revised revenue guidance) consists of the following:



(Millions of Dollars)	Year Ended Dec. 31, 2018
Major product lines
Revenue from contracts with customers:
Residential	$	363.7
C&I	828.3
Other	44.7
Total retail	1,236.7
Wholesale	426.0
Transmission	231.1
Other	12.8
Total revenue from contracts with customers	1,906.6
Alternative revenue and other	26.6
Total revenues	$	1,933.2


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


6.7.	Income Taxes

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

Corporate federal tax rate reduction from ~~35 percent~~35% to ~~21 percent;~~21%;

Normalization of resulting plant-related excess deferred taxes;

Elimination of the corporate alternative minimum tax;

Continued interest expense deductibility and discontinued bonus depreciation for regulated public utilities;

Limitations on certain executive compensation deductions;

Limitations on certain deductions for NOLs arising after Dec. 31, 2017 (limited to ~~80 percent~~80% of taxable income);

Repeal of the section 199 manufacturing deduction; and,

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

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~~

Reductions in deferred tax assets and liabilities due to ~~the reduction~~a decrease in corporate federal tax rates typically result in a net tax benefit. However, the impacts are primarily recognized as regulatory liabilities refundable to utility customers as a result of IRS requirements and past regulatory treatment of deferred taxes in the determination of regulated rates of the utility subsidiaries, including deferred taxes related to regulated plant and certain other deferred tax assets and liabilities, the impact was primarily recognized as a regulatory liability refundable to utility customers.treatment.

~~The fourth quarter 2017 estimated accounting~~Estimated impacts ~~of the December 2017 enactment~~ of the new tax law atfor SPS in December 2017 included:

$426 million ($559 million grossed-up for tax) of reclassifications of plant-related excess deferred taxes to regulatory liabilities upon valuation at the new ~~21 percent~~21% federal rate. The regulatory liabilities will be amortized consistent with IRS normalization requirements, resulting in customer refunds over the average remaining life of the related property;

$45 million and $28 million of reclassifications (grossed-up for tax) of excess deferred taxes for non-plant related deferred tax assets and liabilities, respectively, to regulatory assets and liabilities; and,

$8 million of total estimated income tax benefit related to the federal tax reform implementation, and a $2 million reduction to net income related to the allocation of Xcel Energy Services Inc.’s tax rate change on its deferred taxes.

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~~Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows:



Tax Year(s)		Expiration
2009 - ~~2011~~		~~June 2018~~
~~2012 - 2013~~2014		October ~~2018~~
~~2014~~		~~September 2018~~2019
2015		September 2019
2016		September 2020
2017		September 2021

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 the Office of 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. AsIn the second quarter of ~~Dec. 31, 2017, the case has been forwarded to~~2018, the Joint Committee on ~~Taxation.~~

Taxation completed its review and took no exception to the agreement. As a result, the remaining unrecognized tax benefit was released and recorded as a payable to the IRS.

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,~~2018, the case has been forwarded to the Office of Appeals and Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is ~~uncertain.~~unknown.

In the fourth quarter of 2018, the IRS began an audit of tax years 2014 - 2016, however no adjustments have been proposed.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, ~~2017,~~2018, 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~~2010. There are currently no state income tax audits in ~~September 2017, began an audit of 2011. In the fourth quarter of 2017, Texas concluded these audits and SPS recognized the related benefit.~~progress.

Unrecognized Tax Benefits — ~~The unrecognized~~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.

Unrecognized tax benefits - permanent vs temporary:

~~A reconciliation of the amount of~~



(Millions of Dollars)	Dec. 31, 2018		Dec. 31, 2017
Unrecognized tax benefit — Permanent tax positions	$	3.0	$	2.3
Unrecognized tax benefit — Temporary tax positions	1.5		2.0
Total unrecognized tax benefit	$	4.5	$	4.3

Changes in unrecognized tax ~~benefit is as follows:~~benefits:

(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



(Millions of Dollars)	2018			2017			2016
Balance at Jan. 1	$	4.3		$	28.7		$	24.7
Additions based on tax positions related to the current year	0.6			0.9			1.4
Reductions based on tax positions related to the current year	(0.1		)	(0.6		)	—
Additions for tax positions of prior years	0.1			1.3			3.9
Reductions for tax positions of prior years	(0.3		)	(19.9		)	(1.3		)
Settlements with taxing authorities	(0.1		)	(6.1		)	—
Balance at Dec. 31	$	4.5		$	4.3		$	28.7

~~A reconciliation of the beginning and ending amount of unrecognized~~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~~benefits were reduced by ~~the~~ tax benefits associated with NOL and tax credit ~~carryforwards. The amounts of~~carryforwards:



(Millions of Dollars)	Dec. 31, 2018			Dec. 31, 2017
NOL and tax credit carryforwards	$	(3.8	)	$	(5.9	)

Net deferred tax ~~benefits~~liability associated with ~~NOL~~the unrecognized tax benefit amounts and related NOLs and tax ~~credit~~credits carryforwards ~~are as follows:~~were $0.8 million and $2.7 million at Dec. 31, 2018 and Dec. 31, 2017, respectively.

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

~~It is reasonably possible that SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals progresses and audit resumes and state audits resume.~~ As the IRS Appeals ~~progresses,~~and federal audit progress and state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately ~~$1 million.~~$3.6 million in the next 12 months.

~~The payable~~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~~

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


(Millions of Dollars)	2017			2016			2015			2018		2017			2016
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 Jan. 1										$	0.5	$	(0.9	)	$	—
Interest income (expense) related to unrecognized tax benefits										0.2		1.4			(0.9		)
Receivable (payable) for interest related to unrecognized tax benefits at Dec. 31	$	0.5		$	(0.9	)	$	—		$	0.7	$	0.5		$	(0.9	)

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2018, 2017, ~~2016,~~ or ~~2015.~~

2016.

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)	2018		2017
Federal NOL carryforward	$	—	$	115.0
Federal tax credit carryforwards	5.7		5.2
State NOL carryforwards	2.9		40.5

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

~~The federal~~

Federal carryforward periods expire between 2021 and ~~2037. The~~2038 and 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~~

Effective income tax rate for ~~the~~ years ~~ending~~ended Dec. 31:


	2017		2016 ^(a)		2015 ^(a)		2018		2017 ^(a)		2016 ^(a)
Federal statutory rate	35.0	%	35.0	%	35.0	%	21.0	%	35.0	%	35.0	%
State income tax on pretax income, net of federal tax effect	0.9	%	1.0	%	1.0	%	2.3	%	2.0	%	2.2	%
Increases (decreases) in tax from:
Tax reform	(3.5	)	—		—
Regulatory differences - ARAM ^(b)							(4.2	)	—		—
Tax Reform							—		(3.5	)	—
Adjustments attributable to tax returns							(1.5	)	(0.4	)	(1.1	)
Regulatory differences - other utility plant items							(1.3	)	(0.8	)	(1.0	)
Amortization of excess nonplant deferred taxes							(1.2	)	—		—
Tax credits recognized, net of federal income tax expense							(0.7	)	(0.7	)	(0.5	)
Regulatory differences - Deferral of ARAM ^(c)							0.7		—		—
Change in unrecognized tax benefits	(1.0	)	0.8		0.5		0.1		(1.0	)	0.8
Tax credits recognized, net of federal income tax expense	(0.7	)	(0.5	)	(0.3	)
Regulatory differences - other utility plant items	(0.8	)	(1.0	)	(0.8	)
Other, net	0.2		(0.2	)	1.7		0.2		(0.5	)	(0.4	)
Effective income tax rate	30.1	%	35.1	%	37.1	%	15.4	%	30.1	%	35.0	%


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


^(b)	ARAM is a method to flow back excess deferred taxes to customers.


^(c)	ARAM has been deferred when regulatory treatment has not been established. As Xcel Energy received direction from its regulatory commissions regarding the return of excess deferred taxes to customers, the ARAM deferral was reversed. This resulted in a reduction to tax expense with a corresponding reduction to revenue.

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

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



(Millions of Dollars)	2018			2017			2016
Current federal tax expense (benefit)	$	12.3		$	(20.9	)	$	(40.9	)
Current state tax expense (benefit)	2.3			(12.8		)	(2.9		)
Current change in unrecognized tax expense (benefit)	2.3			(24.3		)	3.1
Deferred federal tax expense	20.5			89.9			116.4
Deferred state tax expense	3.6			14.5			7.8
Deferred change in unrecognized tax (benefit) expense	(2.0		)	22.1			(1.2		)
Deferred ITCs	(0.1		)	(0.1		)	(0.2		)
Total income tax expense	$	38.9		$	68.4		$	82.1

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



(Millions of Dollars)	2018			2017			2016
Deferred tax expense (benefit) excluding items below	$	44.2		$	(414.2	)	$	128.4
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(22.0		)	540.7			(5.4		)
Tax (expense) benefit allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other	(0.1		)	—			—
Deferred tax expense	$	22.1		$	126.5		$	123.0

(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~~Components of the net deferred tax liability atas of Dec. ~~31 were as follows:~~31:

(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.~~



(Millions of Dollars)	2018		2017
Deferred tax liabilities:
Differences between book and tax bases of property	$	680.6	$	654.4
Regulatory assets	49.2		46.8
Pension expense	32.3		33.8
Other	2.9		4.6
Total deferred tax liabilities	$	765.0	$	739.6

Deferred tax assets:
Regulatory liabilities	116.8		114.6
NOL carryforward	0.2		26.2
Deferred fuel costs	12.7		10.4
Other employee benefits	5.6		5.8
Tax credit carryforward	5.7		5.2
Other	4.9		2.5
Total deferred tax assets	$	145.9	$	164.7
Net deferred tax liability	$	619.1	$	574.9


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.

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


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:~~

include:

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

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

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

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

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of important inputs to the value of FTRs between auction processes, including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3. Non-trading monthly FTR settlements are expected to be recovered through fuel and purchased energy cost recovery mechanisms, and therefore changes in the fair value of the yet to be settled portions of FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of SPS, the numerous unobservable quantitative inputs pertinent to the value of FTRs are 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 As of Dec. 31, ~~2017,~~2018, 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~~SPS is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, ~~which is made up~~comprised of management personnel not directly involved in the activities governed by this policy.

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

~~The following table details the gross~~Gross notional amounts of commodity FTRs at Dec. 31, ~~2017~~2018 and ~~2016:~~

2017:

(Amounts in Thousands) ^(a)

Dec. 31, 2017

Dec. 31, 2016

(Amounts in Millions) ^(a)

Dec. 31, 2018

Dec. 31, 2017

MWh of electricity

4,251

2,685

5.5

4.3


^(a)	~~Amounts~~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~~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,~~2018, two of the eight most significant counterparties for these activities, comprising ~~$10.6~~$11.6 million or ~~28 percent~~28% of this credit exposure, had investment grade ratings from ~~S&P’s,~~Standard & Poor’s, Moody’s or Fitch Ratings. Five of the eight most significant counterparties, comprising ~~$7.8~~$8.7 million or ~~20 percent~~21% 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~~Another of these significant counterparties, comprising ~~approximately $0.1~~$0.6 million or less than ~~1 percent~~1% of this credit exposure, had credit quality less than investment grade, based on external analysis. ~~Seven~~Six of these significant counterparties are municipal or cooperative electric entities, or other utilities.

~~Financial Impact of~~ Qualifying Cash Flow Hedges — ~~The~~Financial impact of qualifying interest rate cash flow hedges on SPS’ accumulated other comprehensive loss, included in the statements of common stockholder’s equity and in the statements of comprehensive ~~income, is detailed in the following table:~~income:


(Thousands of Dollars)	2017			2016			2015
(Millions of Dollars)										2018			2017			2016
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(678	)	$	(817	)	$	(989	)	$	(0.8	)	$	(0.7	)	$	(0.8	)
After-tax net realized losses on derivative transactions reclassified into earnings	39			139			172			0.1			—			0.1
Adoption of ASU. 2018-02 ^(a)										—			(0.1		)	—
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(639	)	$	(678	)	$	(817	)	$	(0.7	)	$	(0.8	)	$	(0.7	)


^(a)	In 2017, SPS implemented ASU No. 2018-02 related to TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings.

Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were $0.1 million, $0.1 million and $0.2 million ~~and $0.3 million each of~~for the years ended Dec. 31, 2018, 2017 and 2016, ~~and 2015,~~ respectively.

Changes in the fair value of FTRs resulting in pre-tax net gains of $7.0 million, $0.5 million and $3.0 million recognized for the years ended Dec. 31, 2018, 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 $4.4 million, $0.8 million and $2.1 million were recognized for the years ended Dec. 31, 2018, 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, 2018, 2017 ~~2016~~ and ~~2015. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.~~2016.

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, 2018 and 2017:


	Dec. 31, 2017														Dec. 31, 2018													Dec. 31, 2017
	Fair Value						Fair Value Total			Counterparty Netting ^(b)					Fair Value													Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3				Total
(Millions of Dollars)															Level 1		Level 2		Level 3		Fair Value Total		Netting ^(a)			Total		Level 1		Level 2		Level 3		Fair Value Total		Netting ^(a)			Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	14,717	$	14,717		$	(1,994	)	$	12,723	$	—	$	—	$	14.9	$	14.9	$	(0.2	)	$	14.7	$	—	$	—	$	14.7	$	14.7	$	(2.0	)	$	12.7
Total current derivative assets	$	—	$	—	$	14,717	$	14,717		$	(1,994	)	12,723		$	—	$	—	$	14.9	$	14.9	$	(0.2	)	14.7		$	—	$	—	$	14.7	$	14.7	$	(2.0	)	12.7
PPAs ^(a)													3,159
PPAs ^(b)																										3.1													3.2
Current derivative instruments													$	15,882												$	17.8												$	15.9
Noncurrent derivative assets
PPAs ^(a)													$	18,954
PPAs ^(b)																										15.8													19.0
Noncurrent derivative instruments													$	18,954												$	15.8												$	19.0
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	1,994	$	1,994		$	(1,994	)	$	—	$	—	$	—	$	0.2	$	0.2	$	(0.2	)	$	—	$	—	$	—	$	2.0	$	2.0	$	(2.0	)	$	—
Total current derivative liabilities	$	—	$	—	$	1,994	$	1,994		$	(1,994	)	—		$	—	$	—	$	0.2	$	0.2	$	(0.2	)	—		$	—	$	—	$	2.0	$	2.0	$	(2.0	)	—
PPAs ^(a)													3,565
PPAs ^(b)																										3.6													3.6
Current derivative instruments													$	3,565												$	3.6												$	3.6
Noncurrent derivative liabilities
PPAs ^(a)													$	19,949
PPAs ^(b)																										16.4													19.9
Noncurrent derivative instruments													$	19,949												$	16.4												$	19.9

^(a)

SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2018 and 2017. At both Dec. 31, 2018 and 2017, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.


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

^(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~~Changes in Level 3 commodity derivatives for the years ended Dec. 31, 2018, 2017 ~~2016~~ and ~~2015:~~2016:


	Year Ended Dec. 31									Year Ended Dec. 31
(Thousands of Dollars)	2017			2016			2015
(Millions of Dollars)										2018			2017			2016
Balance at Jan. 1	$	1,955		$	5,060		$	15,884		$	12.7		$	2.0		$	5.1
Purchases	41,176			7,616			23,425			32.3			41.2			7.6
Settlements	(55,758		)	(41,923		)	(31,703		)	(41.6		)	(55.8		)	(41.9		)
Net transactions recorded during the period:
Net gains (losses) recognized as regulatory assets	25,350			31,202			(2,546		)
Net gains recognized as regulatory assets										11.3			25.3			31.2
Balance at Dec. 31	$	12,723		$	1,955		$	5,060		$	14.7		$	12.7		$	2.0

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.~~- 2018.

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:~~value:



	2018				2017
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	2,126.1	$	2,139.8	$	1,829.9	$	2,002.0

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~~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~~Fair value estimates are based on information available to management as of Dec. 31, ~~2017~~2018 and ~~2016,~~2017, and given the observability of the inputs, ~~to these estimates, the~~ fair values presented for long-term debt ~~have been~~were assigned aas Level 2.


~~10.~~9.	~~Rate Matters~~Benefit Plans and Other Postretirement Benefits

Xcel Energy, which includes SPS, has several noncontributory, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a combination of years of service and average pay. Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs subject to the limitations of applicable employee benefit and tax laws.

~~Tax Reform~~ — ~~Regulatory Proceedings~~

In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The ~~specific impacts~~SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides benefits for compensation that is in excess of the ~~TCJA on retail customer rates are subject~~limits applicable to ~~regulatory approval. SPS is in~~ the ~~process of quantifying the rate impacts~~qualified pension plans, with distributions funded by Xcel Energy’s consolidated operating cash flows. Obligations of the ~~TCJA~~SERP and ~~addressing these impacts~~nonqualified plan as of Dec. 31, 2018 and 2017 were $33 million and $37 million, respectively, of which $2 million was attributable to SPS 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~~and 2017. In 2018 and 2017, Xcel Energy recognized net benefit cost for the ~~impacts~~SERP and nonqualified plans of ~~the TCJA. On Feb. 16, 2018, SPS provided the PUCT supplemental testimony on the impacts~~$4 million and $5 million, respectively, of ~~the TCJA for its ongoing Texas 2017 electric rate case, including increasing its equity ratio~~which immaterial amounts were attributable to ~~58 percent to offset the negative impact of the TCJA on its credit metrics and potentially its credit ratings.~~SPS.

In ~~February 2018, SPS provided the NMPRC a preliminary quantification~~2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of the ~~impacts~~SERP and its deferred compensation plan. Rabbi trust funding of deferred compensation plan distributions attributable to SPS will be supplemented by SPS’s operating cash flows.

Xcel Energy has a contributory health and welfare benefit plan that provides health care and death benefits to certain Xcel Energy retirees.

Xcel Energy discontinued health care benefits for SPS bargaining employees hired after Jan. 1, 2012.

Xcel Energy discontinued subsidizing health care benefits for nonbargaining employees of the ~~TCJA~~former NCE, which includes SPS employees, who retired after June 30, 2003.

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

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

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

Investment returns in 2017 were above the assumed level of 6.78%;

Investment returns in 2016 were below the assumed level of 6.78%; and,

In 2019, Xcel Energy’s expected investment-return assumption is 6.78%.

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

State agencies also have issued guidelines to the funding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for Texas and New Mexico ~~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~~amounts collected in rates. These assets are invested 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 appealmanner consistent with the ~~Texas State District Court (District Court) challenging~~investment strategy for 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 decisionpension plan.

Xcel Energy’s ongoing investment strategy 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,~~plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a ~~requested ROE~~plan’s funded status increases over time. The investment recommendations result in a greater percentage of ~~10.25 percent,~~long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a ~~Texas retail electric rate base~~greater percentage of ~~approximately $1.9 billion and an equity ratio of 53.97 percent.~~growth assets being allocated to plans having relatively lower funded status ratios.

Pension Plan Assets

The following ~~table summarizes~~presents, for each of the fair value hierarchy levels, SPS’ ~~rate increase request:~~pension plan assets measured at fair value:

Revenue Request (Millions of Dollars)
Incremental revenue request $ 69
TCRF revenue conversion to base rates ^(a)
(14 )
Net revenue increase request $ 55



	Dec. 31, 2018												Dec. 31, 2017
(Millions of Dollars)	Level 1		Level 2		Level 3		Measured at NAV			Total			Level 1			Level 2		Level 3		Measured at NAV		Total
Cash equivalents	$	21.6	$	—	$	—	$	—		$	21.6		26.9			—		—		—		$	26.9
Commingled funds:	128.6		—		—		132.5			261.1			145.7			—		—		142.7		288.4
Debt securities:	—		98.1		—		—			98.1			—			105.3		—		—		105.3
Equity securities:	14.4		—		—		—			14.4			15.2			—		—		—		15.2
Other	0.2		0.8		—		(4.0		)	(3.0		)	(3.3		)	0.6		—		0.1		(2.6		)
Total	$	164.8	$	98.9	$	—	$	128.5		$	392.2		$	184.5		$	105.9	$	—	$	142.8	$	433.2

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



	Dec. 31, 2018 ^(a)										Dec. 31, 2017 ^(a)
(Millions of Dollars)	Level 1		Level 2		Level 3		Measured at NAV		Total		Level 1		Level 2		Level 3		Measured at NAV		Total
Cash equivalents	$	1.8	$	—	$	—	$	—	$	1.8	$	2.8	$	—	$	—	$	—	$	2.8
Insurance contracts	—		4.3		—		—		4.3		—		4.7		—		—		4.7
Commingled funds:	12.8		—		—		3.8		16.6		14.1		—		—		—		14.1
Debt securities:	—		17.2		—		—		17.2		—		19.0		—		—		19.0
Equity securities:	—		—		—		—		—		3.3		—		—		—		3.3
Other	—		0.1		—		—		0.1		—		0.2		—		—		0.2
Total	$	14.6	$	21.6	$	—	$	3.8	$	40.0	$	20.2	$	23.9	$	—	$	—	$	44.1


^(a)	~~The roll-in of the TCRF rider revenue into base rates will not have an impact~~See Note 8 for further information 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.fair value measurement inputs and methods.

No assets transferred in or out of Level 3 for the years ended Dec. 31, 2018 or 2017.

~~Key dates~~Funded Status — Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for Xcel Energy are presented in the ~~revised procedural schedule~~following table:



	Pension Benefits						Postretirement Benefits
(Millions of Dollars)	2018			2017			2018			2017
Change in Benefit Obligation:
Obligation at Jan. 1	$	515.9		$	483.6		$	47.0		$	41.9
Service cost	9.7			9.8			1.1			0.9
Interest cost	18.4			19.7			1.6			1.7
Plan amendments	—			(1.0		)	—			—
Actuarial (gain) loss	(34.8		)	31.2			(5.1		)	4.7
Plan participants’ contributions	—			—			0.6			0.6
Benefit payments ^(a)	(31.4		)	(27.4		)	(3.4		)	(2.8		)
Obligation at Dec. 31	$	477.8		$	515.9		$	41.8		$	47.0
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	433.2		$	380.4		$	44.1		$	42.3
Actual return on plan assets	(17.6		)	56.7			(1.3		)	3.8
Employer contributions	8.0			23.5			—			0.2
Plan participants’ contributions	—			—			0.6			0.6
Benefit payments	(31.4		)	(27.4		)	(3.4		)	(2.8		)
Fair value of plan assets at Dec. 31	$	392.2		$	433.2		$	40.0		$	44.1
Funded status of plans at Dec. 31	$	(85.6	)	$	(82.7	)	$	(1.8	)	$	(2.9	)
Amounts recognized in the Balance Sheet at Dec. 31:
Noncurrent liabilities	(85.6		)	(82.7		)	(1.8		)	(2.9		)
Net amounts recognized	$	(85.6	)	$	(82.7	)	$	(1.8	)	$	(2.9	)
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.31		%	3.63		%	4.32		%	3.62		%
Expected average long-term increase in compensation level	3.75			3.75			N/A			N/A
Mortality table	RP-2014			RP-2014			RP-2014			RP-2014
Health care costs trend rate — initial: Pre-65	N/A			N/A			6.50		%	7.00		%
Health care costs trend rate — initial: Post-65	N/A			N/A			5.30		%	5.50		%
Ultimate trend assumption — initial: Pre-65	N/A			N/A			4.50		%	4.50		%
Ultimate trend assumption — initial: Post-65	N/A			N/A			4.50		%	4.50		%
Years until ultimate trend is reached	N/A			N/A			4			5


^(a)	Includes approximately $6.9 million in 2018 and $0 million in 2017, of lump-sum benefit payments used in the determination of a settlement charge.

Accumulated benefit obligation for the pension plan was $445.8 million and $478.8 million as of Dec. 31, 2018 and 2017, respectively.

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

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

~~Intervenors’ direct testimony — April 25, 2018;~~



	Pension Benefits									Postretirement Benefits
(Millions of Dollars)	2018			2017			2016			2018			2017			2016
Service cost	$	9.7		$	9.8		$	9.8		$	1.1		$	0.9		$	0.8
Interest cost	18.4			19.7			21.2			1.6			1.7			1.8
Expected return on plan assets	(28.3		)	(27.9		)	(27.6		)	(2.5		)	(2.4		)	(2.4		)
Amortization of prior service credit	(0.1		)	—			—			(0.4		)	(0.4		)	(0.4		)
Amortization of net loss	14.1			13.0			12.0			(0.4		)	(0.6		)	(0.6		)
Settlement charge ^(a)	3.2			—			—			—			—			—
Net periodic pension cost (credit)	17.0			14.6			15.4			(0.6		)	(0.8		)	(0.8		)
Costs not recognized due to effects of regulation	(2.2		)	0.3			2.0			—			—			—
Net benefit cost (credit) recognized for financial reporting	$	14.8		$	14.9		$	17.4		$	(0.6	)	$	(0.8	)	$	(0.8	)
Significant Assumptions Used to Measure Costs:
Discount rate	3.63		%	4.13		%	4.66		%	3.62		%	4.13		%	4.65		%
Expected average long-term increase in compensation level	3.75			3.75			4.00			—			—			—
Expected average long-term rate of return on assets	6.78			6.78			6.78			5.80			5.80			5.80

^(a)

A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2018, as a result of lump-sum distributions during the 2018 plan year, SPS recorded a total pension settlement charge of $3.3 million the majority of which $0 million was not recognized due to the effects of regulation.

~~PUCT Staff direct testimony — May 2, 2018;~~



	Pension Benefits						Postretirement Benefits
(Millions of Dollars)	2018			2017			2018			2017
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	230.9		$	237.0		$	(9.6	)	$	(8.6	)
Prior service credit	(1.2		)	(1.3		)	(1.8		)	(2.2		)
Total	$	229.7		$	235.7		$	(11.4	)	$	(10.8	)
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	$	12.9		$	13.9		$	—		$	—
Noncurrent regulatory assets	216.8			221.8			—			—
Current regulatory liabilities	—			—			(0.9		)	(0.8		)
Noncurrent regulatory liabilities	—			—			(10.5		)	(10.0		)
Total	$	229.7		$	235.7		$	(11.4	)	$	(10.8	)

~~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~~



Measurement date	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017

~~Appeal~~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 ~~the New Mexico~~income tax and other pension-related regulations. Required contributions were made in 2016 ~~Electric Rate Case Dismissal~~- 2019 to meet minimum funding requirements. ~~— In November~~

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

$150 million in January 2019, of which $17 million was attributable to SPS;

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

$162 million in 2017, of which $24 million was attributable to SPS; and,

$125 million in 2016, of which $18 million was attributable to SPS.

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

The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved. Additional cash funding requirements are prescribed by certain state and federal rate ~~case with the NMPRC seeking an increase in base rates of~~regulatory authorities. Xcel Energy’s voluntary postretirement funding contributions were as follows:

Expects to contribute approximately ~~$41~~$11 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 $832during 2019;

$11 million during 2018;

$20 million during 2017; and, ~~a FTY ending June 30, 2018. In April 2017, the NMPRC dismissed SPS’ rate case. In May 2017,~~

$18 million during 2016.

Amounts attributable to SPS ~~filed a notice of appeal to the New Mexico Supreme Court. A decision is pending.~~were immaterial.

Target asset allocations:



	Pension Benefits				Postretirement Benefits
	2018		2017		2018		2017
Domestic and international equity securities	35	%	34	%	18	%	24	%
Long-duration fixed income securities	32		31		—		—
Short-to-intermediate fixed income securities	16		19		70		60
Alternative investments	15		14		8		9
Cash	2		2		4		7
Total	100	%	100	%	100	%	100	%

~~New Mexico 2017 Electric Rate Case~~Plan Amendments — ~~In October 2017,~~Xcel Energy, which includes SPS, ~~filed an electric rate case with~~amended 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 MWXcel Energy Inc. Nonbargaining Pension Plan (South) in 2017 ~~from certain wholesale customers~~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 2018, there were no plan amendments made which affected the benefit obligation.

Projected Benefit Payments

SPS’ projected benefit payments:



(Millions of Dollars)	Projected Pension Benefit Payments	Gross Projected Postretirement Health Care Benefit Payments	Expected Medicare Part D Subsidies	Net Projected Postretirement Health Care Benefit Payments
2019	29.7	3.2	—	3.2
2020	30.0	3.1	—	3.1
2021	29.3	3.2	—	3.2
2022	30.8	3.2	—	3.2
2023	30.8	3.2	—	3.2
2024-2028	156.2	14.4	0.2	14.2

Defined Contribution Plans

Xcel Energy, which includes SPS, maintains 401(k) and ~~seeks~~other defined contribution plans that cover most employees. The expense to ~~adjust the life of SPS’ Tolk power plant (Unit 1 from 2042 to 2032~~these plans for SPS was approximately $3 million in 2018, 2017 and ~~Unit 2 from 2045 to 2032).~~2016.

~~Key dates~~10. Commitments and Contingencies

Legal

SPS is involved in various litigation matters that are being defended and handled in the ~~procedural schedule~~ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves complex judgments about future events. Management maintains accruals for losses that are ~~as follows:~~

~~Staff~~probable of being incurred and ~~intervenor direct testimony — April 13, 2018;~~

~~SPS’ rebuttal testimony — May 2, 2018; and~~

~~Hearings — May 15 - 25, 2018.~~

~~SPS anticipates~~subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a ~~decision and implementation of final rates~~reasonably possible loss in certain situations, including when (1) the damages sought are indeterminate, (2) the proceedings are in the ~~second half~~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 ~~2018. As discussed above,~~such matters, including a possible eventual loss.

For current proceedings not specifically reported herein, management does not anticipate that the ~~NMPRC has opened a docket on the impact of the TCJA, which may~~ultimate liabilities, if any, arising from such current proceedings would have a ~~significant impact~~material effect on ~~this rate case.~~SPS’ financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

~~Pending Regulatory Proceedings — FERC~~

Rate Matters

SPP ~~Open Access Transmission Tariff (OATT)~~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.

In July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP ~~is also billing SPS ongoing~~the right to recover these charges ~~of approximately $0.5 million per month. SPS is currently seeking~~was remanded to the FERC. SPS’ recovery of these ~~SPP~~ charges (from 2008 through 2016) is being reviewed by the FERC, which is expected to rule in ~~its pending Texas and New Mexico base rate cases.~~

the first quarter of 2019.

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~~in violation of the SPP OATT. The FERC has granted a rehearing of further consideration in May 2018. The timing of the FERC action on the SPS rehearing is uncertain. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the differential in future rate proceedings.

SPP Filing to Assign GridLiance Facilities to SPS Rate Zone — In August 2018, SPP filed a request with the FERC to amend its OATT to include the costs of the GridLiance High Plains, LLC. facilities in the SPS rate zone. In a previous filing, the FERC determined that some of these facilities did not qualify as transmission facilities under the SPP OATT. SPP’s proposed tariff changes could result in an increase in the ATRR of $9.5 million per year, with $6 million allocated to SPS’ retail customers.

The remaining $3.5 million would be paid by other wholesale loads in the SPS rate zone. In September 2018, SPS protested the proposed SPP tariff charges, and asked the FERC to reject the SPP filing. On October 31, 2018, the FERC issued an order accepting the proposed charges as of November 1, 2018. In December 2018, the FERC hosted a settlement hearing over the matter. A hearing will be ordered if a settlement is not reached.

SPS Filing to Modify Wholesale Transmission Rates - In 2018, SPS filed revisions to its wholesale transmission formula rate. The proposal includes an update to the depreciation rates for transmission plant. The new formula rate would provide flow-back of “excess” ADIT resulting from the TCJA and recover certain wholesale regulatory commission expenses.

The proposed changes would increase wholesale transmission revenues by approximately $9.4 million, with approximately $4.4 million of the total being recovered in SPP regional transmission rates. SPS proposed that the formula rate changes be effective February 1, 2019.

In January 2019, the FERC issued an order accepting the proposed rate changes as of February 1, 2019, subject to refund and settlement procedures. The first settlement conference is expected in the first quarter of 2019.


~~11.~~	~~Commitments and Contingencies~~

Environmental

~~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~~its predecessors 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;~~MGPs; and third-party sites, such as landfills, for which SPS is alleged to ~~be a PRP that~~have sent wastes to that site.

MGP, Landfill or Disposal Sites — SPS is currently ~~involved in~~ investigating ~~and/~~or remediating anone MGP, landfill or other disposal ~~site. SPS has identified one~~ site ~~where contamination is present~~across its service territories, 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 remediationthese activities will continue through at least ~~2018.~~2019. SPS ~~has~~ accrued $0.1 million ~~for the site~~ as of Dec. 31, 2018 and 2017, ~~and 2016, respectively.~~respectively, for this site. There may be insurance recovery and/or recovery from other ~~PRPs that will offset any~~potentially responsible parties, offsetting some portion of 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~~WOTUS 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 under the CWA that are subject to federal ~~jurisdiction. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued~~jurisdiction, referred to as “WOTUS”. The Rule has been subject to significant litigation and is currently stayed in a ~~nationwide stay~~portion of the ~~final rule~~country. SPS cannot estimate potential impacts until the legal 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 agenciesadministrative processes are ~~also undertaking a rulemaking to develop a new definition of “Waters of the U.S.”~~

finalized, but expects costs will be recoverable through regulatory mechanisms.

Federal CWA ~~Effluent Limitations Guidelines (ELG)~~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.~~CCRs. In 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport until November 2020. After 2020, ~~while the agency conducts~~SPS estimates that ELG compliance will be immaterial.

The EPA, however, is conducting a rulemaking process to potentially revise the effluent limitations and pretreatment standards, ~~for~~which may impact compliance costs. SPS estimates these ~~waste streams.~~costs will be fully recoverable through regulatory mechanisms.

~~Air~~

~~GHG Emission Standard for Existing Sources (CPP)~~ Environmental Requirements — 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 SO~~₂ ~~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.

Air

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:~~includes 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 SO~~₂ ~~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~~has issued a revised final rule adopting a BART alternative Texas only SO₂ trading program that applies to all Harrington and Tolk units. Under the trading program, SPS expects the allowance allocations to be sufficient for SO₂ ~~emissions from units in 2019 and future years.~~emissions. The anticipated costs of compliance are not expected to have a material ~~impact on the results of operations, financial position or cash flows;~~impact; and SPS believes that compliance costs would be recoverable through regulatory mechanisms.

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

parties while the EPA works on the reconsideration rulemaking.

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

The court has held the litigation in abeyance while the EPA decided whether to reconsider the rule. In August 2018, the EPA started a reconsideration rulemaking. It is not known when the EPA will make a final decision on this proposal.

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.requirements. 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 SO~~₂ 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 designatehas designated all areas near ~~SPS~~SPS’ generating plants as ~~meeting~~attaining the SO₂ NAAQS with ~~one~~an exception. ~~In June 2016, the~~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)~~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’ assets.

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~~were 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



	Dec. 31, 2018
(Millions of Dollars)	Balance Jan. 1, 2018		Accretion		Cash Flow Revisions ^(a)		Balance Dec. 31, 2018 ^(b)
Electric
Steam production	$	20.3	$	1.2	$	0.5	$	22.0
Distribution	7.0		0.3		1.8		9.1
Other	1.2		0.1		—		1.3
Total liability	$	28.5	$	1.6	$	2.3	$	32.4


^(a)	In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes in electric distribution AROs were primarily related to increased labor costs.


^(b)	There were no ARO amounts incurred or settled in 2018.



	Dec. 31, 2017
(Millions of Dollars)	Balance Jan. 1, 2017		Accretion		Cash Flow Revisions ^(a)			Balance Dec. 31, 2017 ^(b)
Electric plant
Steam production	$	20.7	$	1.3	$	(1.7	)	$	20.3
Distribution	6.8		0.2		—			7.0
Other	1.2		—		—			1.2
Total liability	$	28.7	$	1.5	$	(1.7	)	$	28.5


^(a)	In 2017, an asbestos ARO was revised for changes in timing of estimated cash flows.


^(b)	There were no ARO ~~liabilities recognized~~amounts incurred or settled ~~during the year ended Dec. 31, 2017.~~in 2018.

(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.~~2018. 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, 2018 and 2017 were $188 million and ~~2016 were~~ $197 million respectively.

Leases— SPS leases a variety of equipment and ~~$209 million, respectively.~~facilities. These leases, primarily for office space, generating facilities, vehicles, aircraft and power-operated equipment, are accounted for as operating leases.

Total expenses (including capacity payments) under operating lease obligations for SPS and the corresponding capacity payments for PPAs accounted for as operating leases for the year ended Dec. 31:

~~Legal Contingencies~~



(Millions of Dollars)	2018		2017		2016
Total expense	$	59.0	$	57.8	$	56.6
Capacity payments	51.1		51.4		50.6

~~SPS is involved in various litigation matters that are being defended and handled~~Included 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~~commitments under operating leases are estimated future capacity payments under PPAs that have been accounted 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.~~operating leases.

~~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 guidanceFuture commitments 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~~operating leases 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



(Millions of Dollars)	Operating Leases		PPA ^{(a) (b)} Operating Leases		Total Operating Leases
2019	$	5.2	$	46.7	$	51.9
2020	5.2		46.2		51.4
2021	5.1		46.2		51.3
2022	5.1		46.2		51.3
2023	5.1		46.2		51.3
Thereafter	56.3		450.8		507.1


^(a)	~~Includes the non-qualified pension plan.~~Amounts do not include PPAs accounted for as executory contracts.


^(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.~~PPA operating leases contractually expire through 2033.

Non-Lease 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.

~~The components of regulatory liabilities shown~~In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Capacity payments are contingent on the ~~balance sheets~~IPP meeting contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of ~~SPS at Dec. 31,~~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 $57.6 million, $58.4 million and $56.8 million in 2018, 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.~~

respectively.

At Dec. 31, ~~2017~~2018, the estimated future payments for capacity that SPS is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:



(Millions of Dollars)	Capacity
2019	$	20.3
2020	12.0
2021	12.2
2022	12.4
2023	12.6
Thereafter	5.7
Total	$	75.2

Fuel Contracts— SPS has entered into various long-term commitments for the purchase and ~~2016, approximately $64 million~~delivery of a significant portion of its coal and ~~$65 million~~natural gas requirements. These contracts expire between 2019 and 2033. SPS is required to pay additional amounts depending on actual quantities shipped under these agreements.

Estimated minimum purchases under these contracts as of 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.Dec. 31, 2018:



(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2019	$	127.3	$	20.3	$	30.3
2020	83.9		—		30.3
2021	41.0		—		25.2
2022	41.2		—		19.3
2023	—		—		14.1
Thereafter	—		—		33.6
Total	$	293.4	$	20.3	$	152.8

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


~~13.~~	~~Other Comprehensive Income~~

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

SPS evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities. SPS concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. SPS had approximately 1,197 MW and 897 MW of capacity under long-term PPAs at Dec. 31, 2018 and 2017, respectively, with entities that have been determined to be VIEs. These agreements have expiration dates through 2041.

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

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

11. Other Comprehensive Income

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



	2018
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges				Defined Benefit Pension and Postretirement Items				Total
Accumulated other comprehensive loss at Jan. 1	$	(0.8	)		$	(0.7	)		$	(1.5	)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $0 and $0, respectively)	0.1			^(a)	—				0.1
Amortization of net actuarial loss (net of taxes of $0 and $0, respectively)	—				—			^(b)	—
Net current period other comprehensive income	0.1				—				0.1
Accumulated other comprehensive loss at Dec. 31	$	(0.7	)		$	(0.7	)		$	(1.4	)



	2017
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges				Defined Benefit Pension and Postretirement Items				Total
Accumulated other comprehensive loss at Jan. 1	$	(0.7	)		$	(0.6	)		$	(1.3	)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $0.1 and $0, respectively)	—			^(a)	—				—
Amortization of net actuarial loss (net of taxes of $0 and $0, respectively)	—				0.1			^(b)	0.1
Net current period other comprehensive income (loss)	—				0.1				0.1
Adoption of ASU No. 2018-02 ^(c)	(0.1		)		(0.2		)		(0.3		)
Accumulated other comprehensive loss at Dec. 31	$	(0.8	)		$	(0.7	)		$	(1.5	)

Year Ended Dec. 31, 2017
(Thousands of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total
Accumulated other comprehensive loss at Jan. 1 $ (678 ) $ (612 ) $ (1,290 )
Losses reclassified from net accumulated other comprehensive loss 39
44
83
Net current period other comprehensive income 39
44
83

Adoption of ASU No. 2018-02 ^(a)
(137 ) (123 ) (260 )
Accumulated other comprehensive loss at Dec. 31 $ (776 ) $ (691 ) $ (1,467 )


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

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

~~Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2017 and 2016 were as follows:~~

Amounts Reclassified from Accumulated
Other Comprehensive Loss
(Thousands of Dollars) Year Ended Dec. 31, 2017 Year Ended Dec. 31, 2016
Losses on cash flow hedges:
Interest rate derivatives $ 63
^(a)
$ 219
^(a)
Total, pre-tax 63
219

Tax benefit (24 ) (80 )
Total, net of tax 39
139

Defined benefit pension and postretirement losses:
Amortization of net loss 69
^(b)
—
^(b)
Total, pre-tax 69
—

Tax benefit (25 ) —

Total, net of tax 44
—

Total amounts reclassified, net of tax $ 83
$ 139


^(a)	Included in interest charges.


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


^(c)	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.


~~14.~~12.	Related Party Transactions

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

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

See Note 45 for further ~~discussion of this borrowing arrangement.~~information.

~~The table below contains significant~~

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	$	—
(Millions of Dollars)							2018		2017		2016
Operating expenses:
Purchased power	1,436		8,809		8,632		$	—	$	1.4	$	8.8
Other operating expenses — paid to Xcel Energy Services Inc.	196,558		188,175		197,134		195.1		196.6		188.2
Interest expense	—		189		156		0.6		—		0.2
Interest income	—		—		6

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


	2017				2016				2018				2017
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
(Millions of Dollars)									Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	964	$	—	$	935	$	—	$	4.7	$	—	$	1.0	$	—
NSP-Wisconsin	7		—		—		333
PSCo	—		279		—		745		—		0.7		—		0.3
Other subsidiaries of Xcel Energy Inc.	326		22,298		14		13,336		5.8		19.2		0.3		22.3
	$	1,297	$	22,577	$	949	$	14,414	$	10.5	$	19.9	$	1.3	$	22.6


~~15.~~13.	Summarized Quarterly Financial Data (Unaudited)


	Quarter Ended								Quarter Ended
(Thousands of Dollars)	March 31, 2017		June 30, 2017		Sept. 30, 2017		Dec. 31, 2017
(Millions of Dollars)									March 31, 2018		June 30, 2018		Sept. 30, 2018		Dec. 31, 2018
Operating revenues	$	460,072	$	479,796	$	551,623	$	426,509	$	447.2	$	481.3	$	540.1	$	464.6
Operating income	58,415		74,489		122,407		41,498		57.1		87.6		111.0		56.0
Net income	25,055		35,362		67,781		31,015		33.1		58.5		81.5		40.2


	Quarter Ended								Quarter Ended
(Thousands of Dollars)	March 31, 2016		June 30, 2016		Sept. 30, 2016		Dec. 31, 2016
(Millions of Dollars)									March 31, 2017		June 30, 2017		Sept. 30, 2017		Dec. 31, 2017
Operating revenues	$	390,839	$	440,445	$	554,926	$	464,749	$	460.1	$	479.8	$	551.6	$	426.5
Operating income(a)	53,569		68,386		122,362		62,964		59.2		75.2		123.1		43.4
Net income	22,523		32,211		68,346		29,077		25.1		35.3		67.8		31.0


^(a)	In 2018, SPS implemented ASU No. 2017-07 related to net periodic benefit cost, which resulted in retrospective reclassification of pension costs from O&M expense to other income.

Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A — Controls and Procedures

Disclosure Controls and Procedures

SPS maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in ~~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,~~2018, based on an evaluation carried out under the supervision and with the participation of SPS’ management, including the ~~CEO~~chief executive officer and ~~CFO,~~chief financial officer, of the effectiveness of its disclosure controls and the procedures, the ~~CEO~~chief executive officer and ~~CFO~~chief financial officer 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,~~2018, 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.

~~None.~~

PART III

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

Item 10 — Directors, Executive Officers and Corporate Governance

Item 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~~2019 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~~2019 Annual Meeting of Stockholders which

definitive Proxy Statement is expected to be filed with the SEC on or about April ~~3, 2018.~~1, 2019. Such information set forth under such

heading is incorporated herein by this reference hereto.

PART IV

Item 15 — Exhibits, Financial Statement Schedules



1.1	Financial Statements
	Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, ~~2017.~~2018.
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Statements of Income — For the three years ended Dec. 31, 2018, 2017 ~~2016~~ and ~~2015.~~2016.
	Statements of Comprehensive Income — For the three years ended Dec. 31, 2018, 2017 ~~2016~~ and ~~2015.~~2016.
	Statements of Cash Flows — For the three years ended Dec. 31, 2018, 2017 ~~2016~~ and ~~2015.~~2016.
	Balance Sheets — As of Dec. 31, ~~2017~~2018 and ~~2016.~~2017.
	Statements of Common Stockholder’s Equity — For the three years ended Dec. 31, ~~2017, 2016 and 2015.~~
	~~Statements of Capitalization — As of Dec. 31,~~2018, 2017 and 2016.

2.2	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2018, 2017 ~~2016~~ and ~~2015.~~2016.

3.3	Exhibits



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



Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.01*	Amended and Restated Articles of Incorporation dated Sept. 30, 1997 ~~(Exhibit 3.01 to~~	SPS Form 10-Q for the quarter ended Sept. 30, 2017 ~~(file no. 001-03789)).~~	001-03789	3.01
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)).~~Jan. 25, 2019
4.01*	Indenture dated Feb. 1, 1999 between SPS and ~~The~~the Chase Manhattan Bank ~~(Exhibit 99.2 to~~	SPS Form 8-K ~~(file no. 001-03789)~~ dated Feb. 25, ~~1999).~~1999	001-03789	99.2
4.02*	Third Supplemental Indenture dated Oct. 1, 2003 to the indenture dated Feb. 1, 1999 between SPS and JPMorgan Chase Bank, as successor Trustee, creating $100 million principal amount of Series C and Series D Notes, ~~6 percent~~6% due 2033 ~~(Exhibit 4.04 to~~	Xcel Energy Inc. Form 10-Q ~~(file no. 001-03034)~~ for the quarter ended Sept. 30, ~~2003).~~2003	001-03034	4.04
4.03*	Fourth Supplemental Indenture dated Oct. 1, 2006 between SPS and ~~The~~the Bank of New York, as successor Trustee ~~(Exhibit 4.01 to~~	SPS Form 8-K ~~(file no. 001-03789)~~ dated Oct. 3, ~~2006).~~


2006	001-03789	4.01
~~4.06~~4.04*	Indenture dated as of Aug. 1, 2011 between SPS and ~~U.S,~~U.S. Bank National Association, as Trustee ~~(Exhibit 4.01 to~~	SPS Form 8-K dated Aug. 10, 2011 ~~(file no. 001-03789)).~~	001-03789	4.01
~~4.07~~4.05*	Supplemental Indenture dated as of Aug. 3, 2011 between SPS and U.S. Bank National Association, as Trustee, creating $200 million principal amount of ~~4.50 percent~~4.50% First Mortgage Bonds, Series No. 1 due 2041 ~~(Exhibit 4.02 to~~	SPS Form 8-K dated Aug. 10, 2011 ~~(file no. 001-03789)).~~	001-03789	4.02
~~4.08~~4.06*	Sixth Supplemental Indenture dated as of June 1, 2014 between SPS and ~~The~~the Bank of New York Mellon Trust Company, N.A., as successor ~~Trustee. (Exhibit 4.03 to SPS’~~Trustee	SPS Form 8-K dated June 2, 2014 ~~(file no. 001-03789)).~~	001-03789	4.03



~~4.10~~4.07*	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~~3.30% First Mortgage Bonds, Series No. 3 due ~~2024. (Exhibit 4.02 to SPS’~~2024	SPS Form 8-K dated June 9, 2014 ~~(file no. 001-03789)).~~	001-03789	4.02
~~4.11~~4.08*	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~~3.40% First Mortgage Bonds, Series No. 4 due ~~2046. (Exhibit 4.02 to~~2046	SPS Form 8-K ~~of SPS~~ dated Aug. 12, 2016 ~~(file no. 001-03789)).~~	001-03789	4.02
~~4.12~~4.09*	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~~3.70% First Mortgage Bonds, Series No. 5 due ~~2047. (Exhibit 4.02 to~~2047	SPS Form 8-K ~~of SPS~~ dated Aug. 9, 2017 ~~(file no. 001-03789)).~~	001-03789	4.02
4.10*	Supplemental Indenture No. 6 dated as of Oct. 1, 2018 between SPS and U.S. Bank National Association, as Trustee, creating 4.40% First Mortgage Bonds, Series No. 6 due 2048	SPS Form 8-K dated Nov. 5, 2018	001-03789	4.02
10.01*+	Xcel Energy Inc. Nonqualified Pension Plan (2009 Restatement) ~~(Exhibit 10.02 to~~	Xcel Energy Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2008).~~2008	001-03034	10.02
10.02*+	Xcel Energy Senior Executive Severance and Change-in-Control Policy (2009 ~~Amendment and~~ Restatement) ~~(Exhibit 10.05 to~~	Xcel Energy Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2008).~~2008	001-03034	10.05
10.03*+	Xcel Energy Inc. Non-Employee Directors Deferred Compensation Plan as amended and restated on Jan. 1, 2009 ~~(Exhibit 10.08 to~~	Xcel Energy Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2008).~~2008	001-03034	10.08
10.04*+	Form of Services Agreement between Xcel Energy Services Inc. and utility companies ~~(Exhibit H-1 to~~	Xcel Energy Inc. Form U5B ~~(file no. 001-03034)~~ dated Nov. 16, ~~2000).~~2000	001-03034	H-1
10.05*+	Xcel Energy Inc. Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 ~~(Exhibit 10.17 to~~	Xcel Energy Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2008).~~2008	001-03034	10.17
10.06*+	Amendment dated Aug. 26, 2009 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy ~~(Exhibit 10.06 to~~	Xcel Energy Inc. Form 10-Q ~~of Xcel Energy (file no. 001-03034)~~ for the quarter ended Sept. 30, ~~2009).~~2009	001-03034	10.06
10.07*+	Xcel Energy Inc. Executive Annual Incentive Award Plan Form of Restricted Stock Agreement ~~(Exhibit 10.08 to~~	Xcel Energy Inc. Form 10-Q ~~of Xcel Energy (file no. 001-03034)~~ for the quarter ended Sept. 30, ~~2009).~~2009	001-03034	10.08
10.08*+	Xcel Energy Inc. Executive Annual Incentive ~~Award~~ Plan (as amended and restated effective Feb. 17, 2010) ~~(incorporated by reference to Appendix A to Schedule 14A,~~	Xcel Energy Inc. Definitive Proxy Statement ~~to Xcel Energy (file no. 001-03034)~~ dated April 6, ~~2010).~~2010	001-03034	Schedule 14A
10.09*+	Xcel Energy Inc. 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) ~~(incorporated by reference to Appendix B to Schedule 14A,~~	Xcel Energy Inc. Definitive Proxy Statement ~~to Xcel Energy (file no. 001-03034)~~ dated April 6, ~~2010).~~2010	001-03034	Schedule 14A
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 Inc. Definitive Proxy Statement ~~(file no. 001-03034) filed Apr.~~dated April 5, ~~2011).~~2011	001-03034	Schedule 14A
10.11*+	Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) ~~(Exhibit 10.07 to~~	Xcel Energy Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2008).~~2008	001-03034	10.07
10.12*+	Second Amendment to Exhibit 10.02 dated Oct. 26, 2011 ~~to the~~	Xcel Energy ~~Senior Executive Severance and Change-in-Control Policy (Exhibit 10.18 to~~Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2011).~~2011	001-03034	10.18
10.13*+	First Amendment to Exhibit 10.11 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).~~2011	001-03034	10.17
10.14*+	First Amendment to Exhibit 10.08 dated Feb. 20, 2013 ~~to the~~	Xcel Energy Inc. ~~Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.01 to~~ Form 10-Q ~~of Xcel Energy (file no. 001-03034)~~ for the quarter ended March 31, ~~2013).~~2013	001-03034	10.01
10.15*+	Fourth Amendment to Exhibit 10.02 dated Feb. 20, 2013 ~~to the~~	Xcel Energy ~~Senior Executive Severance and Change-in-Control Policy (Exhibit 10.02 to~~Inc. Form 10-Q ~~of Xcel Energy (file no. 001-03034)~~ for the quarter ended March 31, ~~2013).~~2013	001-03034	10.02
10.16*+	First Amendment to Exhibit 10.09 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).~~2013	001-03034	10.21
10.17*+	Second Amendment to Exhibit 10.11 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).~~2013	001-03034	10.22
10.18*+	Xcel Energy Inc. 2005 Long-Term Incentive Plan Form of Long-Term Incentive Award Agreement ~~(Exhibit 10.23 to~~	Xcel Energy Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2013).~~


2013	001-03034	10.23
10.19*+	Xcel Energy Inc. 2015 Omnibus Incentive Plan ~~(incorporated by reference to Appendix B to Schedule 14A,~~	Xcel Energy Inc. Definitive Proxy Statement ~~to Xcel Energy Inc. (file no. 001-03034)~~ dated April 6, ~~2015).~~2015	001-03034	Schedule 14A
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~~Plan	Xcel Energy Inc. Form 8-K ~~of Xcel Energy,~~ dated May ~~26,~~20, 2015 ~~(file no. 001-03034).~~	001-03034	10.02
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~~Plan	Xcel Energy Inc. Form 8-K ~~of Xcel Energy,~~ dated May ~~26,~~20, 2015 ~~(file no. 001-03034).~~	001-03034	10.03
10.22*+	Xcel Energy Inc. 2015 Omnibus Incentive Plan Form of Award ~~Agreement. (Exhibit 10.28 to~~Agreement	Xcel Energy inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2015).~~2015	001-03034	10.28
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~~Plan	Xcel Energy inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2015).~~2015	001-03034	10.29
10.24*+	Fifth Amendment Exhibit 10.02 dated May 3, 2016 ~~to the~~	Xcel Energy ~~Senior Executive Severance and Change-in-Control Policy (Exhibit 10.01 to~~Inc. Form 10-Q ~~of Xcel Energy (file no. 001-03034)~~ for the quarter ended June 30, ~~2016).~~2016	001-03034	10.01
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~~Agents	Xcel Energy Inc. Form 8-K ~~of Xcel Energy~~ dated June 20, 2016 ~~(file no. 001-03034)).~~	001-03034	99.04
10.26*+	Third Amendment to Exhibit 10.11 dated Sept. 30, 2016 ~~to the~~	Xcel Energy ~~Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.01 to~~inc. Form 10-Q ~~of Xcel Energy (file no. 001-03034)~~ for the quarter ended Sept. 30, ~~2016).~~2016	001-03034	10.01
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.~~inc. 2015 Omnibus Incentive ~~Plan. (Exhibit 10.27 to~~Plan	Xcel Energy Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2016).~~2016	001-03034	10.27
10.28*+	Fourth Amendment to ~~the~~ Exhibit 10.11 dated Oct. 23, 2017	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)).~~	001-03034	10.1
10.29*+	Sixth Amendment to Exhibit 10.02 dated Feb. 22, 2018 to	Xcel Energy ~~Senior Executive Severance and Change-in-Control Policy (Exhibit 10.30 to~~Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2017.~~2017	001-03034	10.30



~~12.01~~10.30*+	~~Statement~~Seventh Amendment to Exhibit 10.02 dated May 7, 2018	Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018	001-03034	10.01
10.31*+	Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	001-03034	10.34
10.32*+	Form of ~~Computation~~Xcel Energy Inc. 2015 Omnibus Incentive Plan Award Agreement Terms and Conditions under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	001-03034	10.35
10.33*+	Stock Program for Non-Employee Directors of ~~Ratio of Earnings to Fixed Charges.~~Xcel Energy Inc. as Amended and Restated on Dec. 12, 2017 under the 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	001-03034	10.36
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~~2018 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)~~(vii) document and entity information, and ~~(ix)~~(viii) Schedule II.

SCHEDULE II

SOUTHWESTERN PUBLIC SERVICE CO.

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DEC. 31, 2018, 2017 ~~2016~~ AND ~~2015~~

~~(amounts in thousands)~~2016

Additions

Balance at
Jan. 1

Charged to
Costs and
Expenses

Charged to
Other
Accounts^(a)

Deductions
from
Reserves ^(b)

Balance at
Dec. 31
Allowance for bad debts:
2017 $ 6,379
$ 5,091
$ 1,169
$ 6,291
$ 6,348
2016 5,888
6,066
907
6,482
6,379
2015 5,839
4,655
1,036
5,642
5,888



	Allowance for bad debts
(Millions of Dollars)	2018			2017			2016
Balance at Jan. 1	$	6.4		$	6.4		$	5.9
Additions Charged to Costs and Expenses	4.9			5.1			6.1
Additions Charged to Other Accounts ^(a)	1.0			1.2			0.9
Deductions from Reserves ^(b)	(6.7		)	(6.3		)	(6.5		)
Balance at Dec. 31	$	5.6		$	6.4		$	6.4


^(a)	Recovery of amounts previously written off.


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

Item 16 — Form 10-K Summary

None.

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~~22, 2019		/s/ ROBERT C. FRENZEL
		Robert C. Frenzel
		Executive Vice President, Chief Financial Officer and Director
		(Principal Financial Officer)

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



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

/s/ ROBERT C. FRENZEL		/s/ JEFFREY S. SAVAGE
Robert C. Frenzel		Jeffrey S. Savage
Executive Vice President, Chief Financial Officer and Director		Senior Vice President, Controller
(Principal Financial Officer)		(Principal Accounting Officer)

/s/ ~~MARVIN E. MCDANIEL, JR.~~DAVID L. EVES
~~Marvin E. McDaniel, Jr.~~David L. Eves
Executive Vice President and Director

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

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

7544



	Coal				Natural Gas				Weighted Average Owned Fuel Cost
SPS Generating Plants	Cost		Percent		Cost		Percent		Weighted Average Owned Fuel Cost
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



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



(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



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



	One-Percentage Point
(Thousands of Dollars)	Increase		Decrease
APBO	$	4,559	$	(3,858	)
Service and interest components	266		(225		)



Revenue Request (Millions of Dollars)
Incremental revenue request	$	69
TCRF revenue conversion to base rates ^(a)	(14		)
Net revenue increase request	$	55



(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



(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



	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	)



	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	)



			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

Debt-to-Total Capitalization Ratio^(a)

Amount Facility May Be Increased (millions)

Additional Periods For Which a One-Year Extension May Be Requested ^(b)