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, ~~2016~~2019



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

~~Commission file number: 001-03789~~

~~SOUTHWESTERN PUBLIC SERVICE COMPANY~~

001-03789

(Commission File Number)

SOUTHWESTERN PUBLIC SERVICE COMPANY

(Exact name of registrant as specified in its charter)



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



~~New Mexico~~790 South Buchanan Street,	Amarillo,	Texas		~~75-0575400~~	79101
~~State or other jurisdiction~~ (Address of ~~incorporation or organization~~Principal Executive Offices)					(~~I.R.S. Employer Identification No.)~~Zip Code)
			(303)	571-7511
(Registrant’s Telephone Number, Including Area Code)

~~Tyler at Sixth, Amarillo, Texas 79101~~

~~(Address of principal executive offices)~~

~~Registrant’s telephone number, including area code:~~ ~~303-571-7511~~

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



Title of each class	Trading Symbol	Name of each exchange on which registered
N/A	N/A	N/A

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

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 1313 or Section 15(d) of the Act. ¨☐ Yes x☒No

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

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate Website, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 ~~and~~of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit ~~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, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated ~~filer,”~~filer”, “accelerated filer”, “smaller reporting company”, and ~~“smaller reporting~~“emerging growth company” in Rule 12b-2 of the Exchange ~~Act~~Act. ☐ Large accelerated Filer ☐ Accelerated Filer ☒Non-accelerated Filer☐ Smaller Reporting Company ☐ Emerging Growth Company

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



~~Large accelerated filer~~ ¨		~~Accelerated filer~~ ¨
~~Non-accelerated filer~~ x		~~Smaller Reporting Company~~ ¨
~~(Do not check if a smaller reporting company)~~

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. ~~24, 2017~~21, 2020, 100 shares of common stock, par value $1$1.00 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm – Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the ~~2017~~2020 Annual Meeting of ~~Stockholders~~Shareholders which definitive Proxy Statement is expected to be filed with the SEC on or about April ~~4, 2017.~~6, 2020. Such information set forth under such heading is incorporated herein by this reference hereto.

Southwestern Public Service Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).

TABLE OF CONTENTS

~~Index~~



PART I	3
Item 1 —	Business	3
	~~DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS~~Definition of Abbreviations	3
	~~COMPANY OVERVIEW~~Forward-Looking Statements	54
	~~ELECTRIC UTILITY OPERATIONS~~Where To Find More Information	54
	~~Public Utility Regulation~~Company Overview	54
	~~Capacity and Demand~~Electric Operations	4
	Public Utility Regulation	6
~~Energy Sources and Related Transmission Initiatives~~	6
~~Fuel Supply and Costs~~General	7
	~~Fuel Sources~~Environmental	7
	~~Renewable Energy Sources~~Employees	8
Item 1A —	~~Wholesale Commodity Marketing Operations~~Risk Factors	8
Item 1B —	~~Summary of Recent Federal Regulatory Developments~~Unresolved Staff Comments	913
Item 2 —	~~Electric Operating Statistics~~Properties	1013
Item 3 —	~~Natural Gas Facilities Used for Electric Generation~~Legal Proceedings	1113
Item 4 —	~~GENERAL~~Mine Safety Disclosures	1113
~~ENVIRONMENTAL MATTERS~~	12
~~EMPLOYEES~~	12
~~Item 1A — Risk Factors~~	12
~~Item 1B — Unresolved Staff Comments~~	21
~~Item 2 — Properties~~	22
~~Item 3 — Legal Proceedings~~	22
~~Item 4 — Mine Safety Disclosures~~	22

PART II		2313
Item 5 —	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	2313
Item 6 —	Selected Financial Data	2313
Item 7 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2313
Item 7A —	Quantitative and Qualitative Disclosures About Market Risk	2516
Item 8 —	Financial Statements and Supplementary Data	2716
Item 9 —	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	7141
Item 9A —	Controls and Procedures	7141
Item 9B —	Other Information	7241

PART III		7242
Item 10 —	Directors, Executive Officers and Corporate Governance	7242
Item 11 —	Executive Compensation	7242
Item 12 —	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	7242
Item 13 —	Certain Relationships and Related Transactions, and Director Independence	7242
Item 14 —	Principal Accountant Fees and Services	7242

PART IV		7342
Item 15 —	Exhibits, Financial Statement Schedules	7342
Item 16 —	Form 10-K Summary	44

~~SIGNATURES~~Signatures		7745

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

PART I

~~Item l~~ — ~~Business~~

ITEM l — BUSINESS

~~DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS~~Definitions of Abbreviations



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
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
RPS	Renewable portfolio standards
TCRF	Transmission cost recovery factor (recovers transmission infrastructure improvement costs and changes in wholesale transmission charges)



Other ~~Terms and Abbreviations~~
ADIT	Accumulated deferred income taxes
AFUDC	Allowance for funds used during construction
ALJ	Administrative ~~law judge~~
~~APBO~~	~~Accumulated postretirement benefit obligation~~Law Judge
ARO	Asset retirement obligation
ASC	FASB Accounting Standards Codification
ASU	FASB Accounting Standards Update
BART	Best available retrofit technology
~~CAA~~CEO	~~Clean Air Act~~Chief executive officer
~~CAIR~~CFO	~~Clean Air Interstate Rule~~Chief financial officer
C&I	Commercial and Industrial
CO₂ Corps	~~Carbon dioxide~~
~~CCN~~	~~Certificate~~U.S. Army Corps of ~~convenience and necessity~~
~~CPP~~	~~Clean Power Plan~~
~~CSAPR~~	~~Cross-State Air Pollution Rule~~Engineers
CWIP	Construction work in progress
~~EGU~~DSM	~~Electric generating unit~~Demand side management
~~ERCOT~~ELG	~~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~~producing entity
IRP	Integrated Resource Plan



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~~
~~PJM~~	~~PJM Interconnection, LLC~~
PM	~~Particulate matter~~Open Access Transmission Tariff
PPA	Purchased power agreement
PRP	Potentially responsible party
PTC	Production tax credit
PV	~~Photovoltaic~~
QF	~~Qualifying facilities~~
~~R&E~~	~~Research and experimentation~~
REC	Renewable energy credit
ROE	Return on equity
~~RPS~~ROFR	~~Renewable portfolio standards~~Right-of-first-refusal
ROU	Right-of-use
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

~~COMPANY OVERVIEW~~

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2019 (including risk factors listed from time to time by SPS in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K hereto), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: operational safety; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee work force and third-party contractor factors; ability to recover costs, changes in regulation and subsidiaries’ ability to recover costs from customers; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of SPS to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; our subsidiaries’ ability to make dividend payments; tax laws; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; and costs of potential regulatory penalties.

~~SPS was incorporated in 1921 under the laws of New Mexico.~~

Where to Find More Information

SPS is a ~~utility engaged primarily in~~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 ~~generation, purchase, transmission, distribution,~~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 ~~sale of electricity in portions of Texas~~information statements, and ~~New Mexico. The wholesale customers served by~~ other information regarding issuers that file electronically at http://www.sec.gov.

Company Overview






Electric customers	0.4 million	SPS was incorporated in 1921 under the laws of New Mexico. SPS conducts business in Texas and New Mexico and generates, purchases, transmits, distributes and sells electricity.
Total assets	$7.9 billion
Rate base	$4.9 billion
ROE	9.71%
Electric generating capacity	4,804 MW
Electric transmission lines (conductor miles)	38,418 miles
Electric distribution lines (conductor miles)	21,810 miles

Electric Operations

SPS comprised approximately 31 percent of its total KWh sold in 2016. SPS provides electric utility service to approximately 389,000 retail customers in Texas and New Mexico. Approximately 71 percent of SPS’ retail electric operating revenues were derived from operations in Texas during 2016 and 2015. Although SPS’ large C&I electric retail customers are comprised of many diversified industries, a significant portion of SPS’ large C&Ihad electric sales ~~include~~volume of 30,894 (millions of KWh), 395,828 customers and electric revenues of $1,825.8 (millions of dollars) for 2019.

Sales/Revenue Statistics



	2019			2018
KWH sales per retail customer	53,123			52,074
Revenue per retail customer	$3,147			$3,124
Residential revenue per KWh		10.04	¢		9.92	¢
Large C&I revenue per KWh		4.01	¢		4.08	¢
Small C&I revenue per KWh		7.17	¢		7.22	¢
Total retail revenue per KWh		5.92	¢		6.00	¢

Owned and Purchased Energy Generation — 2019

Electric Energy Sources

Total electric generation by source (including energy market purchases) for the ~~following industries: oil~~year ended Dec. 31, 2019:

*Distributed generation from the Solar*Rewards^® program is not included (approximately 12.9 million KWh for 2019).

Renewable Energy Sources

SPS’ renewable energy portfolio includes wind and ~~gas extraction,~~solar power from both owned generating facilities and PPAs. Renewable percentages will vary year over year based on system additions, weather, system demand and transmission constraints.

See Item 2 — Properties for further information.

Renewable energy as ~~well as petroleum~~a percentage of total energy for 2019:


^(a)	Includes biomass and hydroelectric.

Wind Energy Sources

Owned — Owned and operated wind farms with corresponding capacity:

PPAs — Number of PPAs with range:

Capacity — Wind capacity:



2019		2018
2,045 MW		1,565 MW

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



2019		2018
$25		$26

Wind Energy Development

SPS placed approximately 460 MW of wind into service during 2019:



Project		Capacity
Hale		460 MW

SPS currently has approximately 522 MW of wind under development or construction with an estimated completion date of 2020:



Project	Capacity	Estimated Completion
Sagamore	522 MW	2020

Solar Energy Sources

Solar energy PPAs:



Type		Capacity
Distributed Generation		10 MW
Utility-Scale		191 MW

Fossil Fuel Energy Sources

SPS’ fossil fuel energy portfolio includes coal and natural gas ~~products. For small C&I customers, significant~~power from both owned generating facilities and PPAs.

See Item 2 — Properties for further information.

Coal Energy Sources

SPS has two coal plants with approximately 2,100 MW of total 2019 net summer dependable capacity.

SPS plans to continue to evaluate its coal fleet for other potential early coal plant retirements as part of state resource plans or other regulatory proceedings.

Coal Fuel Cost

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



	Coal
	Cost		Percent
2019	$	2.19	45	%
2018	2.04		56

Natural Gas Energy Sources

SPS has eight natural gas plants with approximately 2,300 MW of total 2019 net summer dependable capacity.

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

Natural Gas Cost

Delivered cost per MMBtu of natural gas consumed for owned electric generation and ~~gas extraction, grocery and dining establishments. Generally, SPS’ earnings contribute approximately 10 percent to 15 percent~~percentage of ~~Xcel Energy’s consolidated net income.~~total fuel requirements:



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

~~ELECTRIC UTILITY OPERATIONS~~

~~Public Utility Regulation~~

~~Summary of Regulatory Agencies and Areas of Jurisdiction~~ — The PUCT and NMPRC regulate SPS’ retail electric operations and have jurisdiction over its retail rates and services and the construction of transmission or generation in their respective states. The municipalities in which SPS operates in Texas have original jurisdiction over SPS’ rates in those communities. Each municipality can deny SPS’ rate increases. SPS can then appeal municipal rate decisions to the PUCT, which hears all municipal rate denials in one hearing. The NMPRC also has jurisdiction over the issuance of securities. SPS is regulated by the FERC with respect to 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 operates within the SPP RTO and SPP integrated market 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 certain distribution costs in Texas that are not included in base rates.~~

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

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

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

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

~~RPS~~ ~~— Recovers deferred costs associated with renewable energy programs in New Mexico.~~

~~TCRF~~ ~~— Recovers certain transmission infrastructure improvement costs and changes in wholesale transmission charges in Texas that are not included in base rates.~~

~~Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor, which is part of SPS’ retail electric tariff. 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 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 reconciles fuel and purchased power costs for 2013 through 2015. In February 2017, an unopposed stipulation was reached which resolves all issues in this case. The stipulation is pending PUCT approval, which is expected in the first half of 2017.

Each New Mexico utility operating with a FPPCAC must periodically file an application for continued use. In October 2015, the NMPRC granted SPS authority to continue using its FPPCAC to collect its fuel and purchase power costs. SPS will be required to file a request for continuation of its FPPCAC by October 2019.

~~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~~Renewable Energy Sources

SPS’ renewable energy portfolio includes wind and ~~Demand~~solar power from both owned generating facilities and PPAs. Renewable percentages will vary year over year based on system additions, weather, system demand and transmission constraints.

See Item 2 — Properties for further information.

~~Uninterrupted system peak demand~~

Renewable energy as a percentage of total energy for ~~SPS for each of the last three years~~2019:


^(a)	Includes biomass and hydroelectric.

Wind Energy Sources

Owned — Owned and ~~the forecast for 2017, assuming normal weather conditions, is as follows:~~operated wind farms with corresponding capacity:

System Peak Demand (in MW)
2014 2015 2016 2017 Forecast
SPS 4,871
4,678
4,836
4,484

PPAs — Number of PPAs with range:

Capacity — Wind capacity:



2019		2018
2,045 MW		1,565 MW

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



2019		2018
$25		$26

Wind Energy Development

SPS placed approximately 460 MW of wind into service during 2019:



Project		Capacity
Hale		460 MW

SPS currently has approximately 522 MW of wind under development or construction with an estimated completion date of 2020:



Project	Capacity	Estimated Completion
Sagamore	522 MW	2020

Solar Energy Sources

Solar energy PPAs:



Type		Capacity
Distributed Generation		10 MW
Utility-Scale		191 MW

~~The peak demand~~

Fossil Fuel Energy Sources

SPS’ fossil fuel energy portfolio includes coal and natural gas power from both owned generating facilities and PPAs.

See Item 2 — Properties for the SPS system typically occurs in the summer. The 2016 system peak demand for SPS occurred on July 13, 2016. The 2016 peak demand increased due to warmer than normal July summer weather. The 2017 forecast assumes normal peak day weather. In addition, the partial requirement contract with Golden Spread ends May 2017, causing a lower 2017 forecast peak demand for SPS.further information.

Coal Energy Sources ~~and Related Transmission Initiatives~~

SPS ~~expects~~has two coal plants with approximately 2,100 MW of total 2019 net summer dependable capacity.

SPS plans to ~~use existing electric generating stations, power purchases, DSM and new generation options to meet its system capacity requirements.~~

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

~~Purchased Transmission Services~~ ~~— SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers.~~

~~High Priority Incremental Load Study Report~~ — In 2014, the SPP Board of Directors approved the High Priority Incremental Load Study Report, a reliability assessment that evaluated the anticipated transmission needs of certain parts of the SPP region resulting from expected load growth. As a result of this study, SPS has received NTCs and conditional NTCs for 44 new transmission projects at an estimated cost of approximately $557 million to be placed into service by 2020. As of Dec. 31, 2016, 16 of these projects have been completed at an original estimated cost of $88 million. SPS is developing plans for the remaining 28 projects and submitting CCNs to the PUCT and the NMPRC. The original estimated cost for these remaining projects is $469 million. These projects are intended to provide regional reliability benefits as well as the ability to serve the increase in load in southeastern New Mexico.

~~TUCO Substation to Yoakum County Substation to Hobbs Plant Substation 345 KV Transmission Line~~— In March 2016, the PUCT approved SPS’ CCN for the 33-mile Yoakum County to Texas/New Mexico State line portion of this 345 KV line project. A CCN for the 111-mile TUCO to Yoakum County substation segment was filed in June 2016. Assuming approval of this CCN, this segment is scheduled to be in service in 2019. A 36-mile CCN for the Texas/New Mexico state line to Hobbs Plant segment is planned to be filed later in the first quarter of 2017. The estimated project cost for all three segments is approximately $242 million.

~~Hobbs Plant Substation to China Draw Substation 345 KV Transmission Line —~~ In November 2016, the NMPRC approved SPS’ CCN for the Hobbs Plant to China Draw transmission line. The estimated project cost is approximately $163 million. The line is anticipated to be in service in 2018.

~~SPS Resource Plans —~~ SPS was required to develop and implement a renewable portfolio plan by 2015, in which 15 percent of its energy to serve its New Mexico retail customers is produced by renewable resources. The requirement was met through PPAs, including wind, solar and distributed generation. In 2020, the renewable resource production requirement increases to 20 percent. In addition, SPS indicated that it was evaluating water supply issues at its Tolk facility and if additional investment is required to operate the plant through its existing life. The Ogallala aquifer in this region of the country has depleted more rapidly than expected and SPS is currently seeking a permit for a horizontal well configuration pilot program that could help to delay the need for a more substantial investment solution. As a result of this issue and environmental issues currently facing the plant, SPS is seeking a decrease to the remaining useful life of the facility in its current New Mexico rate case proceeding (see Note 10).

~~Wholesale Customer Participation in ERCOT —~~ In March 2016, the PUCT Staff requested comments on Lubbock Power & Light’s (LP&L’s) proposal to transition a portion of its load (approximately 430 MW on a peak basis) to the ERCOT in June 2019. LP&L’s proposal would result in an approximate seven percent reduction of load in SPS, or a loss of approximately $18 million in wholesale transmission revenue. The remaining portion of LP&L’s load (approximately 170 MW) would continue to ~~be served by SPS. Should LP&L join ERCOT, costs to SPS’ remaining customers would increase~~evaluate its coal fleet for other potential early coal plant retirements as ~~SPS’ transmission costs would be spread across a smaller base~~part of ~~customers.~~ state resource plans or other regulatory proceedings.

Coal Fuel Cost

The PUCT has indicated there will be a two-step process regarding LP&L’s possible transfer to ERCOT. The first step will be a proceeding to determine whether the proposed transfer is in the public interest and to consider certain protections for non-LP&L customers who would be affected by LP&L’s transfer. If the PUCT determines the transfer is in the public interest, the second step will be for LP&L to file a CCN application for transmission facilities to connect with ERCOT. The PUCT asked SPP and ERCOT to perform reliability and economic studies to better understand the implications of LP&L’s proposal. SPS intends to participate in the PUCT’s processes to protect its customers’ interests.

In May 2016, SPS submitted a filing to the FERC seeking approval to impose an Interconnection Switching Fee (exit fee) associated with LP&L’s proposal. In September 2016, FERC dismissed SPS’ petition without prejudice to refile, finding the petition premature since LP&L has not made a final decision to move to ERCOT and the terms of the transition have not been determined.

~~Fuel Supply and Costs~~

~~The following table shows the delivered~~Delivered cost per MMBtu of ~~each significant category of fuel~~coal consumed for owned electric generation ~~the~~and percentage of total fuel ~~requirements represented by each category of fuel and the total weighted average cost of all fuels.~~requirements:

Coal Natural Gas
Weighted Average
Owned Fuel Cost
SPS Generating Plants Cost Percent Cost Percent
2016 $ 2.12
70 % $ 2.81
30 % $ 2.32
2015 2.12
73
3.11
27
2.39
2014 2.07
71
4.76
29
2.85



	Coal
	Cost		Percent
2019	$	2.19	45	%
2018	2.04		56

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

~~Fuel~~Natural Gas Energy Sources

~~Coal~~—SPS purchases all of the coal requirements for its two coal facilities, Harrington and Tolk electric generating stations, from TUCO. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers. The coal supply contract with TUCO expires in December 2017 for both Harrington and Tolk. SPS normally maintains approximately 43 days of coal inventory. As of Dec. 31, 2016 and 2015, coal inventories at SPS were approximately 64 and 76 days supply, respectively. At Dec. 31, 2016, milder weather, purchase commitments and relatively lowhas eight natural gas prices resulted in coal inventories being above optimal levels. SPS’ generation stations primarily use low-sulfur western coal from mines operating in Wyoming. TUCO has coal agreements to supply 65 percentplants with approximately 2,300 MW of ~~SPS’ estimated coal requirements in 2017. SPS’ general coal purchasing objective is to contract for approximately 80 percent of requirements for the first year.~~total 2019 net summer dependable capacity.

~~Natural gas~~— ~~SPS uses both firm and interruptible natural gas supply and standby oil in combustion turbines and certain boilers.~~ Natural gas supplies, transportation and storage services for ~~SPS’~~ power plants isare procured ~~under contracts~~ to provide an adequate supply of ~~fuel; which typically is purchased with terms of one year or less. The transportation and storage contracts expire in various years from 2017 to 2033. All of the~~fuel. Remaining requirements are procured through a liquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to ~~various~~ natural gas indices.

~~Most transportation contract pricing is based on FERC and Railroad Commission of Texas approved transportation tariff rates. Certain natural~~ Natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes ~~of natural gas~~ or ~~to make~~ payments in lieu of delivery. ~~SPS’ commitments related to~~

Natural Gas Cost

Delivered cost per MMBtu of natural gas ~~supply contracts were approximately $17 million~~consumed for owned electric generation and ~~$10 million and commitments related to gas transportation and storage contracts were approximately $161 million and $192 million at Dec. 31, 2016 and 2015, respectively.~~percentage of total fuel requirements:

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



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

Renewable Energy Sources

SPS’ renewable energy portfolio includes wind and solar power from both owned generating facilities and PPAs. ~~As of Dec. 31, 2016, SPS is in compliance with mandated RPS, which require generation from renewable resources of 3.7 percent of Texas electric retail sales~~Renewable percentages will vary year over year based on system additions, weather, system demand and ~~15.0 percent of New Mexico electric retail sales.~~transmission constraints.

See Item 2 — Properties for further information.

•

Renewable energy ~~comprised 22.8 percent and 19.0 percent~~as a percentage of ~~SPS’~~ total energy for ~~2016~~2019:


^(a)	Includes biomass and hydroelectric.

Wind Energy Sources

Owned — Owned and ~~2015, respectively;~~operated wind farms with corresponding capacity:

•

PPAs — Number of PPAs with range:

Capacity — Wind ~~energy comprised 21.6 percent and 18.5 percent of the total energy for 2016 and 2015, respectively; and~~capacity:

•~~Solar power comprised approximately 1.2 percent and 0.5 percent of the total energy for 2016 and 2015, respectively.~~



2019		2018
2,045 MW		1,565 MW

~~SPS also offers customer-focused renewable energy initiatives. Windsource~~^® allows customers in New Mexico to purchase a portion or all of their electricity from renewable sources. The number of customers utilizing Windsource increased to approximately 900 in 2016 from 880 in 2015.

~~Additionally, to encourage the growth of solar energy on the system in New Mexico, customers are offered incentives to install solar panels on their homes and businesses under the Solar*Rewards~~^® program. Over 147 PV systems with approximately 8.1 MW of aggregate capacity and over 144 PV systems with approximately 8.0 MW of aggregate capacity have been installed in New Mexico under this program as of Dec. 31, 2016 and 2015, respectively.

~~Wind~~Average Cost (PPAs) — SPS acquires its wind energy from IPP contracts and QF tariffs with wind farm owners, primarily located in the Texas Panhandle area of Texas and New Mexico. SPS currently has 24 of these agreements in place, with facilities ranging in size from under two MW to 250 MW for a total capacity greater than 1,500 MW.

SPS had approximately 1,500 MW and 1,755 MW of wind energy on its system at the end of 2016 and 2015, respectively. This decrease is primarily due to the timing of supplier contracts expiring. In addition to receiving purchased wind energy under these agreements, SPS also typically receives wind RECs, which are used to meet state renewable resource requirements.

~~The average~~Average cost per MWh of wind energy under ~~the IPP contracts~~existing PPAs:



2019		2018
$25		$26

Wind Energy Development

SPS placed approximately 460 MW of wind into service during 2019:



Project		Capacity
Hale		460 MW

SPS currently has approximately 522 MW of wind under development or construction with an estimated completion date of 2020:



Project	Capacity	Estimated Completion
Sagamore	522 MW	2020

Solar Energy Sources

Solar energy PPAs:



Type		Capacity
Distributed Generation		10 MW
Utility-Scale		191 MW

Fossil Fuel Energy Sources

SPS’ fossil fuel energy portfolio includes coal and ~~QF tariffs was~~natural gas power from both owned generating facilities and PPAs.

See Item 2 — Properties for further information.

Coal Energy Sources

SPS has two coal plants with approximately ~~$25 and $24~~2,100 MW of total 2019 net summer dependable capacity.

SPS plans to continue to evaluate its coal fleet for ~~2016 and 2015, respectively. The~~other potential early coal plant retirements as part of state resource plans or other regulatory proceedings.

Coal Fuel Cost

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



	Coal
	Cost		Percent
2019	$	2.19	45	%
2018	2.04		56

Natural Gas Energy Sources

SPS has eight natural gas plants with approximately 2,300 MW of total 2019 net summer dependable capacity.

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

Natural Gas Cost

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



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

Capacity and Demand

Uninterrupted system peak demand and occurrence date:



System Peak Demand (in MW)
2019		2018
4,261	Aug. 5	4,648	July 19

Transmission

Transmission lines deliver electricity over long distances from power sources to transmission substations closer to homes and businesses. A strong transmission system ensures continued reliable and affordable service, ability to meet state and regional energy policy goals, and support a diverse generation mix, including renewable energy. SPS owns more than 38,400 conductor miles of transmission lines across its service territory.

During 2019, SPS completed the following transmission projects:



Project	Miles	Size
TUCO-Yoakum-Hobbs	64	345 KV
NEF-Cardinal	15	115 KV
Potash Junction-Livingston Ridge	15	115 KV
Mustang-Shell	9	115 KV
North Loving-South Loving	3	115 KV
Cunningham-Monument Tap	7	115 KV

Upcoming transmission projects:



Project	Miles	Size	Completion Date
TUCO-Yoakum-Hobbs	106	345 KV	2020
Eddy-Kiowa	34	345 KV	2020

Public Utility Regulation

Summary of Regulatory Agencies / RTO and Areas of Jurisdiction



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

Recovery Mechanisms



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

Resource Plan

In December 2018, the NMPRC issued a final order accepting SPS’ IRP.

SPS is forecasting a surplus capacity of 382 MW in 2028, but a capacity deficit of approximately 2,896 MW in 2038. SPS’ optimal resource plan for the planning period incorporates the addition of wind, simple cycle combustion turbine generation, combined cycle energy ~~varies by contract~~ and entering PPAs. Various factors may impact this IRP, which could potentially require updates to the action plan and will be ~~influenced by~~the subject of future IRPs, including:

New and revised environmental regulations;

Impacts of variability due to participation in the SPP;

Customer expectations;

Technological advances;

Groundwater aquifer depletion at SPS’ Tolk Station;

Aging generation fleet;

Load growth and gas price variability;

Changes to tax credits and incentives; and

Changes to renewable portfolio standard acquisitions.

SPS is required to file an IRP in New Mexico every three years and will file its next IRP in July 2021.

Purchased Power Arrangements and Transmission Service Providers

SPS expects to use electric generating stations, power purchases, DSM and new generation options to meet its system capacity requirements.

Purchased Power — SPS purchases power from other utilities and IPPs. Long-term purchased power contracts typically require periodic capacity and energy charges. SPS also makes short-term purchases to meet system load and energy requirements to replace owned generation, meet operating reserve obligations or obtain energy at a ~~number~~lower cost.

Purchased Transmission Services — SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers.

Natural Gas

SPS does not provide retail natural gas service, but purchases and transports natural gas for its generation facilities and operates natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines. SPS is subject to the jurisdiction of ~~factors including regulation, state-specific renewable resource requirements~~the FERC with respect to natural gas transactions in interstate commerce and the ~~year of contract execution. Generally, contracts executed in 2016 continued to benefit from improvements in technology, excess capacity among manufacturers,~~PHMSA and ~~motivation to commence new construction prior to the anticipated expiration of the federal PTCs. In December 2016, the federal PTCs were extended through 2019 with a phase down beginning in 2017.~~

PUCT for pipeline safety compliance.

Wholesale and Commodity Marketing Operations

SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. SPS uses physical and financial instruments to minimize commodity price and credit risk and to hedge sales and purchases. ~~See Item 7 for further discussion.~~

~~Summary of Recent Federal Regulatory Developments~~

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, asset transactions and mergers, accounting practices and certain other activities of SPS, including enforcement of NERC mandatory electric reliability standards. State and local agencies have jurisdiction over many of SPS’ activities, including regulation of retail rates and environmental matters. In addition to the matters discussed below, see Note 10 to the accompanying financial statements for a discussion of other regulatory matters.

~~Status of FERC Commissioners~~ — The FERC is comprised of five commissioners appointed by the President and subject to confirmation by the Senate. There are today only two sitting commissioners. It is uncertain when the President will appoint new commissioners to the open seats or when those appointments may be confirmed. Without three sitting commissioners, the FERC will not have a quorum to act on contested matters. The lack of a quorum could affect the timing of FERC decisions on proposed rules or pending, newly submitted and future filings involving, among other things, contested electric rate matters and CCNs for construction of interstate natural gas pipeline facilities.

~~NERC Critical Infrastructure Protection Requirements~~ — The FERC has approved Version 5 of NERC’s critical infrastructure protection standards, which added additional requirements to strengthen grid security controls. SPS applied the requirements to high and medium impact assets by the July 1, 2016 deadline. Requirements must be applied to low impact assets through a staggered implementation beginning April 1, 2017 through September 2018. SPS is currently in the process of implementing initiatives to meet the compliance deadline. The additional cost for compliance is anticipated to be recoverable through rates.

~~NERC Physical Security Requirements~~ — In 2014, the FERC approved NERC’s proposed critical infrastructure protection standard related to physical security for bulk electric system facilities. The new standard became enforceable in October 2015 with staggered milestone deliverable dates through 2016. SPS has developed physical security plans in accordance with the requirements of the standard. The additional cost for compliance is anticipated to be recoverable through rates.

~~Formula Rate Treatment of Accumulated Deferred Income Taxes (ADIT)~~ — In 2015, SPS filed changes to its transmission formula rate to comply with IRS guidance regarding how ADIT must be reflected in formula rates using future test years and a true-up. The filing was intended to ensure that SPS is in compliance with IRS rules and may continue to use accelerated tax depreciation. SPS requested a Jan. 1, 2016 effective date.

In April 2016, the FERC accepted SPS’ formula rate change, subject to a compliance filing. In August 2016, the FERC approved SPS’ compliance filing. SPS believes its wholesale formula rates are in compliance with the IRS ADIT rules.

~~Electric Operating Statistics~~

~~Electric Sales Statistics~~

Year Ended Dec. 31
2016 2015 2014
Electric sales (Millions of KWh)
Residential 3,478
3,536
3,549
Large C&I 10,518
10,334
10,262
Small C&I 4,708
4,719
4,741
Public authorities and other 555
538
556
Total retail 19,259
19,127
19,108
Sales for resale 8,689
8,694
8,563
Total energy sold 27,948
27,821
27,671

Number of customers at end of period
Residential 305,076
304,711
302,922
Large C&I 219
221
214
Small C&I 77,319
77,238
76,553
Public authorities and other 6,377
6,354
6,323
Total retail 388,991
388,524

386,012
Wholesale 8
8
7
Total customers 388,999
388,532

386,019

Electric revenues (Thousands of Dollars)
Residential $ 343,475
$ 347,966
$ 363,841
Large C&I 462,576
445,853
516,648
Small C&I 322,599
353,450
379,558
Public authorities and other 44,892
42,963
46,916
Total retail 1,173,542
1,190,232
1,306,963
Wholesale 414,815
409,956
493,127
Other electric revenues 262,602
187,030
137,280
Total electric revenues $ 1,850,959
$ 1,787,218
$ 1,937,370

KWh sales per retail customer 49,510
49,230
49,501
Revenue per retail customer $ 3,017
$ 3,063
$ 3,386
Residential revenue per KWh
9.88 ¢
9.84 ¢
10.25 ¢
Large C&I revenue per KWh 4.40
4.31
5.03
Small C&I revenue per KWh 6.85
7.49
8.01
Total retail revenue per KWh 6.09
6.22
6.84
Wholesale revenue per KWh 4.77
4.72
5.76

~~Energy Source Statistics~~

Year Ended Dec. 31
2016 2015 2014

Millions of
KWh

Percent of
Generation

Millions of
KWh

Percent of
Generation

Millions of
KWh

Percent of
Generation
Coal 10,990
39 % 12,441
44 % 12,770
48 %
Natural Gas 10,909
38
10,514
36
10,068
37
Wind ^(a)
6,120
22
5,252
19
3,762
14
Other ^(b)
347
1
150
1
180
1
Total 28,366
100 % 28,357
100 % 26,780
100 %

Owned generation 15,015
53 % 16,480
58 % 16,956
63 %
Purchased generation 13,351
47
11,877
42
9,824
37
Total 28,366
100 % 28,357
100 % 26,780
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 14, 13 and 10 million net KWh for 2016, 2015, and 2014, respectively.~~ General

~~Natural Gas Facilities Used for Electric Generation~~

SPS does not provide retail natural gas service, but purchases and transports natural gas for certain of its generation facilities and operates natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines. SPS is subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce; and to the jurisdiction of the PHMSA and the PUCT for pipeline safety compliance.

~~GENERAL~~

Seasonality

~~The 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.~~

Competition

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

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

Several states ~~including New Mexico,~~ have ~~policies designed to promote~~incentives for the development of rooftop solar, community solar gardens and other distributed energy ~~resources through significant incentive policies; with these incentives and federal tax subsidies, distributed~~resources. Distributed generating resources are potential competitors to SPS’ electric service ~~business.~~

business with these incentives and federal tax subsidies.

The FERC has continued to promote competitive wholesale markets through open access transmission and other means. ~~As a result, SPS~~SPS’ wholesale customers can purchase their output from generation resources ~~from~~of competing ~~wholesale~~ suppliers or non-contracted quantities and use the transmission systems of Xcel Energy Inc.’s utility subsidiaries on a comparable basis to serve their native load. State public utilities commissions, including the NMPRC, have created resource planning programs that promote competition in the acquisition of electricity generation resources used to provide service to retail customers. In addition,

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

SPS has franchise agreements with ~~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. No municipalization activities are occurring presently.

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

available.

~~ENVIRONMENTAL MATTERS~~

Environmental

~~SPS’~~Environmental Regulation

Our facilities are regulated by federal and state environmental ~~agencies. These~~ agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. SPS has received ~~all~~ necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. ~~SPS’~~

Our facilities have been designed and constructed to operate in compliance with applicable environmental ~~standards.~~standards and related monitoring and reporting requirements. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or what effect future laws or regulations may ~~have upon SPS’ operations. See Notes 10~~have.

We may be required to incur capital expenditures in the future for remediation of MGP and ~~11 to the financial statements for further discussion.~~

other sites if it is determined that prior compliance efforts are not sufficient.

There are significant present and future environmental regulations to encourage ~~the~~ use of clean energy technologies and regulate emissions of ~~GHGs to address climate change.~~GHGs. SPS has undertaken ~~a number 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~~take into consideration investments ~~we have~~ already made ~~to reduce GHG emissions,~~ or if ~~they require~~ additional initiatives or emission reductions ~~then their requirements would~~are required, substantial costs may be incurred.

In July 2019, the EPA adopted the Affordable Clean Energy rule, which requires states to develop plans for GHG reductions from coal-fired power plants. The state plans, due to the EPA in July 2022, will evaluate and potentially ~~impose~~require heat rate improvements at existing coal-fired plants. It is not yet known how these state plans will affect SPS’ existing coal plants, but they could require substantial additional ~~substantial costs.~~investment, even in plants slated for retirement. SPS believes, based on prior state commission practice, ~~it would recover~~ the cost of these initiatives or replacement generation would be recoverable through rates.

SPS seeks to address climate change and potential climate change regulation through efforts to reduce its GHG emissions in a balanced, cost-effective manner.

~~EMPLOYEES~~

Employees

As of Dec. 31, ~~2016,~~2019, SPS had ~~1,237~~1,158 full-time employees and ~~one~~no part-time ~~employee,~~employees, of which ~~833~~779 were covered under collective-bargaining agreements. ~~See Note 7 to the financial statements for further discussion.~~

~~Item 1A — Risk Factors~~

ITEM 1A — RISK FACTORS

Xcel Energy, which includes SPS, is subject to a variety of risks, many of which are beyond our control. ~~Important 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~~The Board of Directors is responsible for the oversight of material risk and ~~our~~maintaining an effective risk monitoring process. Management and the Board of Directors ~~employs an effective process for doing so. Management and each Board of Directors’ committee has~~have responsibility for overseeing the identification and mitigation of key risks.

At a threshold level, SPS maintains a robust compliance program through promoting a culture of compliance beginning with the tone at the top. The risk mitigation process includes adherence to our code of conduct and compliance policies, operation of formal risk management structures and overall business management. SPS further mitigates inherent risks through formal risk committees and corporate functions such as internal audit, and internal controls over financial reporting ~~its assessments~~ and ~~activities to the full Board of Directors.~~

legal.

Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. ~~Management broadly considers our business, the utility industry, the domestic~~Identification and ~~global economies and the environment when identifying, assessing, managing and mitigating risk. Identification and~~risk analysis occurs formally through ~~a key~~ risk assessment ~~process~~ conducted by senior management, the financial disclosure process, ~~the~~ hazard risk ~~management process and~~procedures, internal ~~auditing~~audit and compliance with financial and operational controls.

Management also identifies and analyzes risk through ~~its~~the business planning process, ~~and~~ development of goals and establishment of key performance indicators, ~~which include risk~~including identification ~~to determine~~of barriers to implementing ~~SPS’~~our strategy. The business planning process also identifies ~~areas in which there is a potential for a business area~~likelihood and mitigating factors to ~~take~~prevent the assumption of inappropriate risk to meet ~~goals, and determines how to prevent inappropriate risk-taking.~~

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

goals.

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

mitigating factors. The ~~Board of Directors approaches oversight, management and mitigation of risk as an integral and continuous part of its governance of SPS. First, the~~ Board of Directors regularly reviews management’s key risk ~~assessment and analyzes~~assessments, which includes areas of existing and future ~~risks~~financial, operational and ~~opportunities. In addition,~~security risks.

Overall, the oversight, management and mitigation of risk is an integral and continuous part of the Board of ~~Directors assigns oversight~~Directors’ governance of ~~certain critical risks to each of its four standing committees~~SPS. Processes are in place to ensure ~~these risks are well understood and given focused oversight by the~~ appropriate ~~committee. The Audit Committee is responsible for reviewing the adequacy of~~ risk oversight, as well as identification and ~~affirming that appropriate oversight occurs. New risks are considered and assigned as appropriate during the annual Board~~consideration of Directors’ and committee evaluation process, and committee charters and annual work plans are updated accordingly. Committees regularly report on their oversight activities and certain risk issues may be brought to the full Board of Directors for consideration where deemed appropriate to ensure broad Board of Directors’ understanding of the nature of the risk. Finally, the Board of Directors conducts an annual strategy session where SPS’ future plans and initiatives are reviewed and confirmed.

new risks.

Risks Associated with Our Business

~~Environmental~~Operational Risks

~~We are subject to environmental laws~~Our electric transmission and ~~regulations, with which compliance could be difficult~~distribution and ~~costly.~~

~~We are subject to environmental laws and regulations~~gas operations involve numerous risks 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 and 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), licenses, permits, inspections and other approvals. 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. At Dec. 31, 2016, these sites included third party sites, such as landfills, for which we are alleged to be a PRP that sent hazardous materials and wastes.

~~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~~accidents and other operating risks and costs.

Our natural gas transmission activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses. We maintain insurance against some, but not all, of these risks and losses. The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of ~~operations. If~~operations and cash flows.

Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our ~~regulators do not allow us~~natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the Department of Transportation’s national regulatory program to ~~recover all or a part~~assure the safe transportation of ~~the cost~~natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of ~~capital investment or the O&M costs incurred~~natural gas pipeline infrastructure. We have programs in place to comply with the ~~mandates, it~~PHMSA regulations and systematically monitor and renew infrastructure over time, however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations.

Our utility operations are subject to long-term planning and project risks.

Most electric utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of when they are brought in-service subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. Our long-term resource plan is dependent on our ability to obtain required approvals, develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.

In addition, the long-term nature of both our planning and our asset lives are subject to risk. The electric utility sector is undergoing a period of significant change. For example, increases in energy efficiency, wider adoption of lower cost renewable generation, distributed generation and shifts away from coal generation to decrease carbon emissions and increasing use of natural gas in electric generation driven by lower natural gas prices. Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, as well as stranded costs if SPS is not able to fully recover costs and investments.

Changing customer expectations and technologies are requiring significant investments in advanced grid infrastructure, which increases exposure to technology obsolescence.

Evolving stakeholder preference for lower emission generation sources may pressure our investments in natural gas generation and delivery. The magnitude and timing of resource additions and changes in customer demand may not coincide while customer preference for resource generation may change, which introduces further uncertainty into long-term planning. Additionally, multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets.

We are subject to longer-term availability of inputs such as coal, natural gas, uranium and water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.

We are subject to commodity risks and other risks associated with energy markets and energy production.

In the event fuel costs increase, customer demand could decline and bad debt expense may rise, which may have a material impact on our results of operations. Despite existing fuel recovery mechanisms, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows.

A significant disruption in supply could cause us to seek alternative supply services at potentially higher costs and supply shortages may not be fully resolved, which could cause disruptions in our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments could negatively impact our cash flows and results of operations.

We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result, we are subject to market supply and commodity price risk.

Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability.

Failure to attract and retain a qualified workforce could have an adverse effect on operations.

Certain specialized knowledge is required of our technical employees for construction and operation of transmission, generation and distribution assets. Our business strategy is dependent on our ability to recruit, retain and motivate employees. Competition for skilled employees is high in the areas of business operations. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. We have seen a tightening of supply for engineers and skilled laborers in certain markets and are implementing plans to retain these employees. Inability to attract and retain these employees could adversely impact our results of operations, financial ~~position~~condition or cash flows.

Our operations use third-party contractors in addition ~~existing environmental laws~~to employees to perform periodic and ongoing work.

We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance standards, progress payments, insurance requirements and security for performance. Poor vendor performance could impact ongoing operations, restoration operations, our reputation and could introduce financial risk or ~~regulations may be revised, and new laws or regulations may be adopted or become applicable to us, including but not limited to, regulation~~risks of ~~mercury, NOx, SO~~₂~~, 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.

fines.

We are ~~subject~~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 ~~physical and financial risks associated with climate change.~~be adverse to our interests.

~~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~~All of 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 outsidemembers of our ~~service territory~~Board of Directors, as well as many of our executive officers, are officers of Xcel Energy Inc. Our Board or Directors makes determinations with respect to a number of significant corporate events, including the payment of our dividends.

We have historically paid quarterly dividends to Xcel Energy Inc. In 2019, 2018 and 2017 we paid $332.7 million, $131.0 million and $108.8 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could 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 woulddecide to increase the ~~cost of energy~~dividends we ~~provide~~pay to ~~our customers.~~

Severe weather impacts our service territories, primarily when thunderstorms, tornadoes 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,Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs. This could adversely affect our operations, principally our fossil generating units. A negative impact to water supplies due to long-term drought conditions could adversely impact our ability to provide electricity to customers, as well as increaseliquidity. The most restrictive dividend limitation for SPS is imposed by its state regulatory commissions. State regulatory commissions indirectly limit the ~~price they~~amount of dividends that SPS can pay ~~for energy. We may not recover all costs related to mitigating these physical and financial risks.~~Xcel Energy Inc., by requiring a minimum equity-to-total capitalization ratio.

~~Climate change may impact a region’s economic health, which could impact our revenues. Our financial performance is tied~~See Note 5 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 CO~~₂emissions under the CAA, or additional environmental regulation could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher pricesfinancial statements 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.further information.

~~Financial~~Operational Risks

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

Our ~~profitability depends~~natural gas transmission activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. These risks could result in ~~part~~loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses. We maintain insurance against some, but not all, of these risks and losses. The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations and cash flows.

Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the Department of Transportation’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with the PHMSA regulations and systematically monitor and renew infrastructure over time, however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations.

Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to ~~recover costs from our customers~~process transactions and ~~there may be changes in circumstances or in the regulatory environment that impair our ability to recover costs from our customers.~~provide services.

WeOur utility operations are subject to ~~comprehensive regulation by federal~~long-term planning and ~~state~~project risks.

Most electric utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of when they are brought in-service subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory ~~agencies. The state utility commissions regulate many aspects of our utility operations, including siting~~mechanisms, customer behavior, available technology 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~~public policy. Our long-term resource plan is dependent on our ability to ~~recover~~obtain required approvals, develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.

In addition, the ~~costs~~long-term nature of ~~providing energy~~both our planning 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. Weasset lives are subject to ~~both future~~risk. The electric utility sector is undergoing a period of significant change. For example, increases in energy efficiency, wider adoption of lower cost renewable generation, distributed generation and ~~historical test years depending upon the regulatory mechanisms approved~~shifts away from coal generation to decrease carbon emissions and increasing use of natural gas 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~~electric generation driven by lower natural gas prices. Customer adoption 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, whichthese technologies and increased energy efficiency 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 retirementsexcess transmission and ~~while regulation typically provides relief for these types of changes, there~~generation resources, downward pressure on sales growth, as well as stranded costs if SPS is ~~no assurance that regulators would allow full recovery of all remaining costs leaving all or a portion of these asset costs stranded. Rising fuel costs could increase the risk that we will~~ not be able to fully recover costs and investments.

Changing customer expectations and technologies are requiring significant investments in advanced grid infrastructure, which increases exposure to technology obsolescence.

Evolving stakeholder preference for lower emission generation sources may pressure our ~~fuel costs from our customers. Furthermore, there could be~~investments in natural gas generation and delivery. The magnitude and timing of resource additions and changes in ~~the regulatory environment that would impair our ability to recover costs historically collected from our customers.~~

Management currently believes these prudently incurred costs are recoverable given the existing regulatory mechanisms in place. However, 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~~customer demand may not coincide while customer preference for ~~any given period of time, or that a rating will not be lowered or withdrawn entirely by a rating agency. In addition, our credit ratings~~resource generation may change, which introduces further uncertainty into long-term planning. Additionally, multiple states may not agree as ~~a result of~~to the ~~differing methodologies or change in the methodologies used~~appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the various rating agencies. Any downgrade could lead to higher borrowing costs. 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.

same assets.

We are subject to ~~capital market~~longer-term availability of inputs such as coal, natural gas, uranium and ~~interest rate risks.~~water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.

We are subject to commodity risks and other risks associated with energy markets and energy production.

~~Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets~~In the event fuel costs increase, customer demand could decline and bad debt expense may rise, which may have a material impact on our ~~ability to fund~~results of operations. Despite existing fuel recovery mechanisms, higher fuel costs could significantly impact our ~~operations. Capital markets~~results of operations if costs are ~~global~~not recovered. Delays in ~~nature and are impacted by numerous issues and events throughout~~ the ~~world economy. Capital market~~timing of the collection of fuel cost recoveries could impact our cash flows.

A significant disruption ~~events, and resulting broad financial market distress~~in supply could ~~prevent us from issuing new securities or~~ cause us to ~~issue securities~~seek alternative supply services at potentially higher costs and supply shortages may not be fully resolved, which could cause disruptions in our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process. Also, significantly higher energy or fuel costs relative to sales commitments could negatively impact our cash flows and results of operations.

We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with ~~less than ideal terms~~various statutes and ~~conditions, such as higher interest rates.~~commission rulings. As a result, we are subject to market supply and commodity price risk.

~~Higher interest rates on short-term borrowings with variable interest rates~~Failure to attract and retain a qualified workforce could ~~also~~ have an adverse effect on operations.

Certain specialized knowledge is required of our ~~operating results. Changes in interest rates may also impact the fair value~~technical employees for construction and operation of ~~the debt securities in the master pension trust, as well as~~transmission, generation and distribution assets. Our business strategy is dependent on our ability to ~~earn a return on short-term investments~~recruit, retain and motivate employees. Competition for skilled employees is high in the areas of ~~excess cash.~~

~~We are subject~~business operations. Failure to ~~credit risks.~~

~~Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in liquidity~~hire and ~~an increase in bad debt expense. Credit risk is comprised of numerous factors~~adequately train replacement employees, including the ~~price~~transfer of ~~products~~significant internal historical knowledge and ~~services provided, the overall economy~~expertise to new employees or future availability 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 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.

One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges. The credit risk is then socialized through the exchange central clearinghouse function. While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which create an additional need for liquidity to post margin as exchange positions change value daily. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires broad clearingcost of financial swap transactions through a central counterparty, which could lead to additional margin requirements that would impact our liquidity. However, we have taken advantage of an exception to mandatory clearing afforded to commercial end-users who are not classified as a major swap participant. The Board of Directors has authorized Xcel Energy and its subsidiaries to take advantage of this end-user exception.

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, PJM, 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~~labor may adversely affect the ability to manage and operate our business. We have seen a tightening of supply for engineers and skilled laborers in certain markets and are implementing plans to retain these employees. Inability to attract and retain these employees could adversely impact our results of operations, financial ~~position~~condition or ~~liquidity.~~cash flows.

Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.

We are a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.

All of the members of our Board of Directors, as well as many of our executive officers, are officers of Xcel Energy Inc. Our Board or Directors makes determinations with respect to a number of significant corporate events, including the payment of our dividends.

We have ~~defined benefit pension~~historically paid quarterly dividends to Xcel Energy Inc. In 2019, 2018 and ~~postretirement plans that cover most~~2017 we paid $332.7 million, $131.0 million and $108.8 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our ~~employees. Assumptions related~~Board of Directors could decide to ~~future costs, return on investments, interest rates and other actuarial assumptions, including mortality tables, have a significant impact on our funding requirements related~~increase the dividends we pay 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 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 dueXcel Energy Inc. to ~~high retirements or employees leaving SPS~~help support Xcel Energy Inc.’s cash needs. This 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~~liquidity. The most restrictive dividend limitation for SPS is imposed by its state regulatory commissions. State regulatory commissions indirectly limit the amount of ~~operations.~~dividends that SPS can pay Xcel Energy Inc., by requiring a minimum equity-to-total capitalization ratio.

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.

~~Changes in federal tax law may significantly impact our business.~~

There are a number of provisions in federal tax law designed to incentivize capital investments which have benefited our customers by keeping rates lower than without such provisions. Examples of these include the use of accelerated and bonus depreciation for most of our capital investments, PTCs for wind energy, investment tax credits for solar energy and research and development tax credits and deductions. Changes to current federal tax law have the ability to benefit or adversely affect our earnings and our customer costs. Significant changes in corporate tax rates could result in the impairment of deferred tax assets that are established based on existing law. ChangesSee Note 5 to 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 realization of the changes.financial statements for further information.

Operational Risks

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

Our utility operations are subject to long-term planning and project risks.

Changing customer expectations and technologies are requiring significant investments in advanced grid infrastructure, which increases exposure to technology obsolescence.

We are subject to commodity risks and other risks associated with energy markets and energy production.

Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily ~~basis (mark-to-market accounting). Actual settlements~~basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause ~~significant~~ earnings variability.

~~If we encounter market supply shortages or our suppliers are otherwise unable~~Failure to ~~meet their contractual obligations, we may be unable to fulfill our contractual obligations to our customers at previously anticipated costs. Therefore,~~attract and retain 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 commitmentsqualified workforce could have ~~a negative impact~~an adverse effect on operations.

Certain specialized knowledge is required of our ~~cash flows~~technical employees for construction and ~~potentially result in economic losses. Potential market supply shortages may not be fully resolved through alternative supply sources~~operation of transmission, generation and ~~may cause short-term disruptions in~~distribution assets. Our business strategy is dependent on our ability to ~~provide electric services~~recruit, retain and motivate employees. Competition for skilled employees is high in the areas of business operations. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. We have seen a tightening of supply for engineers and skilled laborers in certain markets and are implementing plans to retain these employees. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.

Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.

We have historically paid quarterly dividends to Xcel Energy Inc. In 2019, 2018 and 2017 we paid $332.7 million, $131.0 million and $108.8 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs. This could adversely affect our liquidity. The ~~impact~~most restrictive dividend limitation for SPS is imposed by its state regulatory commissions. State regulatory commissions indirectly limit the amount of ~~these cost and reliability issues~~dividends that SPS can pay Xcel Energy Inc., by requiring a minimum equity-to-total capitalization ratio.

See Note 5 to the financial statements for further information.

Financial Risks

Our profitability depends on our 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.ability to recover costs from our customers and changes in regulation may impair our ability to recover costs from our customers.

~~Our utility operations~~We are subject to ~~long-term planning risks.~~comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.

The profitability of our operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on our capital investment. Our rates are generally regulated and based on an analysis of our costs incurred in a test year. We are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates we are allowed to charge may or may not match our costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.

~~Most electric utility investments are long-lived and are planned~~There can also be no assurance that our regulatory commissions will judge all our costs 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, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. The electric utility sector is undergoing a period of significant change. For example, public policy has driven increases in appliance and lighting efficiency and energy efficient buildings, wider adoption and lower cost of renewable generation and distributed generation, including community solar gardens and customer-sited solar, shifts away from coal generation to decrease CO₂ ~~emissions and increasing use of natural gas in electric generation driven by lower natural gas prices. Over time, customer adoption of these technologies and increased energy efficiency~~prudent, which 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 riskdisallowances, or that the ~~magnitude and timing of resource additions and growth~~regulatory process will always result in ~~customer demand may not coincide, and~~rates 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 during the planning period 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~~will produce full recovery. Overall, management believes prudently incurred costs are ~~recovered~~recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair our ability to recover costs historically collected from customers, ~~as they receive the benefit of service. SPS is engaged in significant~~or we could exceed caps on capital costs (e.g., wind projects) required by commissions and ongoing infrastructure investment programs to accommodate distributed generation and maintain high system reliability. SPS is also investing in renewable and natural gas-fired generation to reduce our CO₂ emissions profile. The inability of coal mining companies to attract capital could disrupt longer-term supplies. Early plant retirements that may result from these changes could expose us to premature financial obligations, which could result in less than full recovery.

Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs. ~~Both decreasing use per customer driven by appliance and lighting efficiency and the availability of cost-effective distributed generation puts~~

In a continued low interest rate environment there has been increased downward pressure on ~~load growth. This~~allowed ROE. Conversely, higher than expected inflation or tariffs may increase costs of construction and operations. Also, rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers.

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

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

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

We are subject to ~~meet customer demand~~capital market and ~~increases~~interest rate risks.

Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Capital markets are global and impacted by issues and events throughout the world. Any disruption in ~~electric rates.~~

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

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

~~The occurrence of any of these events not fully covered by insurance~~capital markets could have a material impact on our ability to fund our operations. Capital market disruption and financial market distress could prevent us from issuing short-term commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our ~~financial position~~operating results.

We are subject to credit risks.

Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in liquidity and ~~results~~an increase in bad debt expense. Credit risk is comprised of ~~operations. For our natural gas transmission lines located near populated~~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 ~~level of potential damages resulting from these risks is greater.~~

~~Additionally, for natural gas~~risk that various counterparties that owe us money or product will become insolvent and may breach their obligations. Should the ~~operating or other costs that~~counterparties fail to perform, we may be ~~required in order~~forced to ~~comply with potential new regulations, including the Pipeline Safety Act,~~enter into alternative arrangements. In that event, our financial results could be ~~significant. The Pipeline Safety Act requires verification~~adversely affected and incur losses.

We may at times have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of ~~pipeline infrastructure records by pipeline owners~~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 ~~operators~~Electric Reliability Council of Texas, in which any credit losses are socialized to ~~confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas.~~ all market participants.

We have ~~programs~~additional indirect credit exposure to financial institutions in ~~place~~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 ~~comply~~drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the ~~Pipeline Safety Act and for systematic infrastructure monitoring and renewal over time. A significant incident~~security were not replaced, the party could ~~increase regulatory scrutiny and result~~be in ~~penalties and higher costs of operations.~~default under the contract.

As we are a subsidiary of Xcel Energy Inc. we may be negatively affected by events impacting the credit or liquidity of Xcel Energy Inc. and its affiliates.

If 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, ~~2016,~~2019, Xcel Energy Inc. and its utility subsidiaries had approximately ~~$14.2~~$17.4 billion of long-term debt and ~~$0.6~~$1.3 billion of short-term debt and current maturities. Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.

Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees. As of Dec. 31, ~~2016,~~2019, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately ~~$18.8~~$2.0 million and ~~exposure of $0.1 million.~~immaterial exposure. Xcel Energy also had additional guarantees of ~~$43.0~~$60.4 million at Dec. 31, ~~2016~~2019 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time. If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

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

We ~~are~~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 ~~wholly owned subsidiary~~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 ~~Xcel Energy Inc. Xcel Energy Inc. can exercise substantial control over our dividend policy and business and operations and may exercise that control~~a significant percentage of pension plan liabilities in a ~~manner that~~single year due to high numbers of retirements or employees leaving would trigger settlement accounting and could require SPS to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future liabilities and benefit costs.

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

Increasing levels of large individual health care claims and overall health care claims could have an adverse toimpact on our ~~interests.~~results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs.

~~All~~

Federal tax law may significantly impact our business.

SPS collects through regulated rates estimated federal, state and local tax payments. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. There could be timing delays before regulated rates provide for realization of tax changes in revenues. In addition, certain IRS tax policies such as tax normalization may impact our ability to economically deliver certain types of resources relative to market prices.

Macroeconomic Risks

Economic conditions impact our business.

Our operations are affected by local, national and worldwide economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay their bills which could lead to additional bad debt expense.

Additionally, SPS faces competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies. We operate in a capital intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates.

Operations could be impacted by war, terrorism or other events.

Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows.

The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have already incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.

A disruption of the ~~members~~regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, our brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility.

We also face the risks of possible loss of business due to significant events such as severe storm, severe temperature extremes, wildfires, widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a disruption of work force within our ~~Board~~operating systems (or on a neighboring system).

The recent coronavirus outbreak in China is an example of ~~Directors,~~how major catastrophic events throughout the world may disrupt our business. While we are a domestic company, the Company participates in a global supply chain, which includes materials and components that are sourced from China. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to reliably serve our customers.

Disruption due to events such as those noted above could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material impact on our results of operations, financial condition or cash flows.

SPS participates in biennial grid security and emergency response exercises (GridEx). These efforts, led by the NERC, test and further develop the coordination, threat sharing and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid.

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

We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors and other individuals.

Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as ~~many~~information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error. Our industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States and individuals. Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability.

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

Our supply chain for procurement of digital equipment may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are ~~officers~~unable to quantify the potential impact of ~~Xcel Energy Inc. Our Board makes determinations with respect~~cyber security threats or subsequent related actions. Cyber security incidents and regulatory action could result in a material decrease in revenues and may causesignificant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.

We maintain security measures to ~~a number of significant corporate events,~~protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including ~~the payment~~asset failure or unauthorized access to assets or information. A failure or breach of our ~~dividends.~~technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability.

Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.

Our electric utility business is seasonal and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Accordingly, our operations have historically ~~paid quarterly dividends to Xcel Energy Inc. In 2016, 2015~~generated less revenues and ~~2014 we paid $85.1 million, $100.5 million~~income when weather conditions are milder in the winter and ~~$83.5 million~~cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of ~~dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s~~operations, or cash requirements increase, our Board of Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs. This could adversely affect our liquidity. The most restrictive dividend limitation for SPS is imposed by its state regulatory commissions. State regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy Inc., by requiring a minimum equity-to-total capitalization ratio. See Item 5 for further discussion on dividend limitations.flows.

Public Policy Risks

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

~~Increased public awareness and concern regarding climate change may result in more state, regional and/or federal requirements to reduce or mitigate the effects of GHGs.~~ Legislative and regulatory responses related to climate change and new interpretations of existing laws ~~through climate change litigation~~ create financial risk as our ~~electric generating~~ facilities may be subject to additional regulation at either the state or federal level in the future. Such regulations could impose substantial costs on our system. ~~International agreements could have an impact to the extent they lead to future federal or state regulations.~~

~~In 2015, the 21~~^st Conference of the Parties to the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries (“nationally determined contributions”), with a goal of holding the increase in global average temperature to below 2^o ~~Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5~~^o~~Celsius. If implemented, the Paris Agreement could result in future additional GHG reductions in the United States.~~

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~~significant and could affect results of operations, financial condition or cash flows ~~and financial condition~~ if such costs are not recovered through regulated rates.

~~The EPA~~Although the United States has ~~proposed the CPP, which would regulate GHGs from power plants by mandating state plans to achieve state-specific~~not adopted any international or federal GHG emission reduction ~~goals. The legality of the CPP has been challenged in the courts,~~targets, many states and the Supreme Court stayed the rule while those challenges proceed. If the rule is ultimately implemented, uncertainties remain regarding implementation plans, including available opportunities to reduce costs, availability of emission trading, how states will allocate the reduction burden among utilities, what actions are creditable and the indirect impact of carbon regulation on natural gas and coal prices.

~~Some states have indicated a desire to~~localities may continue to pursue climate policies ~~even~~ in the absence of federal mandates. ~~All of the~~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 ~~under~~being discussed, the ~~CPP or the Paris Agreement, repeal~~lack of ~~these policies would~~federal action does not adversely impact ~~those~~these state-endorsed actions and plans.

~~Whether under state or federal programs, an important factor is our ability to recover the costs incurred to comply with any regulatory requirements in a timely manner.~~ If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of ~~operations.~~

~~We are also subject to a significant number of proposed and potential rules that will impact our coal-fired and other generation facilities. These include rules associated with emissions of SO~~₂ and NOx, mercury, regional haze, ozone and PM, water intakes, water discharges and ash management. The costs of investment to comply with these rules could be substantial and in some cases would lead to early retirement of coal units. We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us.

operations, financial condition or cash flows.

Increased risks of regulatory penalties could negatively impact our business.

The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. The FERC can ~~now~~ impose penalties of up to ~~$1.2~~$1.3 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. ~~Under statute, the FERC can adjust penalties for inflation.~~ In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial ~~penalties by regional entities,~~penalties. Also, the ~~NERC or the FERC for violations. Additionally, the~~ PHMSA, ~~the~~ Occupational Safety and Health Administration and other federal agencies ~~also~~ have ~~penalty authority.~~the authority to assess penalties. In the event of serious incidents, these agencies have become more active in pursuing penalties. Some states additionally have the authority to impose substantial ~~penalties in the event of non-compliance.~~penalties. If a serious reliability, cyber or safety incident did occur, it could have a material effect on our results of operations, financial condition or ~~financial results.~~cash flows.

Environmental Risks

We ~~attempt~~are subject to ~~mitigate the risk of regulatory penalties through formal training on such prohibited practices~~environmental laws and aregulations, with which compliance ~~function that reviews our interaction with the markets under FERC~~could be difficult and ~~CFTC jurisdictions.~~ 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 ~~managing natural gas risk on our system by removing types~~require us to restrict or limit the output of ~~pipe (e.g. cast iron) with known problem tendencies~~facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and ~~by testing transmission pipelines~~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 ~~high consequence areas. However, there is no guarantee our compliance programs will~~fines or penalties. We may be ~~sufficient~~required to ~~ensure against violations.~~

~~Macroeconomic Risks~~

~~Economic conditions impact our business.~~

~~Our operations are affected by local, national and worldwide economic conditions. Growth in our customer base is correlated with economic conditions. SPS serves~~pay all or a ~~large number~~portion 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 to remediate (i.e., clean-up) sites where our past activities, or the activities of ~~capital~~other parties, caused environmental contamination.

We are subject to mandates to provide customers with clean energy, renewable energy and ~~our ability to raise capital, which is discussed in the capital market risk section above.~~

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

Further, worldwide economic activity has an impact on the demand for basic commodities needed for utility infrastructure, such as steel, copper, aluminum, etc., which may impact our ability to acquire sufficient supplies. Additionally, the cost of those commodities may be higher than expected.

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

Our generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist activities. Any such disruption could result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition and results of operations. The potential for terrorism has subjected our operations to increased risks andenergy conservation offerings. It could have a material effect on our ~~business. We have already~~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 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~~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 ~~implemented~~subject to physical and ~~clarified.~~financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.

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

~~The insurance industry has also been~~Our customers’ energy needs vary with weather. To the extent weather conditions are affected by ~~these events~~climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues.

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

Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may ~~decrease. In addition,~~raise electricity prices, increasing the ~~insurance~~cost of energy we ~~are able~~provide to ~~obtain may have higher deductibles, higher premiums and more restrictive policy terms.~~our customers.

~~A disruption~~

To the extent the frequency of ~~the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources,~~extreme weather events increases, this could ~~negatively~~increase our cost of providing service. Periods of extreme temperatures could impact our ~~business. Because~~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 the transmission systems and local natural gas distribution companies are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility or an event (severe storm, severe temperature extremes, wildfires, solar storms, generator or transmission facility outage, breakdown or failure of equipment, pipeline rupture, railroad disruption, sudden and significant increase or decrease in wind generation or any disruption of work force such as may be caused by flu or other epidemic) within our operating systems or on a neighboring system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material impact on our financial condition and results.

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

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

We operate in an industry that requires the continued operation of sophisticated information technology 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 (e.g., information about our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error. Our industry has begun to see an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States and individuals. Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or exposing us to liability. Our generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third party service providers’ operations, could also negatively impact our business. In addition, such an event would likely receive regulatory scrutiny at both the federal and state level. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. These potential cyber security incidents and corresponding regulatory action could result in a material decrease in revenues and may cause~~significant additional costs (e.g., penalties, third party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.~~

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

~~Rising energy prices could negatively impact our business.~~

Although commodity prices are currently relatively low, if fuel costs increase, customer demand could decline and bad debt expense may rise, which could have a material impact on our results of operations.facilities. While we ~~have fuel clause recovery mechanisms, higher fuel costs~~carry liability insurance, given an extreme event, if SPS was found to be liable for wildfire damages, amounts that potentially exceed our coverage could ~~significantly~~negatively 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~~financial condition or cash flows. ~~Low fuel~~Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of units and increase the price paid for energy. We may not recover all costs ~~could have a positive impact on sales although, low oil prices could negatively impact oil~~related to mitigating these physical and ~~gas production activities. 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. Poor vendor performance could impact on going operations, restoration operations, our reputation and could introduce financial risk or risks of fines for SPS.

risks.

~~Item 1B — Unresolved Staff Comments~~

ITEM 1B — UNRESOLVED STAFF COMMENTS

None.

~~Item 2 —Properties~~

ITEM 2 —PROPERTIES

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

Electric Utility Generating Stations:
Station, Location and Unit Fuel Installed
Summer 2016
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 338

Maddox-Hobbs, N.M., 1 Unit Natural Gas 1963-1976 61

Total 4,416



Station, Location and Unit	Fuel	Installed	MW ^(a)
Steam:
Cunningham-Hobbs, NM, 2 Units	Natural Gas	1957 - 1965	189
Harrington-Amarillo, TX, 3 Units	Coal	1976 - 1980	1,018
Jones-Lubbock, TX, 2 Units	Natural Gas	1971 - 1974	486
Maddox-Hobbs, NM, 1 Unit	Natural Gas	1967	112
Nichols-Amarillo, TX, 3 Units	Natural Gas	1960 - 1968	457
Plant X-Earth, TX, 4 Units	Natural Gas	1952 - 1964	411
Tolk-Muleshoe, TX, 2 Units	Coal	1982 - 1985	1,067
Combustion Turbine:
Cunningham-Hobbs, NM, 2 Units	Natural Gas	1997	209
Jones-Lubbock, TX, 2 Units	Natural Gas	2011 - 2013	334
Maddox-Hobbs, NM, 1 Unit	Natural Gas	1963 - 1976	61
Wind:
Hale-Plainview, TX, 239 Units ^(b)	Wind	2019	460
		Total	4,804

^(a)~~Carlsbad Unit 5 was decommissioned on Dec. 31, 2016.~~


^(a)	Summer 2019 net dependable capacity.


^(b)	Values disclosed are the maximum generation levels for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, ~~2016:~~2019:



Conductor Miles
345 KV	~~8,509~~9,566
230 KV	~~9,424~~9,784
115 KV	~~12,685~~14,662
Less than 115 KV	~~24,499~~26,216

SPS had 452 electric utility transmission and distribution substations at Dec. 31, ~~2016.~~2019.

Natural gas utility mains at Dec. 31, 2019:



Miles
Transmission	20
Distribution	—

~~Item 3 —Legal Proceedings~~

ITEM 3 —LEGAL PROCEEDINGS

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

~~Additional Information~~

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

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

further information.

~~Item 4~~ — ~~Mine Safety Disclosures~~

ITEM 4 — MINE SAFTEY DISCLOSURES

None.

PART II

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

ITEM 5 —MARKETFOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS ANDISSUER PURCHASE OF EQUITY SECURITIES

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

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

The most restrictive dividend limitation for SPS is imposed by its state regulatory commissions. SPS’ state regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy Inc. by requiring an equity-to-total capitalization ratio (excluding short-term debt) between 45.0 percent and 55.0 percent. In addition, SPS may not pay a dividend that would cause it to lose its investment grade bond rating. SPS’ equity-to-total capitalization ratio (excluding short-term debt) was 54.1 percent at Dec. 31, 2016 and $487 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 ~~2016~~2019 and ~~2015~~2018 were as follows:


(Thousands of Dollars)	2016		2015
(Millions of Dollars)					2019		2018
First quarter	$	25,645	$	25,339	$	57.5	$	33.3
Second quarter	19,388		23,025		83.4		30.7
Third quarter	27,498		24,352		114.6		40.0
Fourth quarter	30,870		12,538		78.3		45.4

~~Item 6 —Selected Financial Data~~

ITEM 6 —SELECTED FINANCIAL DATA

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

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

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

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

Non-GAAP Financial ~~Review~~

Measures

The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as, electric margin and ongoing earnings. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from measures calculated and presented in accordance with GAAP. SPS’ management uses non-GAAP measures for financial planning and analysis, ~~by management focuses on those factors that had a material effect on SPS’ financial condition,~~for reporting of results of operations, and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying financial statements and the related notes to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP 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 statementsmeasures are intended to supplement investors’ understanding of our performance and should not be ~~identified~~considered alternatives for financial measures presented in ~~this document~~accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.

Electric Margins

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

Earnings Adjusted for Certain Items (Ongoing Earnings)

Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items.

We use these non-GAAP financial measures to evaluate and provide details of SPS’ core earnings and underlying performance. We believe these measurements are useful to investors to evaluate the ~~words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,”~~actual and ~~similar expressions. Actual results may vary materially. Forward-looking statements speak only as~~projected financial performance and contribution of SPS. For the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal yearyears ended Dec. 31, ~~2016 (including risk factors listed from time~~2019 and Dec. 31, 2018, there were no adjustments to ~~time by SPS in reports filed~~GAAP earnings and therefore GAAP earnings equal ongoing earnings.

Results of Operations

2019 Comparison with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K and Exhibit 99.01 hereto), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of SPS to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth, recovery, trade, fiscal, taxation and environmental policies in areas where SPS has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by SPS; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric market; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability of cost of capital; and employee work force factors.

~~Results of Operations~~

2018

SPS’ net income was approximately ~~$152.2~~$263.1 million for ~~2016,~~2019, compared with net income of ~~approximately $127.3~~$213.3 million for ~~2015. Higher~~2018. The increase was primarily due to higher electric margins attributable to purchased capacity costs, regulatory rate outcomes, demand revenue, higher AFUDC related to the Hale wind farm and lower ~~O&M expenses were~~income taxes, partially offset by ~~an increase in~~increased interest and depreciation ~~and interest charges.~~

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. ~~The design of~~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 and, therefore, changes in fuel or purchased power costs can impact earnings. The following table details the electric~~expenses. Electric revenues and ~~margin:~~margin for 2018 are before and after the impact of the TCJA:



(Millions of Dollars)	2019			2018
Electric revenues before TCJA impact	$	1,825.8		$	1,988.1
Electric fuel and purchased power before TCJA impact	(875.4		)	(1,050.1		)
Electric margin before TCJA impact	$	950.4		$	938.0
TCJA impact (offset as a reduction in income tax)	—			(48.3		)
Electric margin	$	950.4		$	889.7

(Millions of Dollars) 2016 2015
Electric revenues $ 1,851
$ 1,787
Electric fuel and purchased power (1,035 ) (1,001 )
Electric margin $ 816
$ 786

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

~~Electric Revenues~~31, 2019:

(Millions of Dollars) 2016 vs. 2015
Transmission revenue $ 38
Fuel and purchase power cost recovery 17
Retail rate increases ^(a)
11
Estimated impact of weather 2
Trading (5 )
Other, net 1
Total increase in electric revenues $ 64

~~Electric Margin~~

(Millions of Dollars) 2016 vs. 2015
Retail rate increases ^(a)
$ 11
Transmission revenue, net of costs 10
Fuel handling and procurement 5
Estimated impact of weather 2
Other, net 2
Total increase in electric margin $ 30


^(a)	~~The retail rate increases are due to rate proceedings in Texas and New Mexico. See Note 10 to the financial statements.~~



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

Non-Fuel Operating Expense and Other Items

~~O&M Expenses~~— O&M expenses decreased $20.4 million, or 7.0 percent for 2016 compared with 2015. The decrease was mainly due to the timing and scope of plant outages and deferral of certain expenses associated with the Texas 2016 electrical rate case.

Depreciation and Amortization — Depreciation and amortization ~~expenses~~expense increased ~~$11.5~~$20.3 million, or ~~7.6 percent~~9.7%, for ~~2016~~2019 compared with ~~2015. The increase is primarily attributable to capital investments.~~

~~Taxes (Other Than Income Taxes)~~ ~~— Taxes (other than income taxes) increased $3.3 million, or 5.7 percent for 2016 compared with 2015. The increase is primarily due to higher property taxes.~~

~~AFUDC, Equity and Debt~~ ~~— AFUDC increased $3.7 million for 2016 compared with 2015.~~the prior year. The increase was primarily due to the ~~expansion of transmission facilities~~Hale wind farm being placed into service and ~~other~~increased capital ~~expenditures.~~investments.

AFUDC, Equity and Debt— AFUDC increased by $11.1 million, or 39.6% for 2019 compared with the prior year. The increase was primarily due to the Hale and Sagamore wind farms.

Interest Charges— Interest charges increased ~~$4.6~~14.8 million, or ~~5.5 percent,~~17.5% for ~~2016~~2019 compared with ~~2015.~~the prior year. The increase was primarily due to higher ~~long-term~~ debt levels to fund capital investments.

Income Taxes — Income tax expense ~~increased $7.1~~decreased $13.3 million for ~~2016~~2019 compared with ~~2015.~~the prior year. The ~~increase~~decrease was primarily driven by wind PTCs; partially offset by higher pretax income. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income.The ETR was 8.9% for 2019 compared with 15.4% for 2018. The lower ETR in ~~income tax expense~~2019 was primarily due to ~~higher pretax earnings~~the items referenced above.

2018 Comparison with 2017

A discussion of changes in ~~2016, partially offset~~SPS’ results of operations and liquidity and capital resources from the year ended Dec. 31, 2017 to Dec. 31, 2018 can be found in Part II, “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year 2018, which was filed with the SEC on Feb. 22, 2019. However, such discussion is not incorporated by reference into, and does not constitute a ~~tax benefit for prior year adjustments in 2016. The ETR was 35.1 percent for 2016, compared with 37.1 percent for 2015.~~

part of, this Annual Report on Form 10-K.

~~Item 7A —Quantitativeand Qualitative Disclosures About Market Risk~~

Regulation

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

Xcel Energy, which includes SPS, attempts to mitigate the risk of regulatory penalties through formal training on prohibited practices and a compliance function that reviews interaction with the markets under FERC and Commodity Futures Trading Commission jurisdictions.

Pending Regulatory Proceedings



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

Texas Electric Rate Case

In August 2019, SPS filed an electric rate case with the PUCT seeking an increase in retail electric base rates of approximately $141 million. The filing requests an ROE of 10.35%, a 54.65% equity ratio, a rate base of approximately $2.6 billion and is built on a 12 month period that ended June 30, 2019. In September 2019, SPS filed an update to the electric rate case and revised its requested increase to $136.5 million.

On Feb. 10, 2020, the Alliance of Xcel Municipalities (AXM), Texas Industrial Energy Consumers (TIEC), Office of Public Utility Counsel (OPUC) and the Department of Energy (DOE), filed testimony along with several other parties.

On Feb. 18, 2020, the PUCT Staff filed testimony that included certain adjustments and various ring-fencing measures.

Proposed modifications to SPS’ request:



(Millions of Dollars)	Staff			AXM			OPUC			TIEC			DOE
SPS Direct Testimony	$	136.5		$	136.5		$	136.5		$	136.5		$	136.5

Recommended base rate adjustments:
ROE	(22.1		)	(24.2		)	(15.2		)	(20.5		)	(23.8		)
Capital structure	(6.9		)	(10.4		)	—			(6.9		)	(3.1		)
Tolk/Harrington O&M disallowance	—			(6.6		)	—			—			—
Distribution and Transmission Capital Disallowances ^(a)	(6.5		)	—			—			—			—
Depreciation expense	(7.5		)	(14.5		)	(8.3		)	(20.4		)	—
Excess ADIT unprotected plant	—			—			(6.9		)	—			—
Income Tax Expense Differences	(11.6		)	—			—			—			—
Other, net	(6.8		)	(6.1		)	(0.4		)	(0.6		)	—
Total Adjustments	(61.4		)	(61.8		)	(30.8		)	(48.4		)	(26.9		)
Total proposed revenue change	$	75.1		$	74.7		$	105.7		$	88.1		$	109.6



Recommended Position	Staff		AXM		OPUC ^(b)		TIEC		DOE
ROE	9.1	%	9.0	%	—	%	9.2	%	9.0	%
Equity Ratio	51.00	%	50.00	%	—	%	51.00	%	53.00	%


^(a)	Staff recommends exclusion of approximately $134 million in transmission, distribution, and general plant in service in this rate case resulting in an approximate $7 million decrease to the revenue requirement.


^(b)	OPUC did not provide a recommendation for an ROE or equity ratio. For illustrative purposes an ROE of 9.5% was used.

The next steps in the procedural schedule are expected to be as follows:

Rebuttal testimony — March 11, 2020; and

Public hearing begins — March 30, 2020.

A PUCT decision and implementation of final rates is anticipated in the third quarter of 2020.

Texas State ROFR

In May 2019, the Governor signed into law Senate Bill 1938, which grants incumbent utilities a ROFR to build transmission infrastructure when it directly interconnects to the utility’s existing facility. In June 2019, a complaint was filed in the United States District Court for the Western District of Texas claiming the new ROFR law to be unconstitutional. The Texas Attorney General has made a motion to dismiss the federal court complaint. A ruling on the dismissal motion is expected in the first quarter of 2020.

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

ITEM 7A —QUANTITATIVEAND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Derivatives, Risk Management and Market Risk

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

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

information.

SPS is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, ~~when necessary,~~ management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While SPS expects that the counterparties will perform under the contracts underlying its derivatives, the contracts expose SPS to some credit and ~~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 ~~to the extent such exposure exists.~~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, 2016 and 2015, a 100 basis point~~A 100-basis-point change in the benchmark rate on SPS’ variable rate debt would have no impact on annual pretax interest expense ~~by approximately $0.5~~in 2019 and $0.4 million ~~and $0.2 million,~~in 2018, respectively.

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

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

At Dec. 31, ~~2016,~~2019, a ~~10 percent~~10% increase in commodity prices would have resulted in an increase in credit exposure of ~~$0.3~~$1.2 million, while a decrease in prices of ~~10 percent~~10% would have resulted in a decrease in credit exposure of ~~$0.3~~$1.2 million. At Dec. 31, ~~2015,~~2018, a ~~10 percent~~10% increase in commodity prices would have resulted in an increase in credit exposure of ~~$0.5~~$1.5 million, while a decrease in prices of ~~10 percent~~10% would have resulted in a decrease in credit exposure of ~~$0.5~~$1.5 million.

SPS conducts ~~standard~~ credit reviews for all ~~counterparties. SPS~~counterparties and employs ~~additional~~ credit risk ~~control mechanisms when appropriate,~~controls, such as letters of credit, parental guarantees, ~~standardized~~ master netting agreements and termination ~~provisions that allow for offsetting of positive and negative exposures.~~provisions. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase SPS’ credit risk.

Fair Value Measurements

SPS ~~follows 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, ~~2016. SPS also assesses the impact of its own~~2019.

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, ~~2016.~~2019.

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 $3.3 million and $1.3 million of estimated fair values, respectively, for FTRs held at Dec. 31, 2016.

~~Item 8 — Financial Statements and Supplementary Data~~

ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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

Management Report on Internal Controls Over Financial Reporting

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

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

In 2016, SPS implemented the general ledger modules of a new enterprise resource planning system. SPS will initiate deployment of work management systems modules, including the conversion of existing work management systems, during 2017. SPS does not believe this implementation has or will have 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, ~~2016.~~2019. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, ~~2016,~~2019, SPS’ internal control over financial reporting is effective at the reasonable assurance level based on those criteria.



/s/ BEN FOWKE		/s/ ROBERT C. FRENZEL
Ben Fowke		Robert C. Frenzel
Chairman, ~~and~~ Chief Executive Officer and Director		Executive Vice President, Chief Financial Officer and Director
Feb. ~~24, 2017~~21, 2020		Feb. ~~24, 2017~~21, 2020

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholder and Board of Directors ~~and Stockholder~~ of

Southwestern Public Service Company

Opinion on the Financial Statements

We have audited the accompanying balance sheets ~~and statements of capitalization~~ of Southwestern Public Service Company (the ~~“Company”~~"Company") as of December 31, ~~2016~~2019 and ~~2015, and~~2018, 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, ~~2016. Our audits also included~~2019, and the ~~financial statement~~related notes and the schedule listed in the Index at Item ~~15.~~ 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements ~~and financial statement schedule~~ are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements ~~and financial statement schedule~~ 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 ~~Public Company Accounting Oversight Board (United States).~~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.~~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. ~~Our~~As part of our audits, ~~included consideration~~we are required to obtain an understanding of internal control over financial reporting ~~as a basis for designing audit procedures that are appropriate in the circumstances,~~ 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. ~~An audit also includes~~

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 ~~supporting~~regarding the amounts and disclosures in the financial ~~statements, assessing~~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 ~~statement presentation.~~statements. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Southwestern Public Service Company as of December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February ~~24, 2017~~21, 2020

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
	2016			2015			2014			2019			2018			2017

Operating revenues	$	1,850,959		$	1,787,218		$	1,937,370		$	1,825.8		$	1,933.2		$	1,918.0

Operating expenses
Electric fuel and purchased power	1,034,950			1,001,083			1,192,176			875.4			1,043.5			1,055.3
Operating and maintenance expenses	269,471			289,856			277,217			285.3			282.7			285.4
Demand side management program expenses	16,028			13,365			12,350			16.6			17.7			15.5
Depreciation and amortization	162,429			150,913			135,632			229.9			209.6			193.9
Taxes (other than income taxes)	60,800			57,536			53,871			71.9			68.0			67.0
Total operating expenses	1,543,678			1,512,753			1,671,246			1,479.1			1,621.5			1,617.1

Operating income	307,281			274,465			266,124			346.7			311.7			300.9

Other income (expense), net	91			(6		)	(59		)	2.2			(3.0		)	(1.8		)
Allowance for funds used during construction — equity	9,981			7,378			12,118			26.8			19.1			9.3

Interest charges and financing costs
Interest charges — includes other financing costs of $3,055, $3,158 and $3,038, respectively	88,671			84,040			80,218
Interest charges — includes other financing costs of $3.4, $2.9 and $2.5, respectively										99.3			84.5			86.2
Allowance for funds used during construction — debt	(5,589		)	(4,491		)	(7,089		)	(12.3		)	(8.9		)	(5.4		)
Total interest charges and financing costs	83,082			79,549			73,129			87.0			75.6			80.8

Income before income taxes	234,271			202,288			205,054			288.7			252.2			227.6
Income taxes	82,114			75,025			75,202			25.6			38.9			68.4
Net income	$	152,157		$	127,263		$	129,852		$	263.1		$	213.3		$	159.2

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF COMPREHENSIVE INCOME

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

Year Ended Dec. 31
2016 2015 2014
Net income $ 152,157
$ 127,263
$ 129,852

Other comprehensive (loss) income

Pension and retiree medical benefits:
Net pension and retiree medical benefits losses arising during the period,
net of tax of $(84), $(260), and $0, respectively
(148 ) (464 ) —

Derivative instruments:
Reclassification of losses to net income, net of tax of
$80, $97, and $96, respectively
139
172
172

Other comprehensive (loss) income (9 ) (292 ) 172
Comprehensive income $ 152,148
$ 126,971
$ 130,024



	Year Ended Dec. 31
	2019			2018		2017
Net income	$	263.1		$	213.3	$	159.2

Other comprehensive income

Defined pension and other postretirement benefits:
Net pension and retiree medical loss arising during the period, net of tax of $(0.1), $0 and $0, respectively	(0.2		)	—		—
Reclassification of loss to net income, net of tax of $0	0.2			—		0.1
Derivative instruments:
Reclassification of loss to net income, net of tax of $0	—			0.1		—

Other comprehensive income	—			0.1		0.1
Comprehensive income	$	263.1		$	213.4	$	159.3

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF CASH FLOWS

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


	Year Ended Dec. 31									Year Ended Dec. 31
	2016			2015			2014			2019			2018			2017
Operating activities
Net income	$	152,157		$	127,263		$	129,852		$	263.1		$	213.3		$	159.2
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	162,957			153,241			137,947			232.2			210.0			193.9
Demand side management program amortization	1,673			1,673			1,673			—			1.7			1.7
Deferred income taxes	122,983			62,836			123,517			29.0			22.1			126.5
Amortization of investment tax credits	(213		)	(213		)	(341		)
Allowance for equity funds used during construction	(9,981		)	(7,378		)	(12,118		)	(26.8		)	(19.1		)	(9.3		)
Provision for bad debts	6,066			4,655			4,137			5.7			4.9			5.1
Net derivative losses	217			268			268			—			0.1			0.1
Other	122			(3,827		)	—
Changes in operating assets and liabilities:
Accounts receivable	(8,868		)	(3,291		)	9,045			(9.0		)	(19.5		)	(10.4		)
Accrued unbilled revenues	(15,637		)	25,506			(20,080		)	(0.6		)	15.3			(10.4		)
Inventories	(959		)	5,686			(6,093		)	(20.5		)	(16.0		)	(1.9		)
Prepayments and other	22,651			(24,712		)	(11,905		)	2.8			0.5			4.3
Accounts payable	13,776			(24,570		)	11,428			(8.5		)	(6.6		)	11.8
Net regulatory assets and liabilities	(55,689		)	26,452			(973		)	13.8			38.2			38.1
Other current liabilities	5,156			(30,762		)	12,665			5.8			11.6			3.4
Pension and other employee benefit obligations	(15,276		)	(9,405		)	(2,246		)	(17.7		)	(16.0		)	(21.7		)
Change in other noncurrent assets	(200		)	2,352			2,836
Change in other noncurrent liabilities	6,748			8,974			7,166
Other, net										3.5			5.8			(19.9		)
Net cash provided by operating activities	387,683			314,748			386,778			472.8			446.3			470.5

Investing activities
Utility capital/construction expenditures	(512,522		)	(599,511		)	(554,936		)	(844.4		)	(1,020.9		)	(550.6		)
Allowance for equity funds used during construction	9,981			7,378			12,118
Proceeds from insurance recoveries	3,901			—			—
Investments in utility money pool arrangement	(75,000		)	(92,000		)	(105,000		)	(133.0		)	(285.0		)	(142.0		)
Receipts from utility money pool arrangement	75,000			92,000			105,000			133.0			350.0			77.0
Other	(1,174		)	3,136			—			—			—			(0.5		)
Net cash used in investing activities	(499,814		)	(588,997		)	(542,818		)	(844.4		)	(955.9		)	(616.1		)

Financing activities
Proceeds from (repayment of) short-term borrowings, net	35,000			(22,000		)	(47,000		)
(Repayments of) proceeds from short-term borrowings, net										(42.0		)	42.0			(50.0		)
Proceeds from issuance of long-term debt	295,985			198,496			148,123			292.2			295.0			442.3
Repayment of long-term debt	(200,000		)	—			—
Repayment of long-term debt, including reacquisition premiums										—			—			(271.6		)
Borrowings under utility money pool arrangement	636,500			579,700			458,000			296.0			595.0			335.0
Repayments under utility money pool arrangement	(636,500		)	(595,700		)	(480,000		)	(296.0		)	(595.0		)	(335.0		)
Capital contributions from parent	66,225			214,535			160,000			426.3			336.8			143.7
Dividends paid to parent	(85,069		)	(100,544		)	(83,498		)	(332.7		)	(131.0		)	(108.8		)
Net cash provided by financing activities	112,141			274,487			155,625			343.8			542.8			155.6

Net change in cash and cash equivalents	10			238			(415		)
Cash and cash equivalents at beginning of year	834			596			1,011
Cash and cash equivalents at end of year	$	844		$	834		$	596
Net change in cash, cash equivalents and restricted cash										(27.8		)	33.2			10.0
Cash, cash equivalents and restricted cash at beginning of year										44.0			10.8			0.8
Cash, cash equivalents and restricted cash at end of year										$	16.2		$	44.0		$	10.8

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(78,236	)	$	(76,474	)	$	(70,748	)	$	(83.6	)	$	(71.2	)	$	(76.0	)
Cash received (paid) for income taxes, net	61,813			(23,987		)	42,679			11.9			(10.6		)	41.5
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	43,074		$	44,335		$	33,164		$	94.5		$	71.5		$	85.1
Inventory transfer additions in property, plant and equipment										23.3			22.5			13.7
Operating lease right-of-use assets										548.3			—			—
Allowance for equity funds used during construction										26.8			19.1			9.3

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.

BALANCE SHEETS

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


	Dec. 31						Dec. 31
	2016			2015			2019			2018
Assets
Current assets
Cash and cash equivalents	$	844		$	834		$	16.2		$	44.0
Accounts receivable, net	74,190			71,166			92.7			90.7
Accounts receivable from affiliates	949			1,079			4.2			10.5
Investments in money pool arrangements							—			—
Accrued unbilled revenues	119,418			103,781			115.1			114.5
Inventories	38,505			37,546			31.0			33.9
Regulatory assets	38,721			31,541			20.0			26.0
Derivative instruments	5,114			12,952			15.0			17.8
Prepaid taxes	21,779			35,666			0.8			14.2
Prepayments and other	7,855			20,520			21.4			10.7
Total current assets	307,375			315,085			316.4			362.3

Property, plant and equipment, net	4,695,819			4,348,823			6,631.6			5,946.4

Other assets
Regulatory assets	346,683			301,814			364.0			366.2
Derivative instruments	22,113			25,272			12.6			15.8
Operating lease right-of-use assets							522.4			—
Other	7,477			3,449			3.9			5.1
Total other assets	376,273			330,535			902.9			387.1
Total assets	$	5,379,467		$	4,994,443		$	7,850.9		$	6,695.8

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	—		$	200,000
Short-term debt	50,000			15,000			$	—		$	42.0
Accounts payable	176,157			146,794			168.1			191.8
Accounts payable to affiliates	14,414			29,135			20.4			19.9
Regulatory liabilities	41,577			98,305			118.1			85.8
Taxes accrued	39,742			33,374			40.4			41.6
Accrued interest	19,162			17,781			26.2			25.8
Dividends payable	30,870			12,538			46.3			45.2
Derivative instruments	3,565			3,565			3.7			3.6
Operating lease liabilities							26.9			—
Other	29,703			35,654			30.7			28.3
Total current liabilities	405,190			592,146			480.8			484.0

Deferred credits and other liabilities
Deferred income taxes	989,137			860,744			671.8			619.1
Regulatory liabilities	233,454			229,584			732.3			780.9
Asset retirement obligations	28,663			27,233			77.3			32.4
Derivative instruments	23,513			27,078			12.8			16.4
Pension and employee benefit obligations	107,872			93,346			67.0			92.4
Operating lease liabilities							495.3			—
Other	24,084			17,841			9.4			7.9
Total deferred credits and other liabilities	1,406,723			1,255,826			2,065.9			1,549.1

Commitments and contingencies
Capitalization
Long-term debt	1,635,858			1,338,522			2,419.7			2,126.1
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2016 and 2015, respectively	—			—
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2019 and 2018, respectively							—			—
Additional paid in capital	1,446,223			1,371,223			2,350.9			1,932.3
Retained earnings	486,763			438,007			535.0			605.7
Accumulated other comprehensive loss	(1,290		)	(1,281		)	(1.4		)	(1.4		)
Total common stockholder’s equity	1,931,696			1,807,949			2,884.5			2,536.6
Total liabilities and equity	$	5,379,467		$	4,994,443		$	7,850.9		$	6,695.8

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

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


	Common Stock Issued								Accumulated Other Comprehensive Income (Loss)				Total Common Stockholder’s Equity			Common Stock Issued											Accumulated Other Comprehensive Income (Loss)			Total Common Stockholder’s Equity
	Shares	Par Value		Additional Paid In Capital		Retained Earnings						Shares					Par Value			Additional Paid In Capital			Retained Earnings
Balance at Dec. 31, 2013	100	$	—	$	1,005,463	$	359,389			$	(1,161	)			$	1,363,691
Balance at Dec. 31, 2016																100		$	—		$	1,446.2		$	486.7		$	(1.3	)	$	1,931.6

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

Net income																								213.3						213.3
Other comprehensive loss																											0.1			0.1
Common dividends declared to parent																								(149.2		)				(149.2		)
Contribution of capital by parent																					342.1									342.1
Balance at Dec. 31, 2018																100		$	—		$	1,932.3		$	605.7		$	(1.4	)	$	2,536.6

Net income						129,852							129,852											263.1						263.1
Other comprehensive income									172				172														—			—
Common dividends declared to parent						(93,243		)					(93,243		)									(333.8		)				(333.8		)
Contribution of capital by parent				160,000									160,000								418.6									418.6
Balance at Dec. 31, 2014	100	$	—	$	1,165,463	$	395,998		$	(989	)		$	1,560,472
Net income						127,263							127,263
Other comprehensive loss									(292		)		(292		)
Common dividends declared to parent						(85,254		)					(85,254		)
Contribution of capital by parent				205,760									205,760
Balance at Dec. 31, 2015	100	$	—	$	1,371,223	$	438,007		$	(1,281	)		$	1,807,949
Net income						152,157							152,157
Other comprehensive loss									(9		)		(9		)
Common dividends declared to parent						(103,401		)					(103,401		)
Contribution of capital by parent				75,000									75,000
Balance at Dec. 31, 2016	100	$	—	$	1,446,223	$	486,763		$	(1,290	)		$	1,931,696
Balance at Dec. 31, 2019																100		$	—		$	2,350.9		$	535.0		$	(1.4	)	$	2,884.5

See Notes to Financial Statements

~~SOUTHWESTERN PUBLIC SERVICE CO.~~

~~STATEMENTS OF CAPITALIZATION~~

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

Dec. 31
2016 2015
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
—
Unsecured Senior E Notes, due Oct. 1, 2016, 5.6% —
200,000
Unsecured Senior G Notes, due Dec. 1, 2018, 8.75% 250,000
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 premium 365
605
Unamortized debt expense (14,507 ) (12,083 )
Total 1,635,858
1,538,522
Less current maturities —
200,000
Total long-term debt $ 1,635,858
$ 1,338,522

Common Stockholder’s Equity
Common stock — 200 shares authorized of $1.00 par value,
100 shares outstanding at Dec. 31, 2016 and 2015, respectively
$ —
$ —
Additional paid in capital 1,446,223
1,371,223
Retained earnings 486,763
438,007
Accumulated other comprehensive loss (1,290 ) (1,281 )
Total common stockholder’s equity $ 1,931,696
$ 1,807,949

~~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~~commissions. Certain amounts in the ~~same in all material respects.~~2018 and 2017 financial statements or notes have been reclassified to conform to the 2019 presentation for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.

~~Variable Interest Entities— SPS evaluates its arrangements and contracts with other entities, including but not limited to, PPAs and fuel contracts to determine if the other party is a variable interest entity, if~~ SPS has ~~a variable interest~~evaluated events occurring after Dec. 31, 2019 up to the date of issuance of these financial statements. These statements contain all necessary adjustments and ~~if SPS is the primary beneficiary. SPS follows accounting guidance for variable interest entities which requires consideration of the 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~~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, financial condition and cash flows.

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

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

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

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

~~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 expense.

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 and home weatherization.~~connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.

See Note 7 for further information.

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

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

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

SPS records depreciation expense ~~related to its plant~~ using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was ~~2.7, 2.6~~2.9% in 2019, 2.9% in 2018 and ~~2.5 percent for the years ended Dec. 31, 2016, 2015 and 2014, respectively.~~2.8% in 2017.

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

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

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

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

~~Income 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 income in the period that includes the enactment date.

~~Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion~~unrecognized prior service costs 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.

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes, the reversal of some temporary differences are accounted for as current income tax expense. 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 certaindeferred as regulatory assets and liabilities, ~~related to~~rather than recorded as other comprehensive income, ~~taxes, which are summarized in Note 12.~~

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

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

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

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

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

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

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

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

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

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

~~Fair Value Measurements~~ — SPS presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its financial statements. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, SPS may use quoted prices for similar contracts or internally prepared valuation models to determine fair value. See Note 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.

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 of environmental costs.~~information.

~~Benefit Plans~~Cash and ~~Other Postretirement Benefits~~Cash Equivalents — SPS ~~maintains~~considers investments in instruments with a remaining maturity of three months or less at the time of purchase to be cash equivalents.

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

As of Dec. 31, 2019 and 2018, the allowance for bad debts was $5.3 million and $5.6 million, respectively.

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



(Millions of Dollars)	Dec. 31, 2019		Dec. 31, 2018
Inventories
Materials and supplies	$	24.7	$	25.7
Fuel	6.3		8.2
Total inventories	$	31.0	$	33.9

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

See Notes 8 and 9 for further information.

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

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

See Note 8 for further information.

Other Utility Items

AFUDC— AFUDC represents the cost of ~~providing 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. 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, including expected collection within 24 months, revenue is recognized equal to the revenue requirement, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these ~~plans under applicable accounting guidance requires management to make various assumptions~~programs are presented on a gross basis and ~~estimates.~~

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

disclosed separately from revenue from contracts with customers.

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

~~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, including 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 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~~future rates.

Sales of ~~specific triggering events~~RECs are recorded in electric revenues on a gross basis. Cost of these RECs and ~~other conditions which may modify the ongoing obligation~~amounts credited to ~~perform~~customers under ~~the guarantee.~~margin-sharing mechanisms are recorded in electric fuel and purchased power expense.

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

Segment Information — SPS has only one reportable segment. SPS is a wholly owned subsidiary of Xcel Energy Inc. and operates in the regulated electric utility industry providing wholesale and retail electric service in the states of Texas and New Mexico. ~~Operating results from the regulated electric utility segment serve as the primary basis for the chief operating decision maker to evaluate the performance of SPS.~~

~~Reclassifications~~— Due to adoption of new accounting pronouncements, certain previously reported amounts have been reclassified to conform to the current year presentation. See Note 2 for further discussion of recently adopted accounting pronouncements.

~~Subsequent Events~~ — Management has evaluated the impact of events occurring after Dec. 31, 2016 up to the date of issuance of these financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.



2.	Accounting Pronouncements

Recently Issued

~~Revenue Recognition~~Credit Losses— In ~~May 2014, the FASB issued~~ ~~Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09)~~, which provides a new framework for the recognition of revenue. SPS expects its adoption will result in increased disclosures regarding revenue, cash flows and obligations related to arrangements with customers, as well as separate presentation of alternative revenue programs in the statements of income. SPS has not yet fully determined the impacts of adoption for several aspects of the standard, including a determination of whether receipts of non-refundable contributions in aid of construction should be recognized as revenues or may continue to be recorded as reductions to property, plant and equipment. Also, it is yet to be determined whether and how much an evaluation of the collectability of regulated electric revenues will impact the amounts of revenue recognized upon delivery. SPS currently expects to implement the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018, with the cumulative impact on contracts not yet completed as of Dec. 31, 2017 recognized as an adjustment to the opening balance of retained earnings.

~~Classification and Measurement of Financial Instruments —~~ ~~In January~~ 2016, the FASB issued ~~Recognition~~Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326), which changes how entities account for losses on receivables and ~~Measurement~~certain other assets. The guidance requires use of ~~Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01),~~a current expected credit loss model, which ~~among other changes~~may result in earlier recognition of credit losses than under previous accounting and disclosure requirements, replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes, and also eliminates the available-for-sale classification for marketable equity securities. Under the new guidance, other than when the consolidation or equity method of accountingstandards. ASC Topic 326 is ~~utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance will be~~ effective for interim and annual ~~reporting~~ periods beginning on or after Dec. 15, ~~2017.~~2019, and will be applied using a modified-retrospective approach, with a cumulative-effect adjustment to retained earnings as of Jan. 1, 2020. SPS ~~is currently evaluating~~expects the impact of ~~adopting ASU No. 2016-01 on its financial statements.~~

~~Leases —~~ ~~In February 2016,~~adoption of the ~~FASB issued~~ ~~Leases, Topic 842 (ASU No. 2016-02), which, for lessees, requires balance sheet~~new standard to include first-time recognition of ~~right-of-use assets~~expected credit losses (i.e., bad debt expense) on unbilled revenues, with the initial allowance established at Jan. 1, 2020 charged to retained earnings. Recognition of this allowance and ~~lease liabilities for all leases. Additionally, for leases that qualify as finance leases,~~other impacts of adoption are expected to be immaterial to the guidance requires expense recognition consisting of amortization of the right-of-use asset as well as interest on the related lease liability using the effective interest method. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018, and early adoption is permitted. SPS is currently evaluating the impact of adopting ASU No. 2016-02 on its financial statements.

Recently Adopted

~~Consolidation~~Leases —In ~~February 2015,~~2016, the FASB issued ~~Amendments to the Consolidation Analysis,~~ Leases, Topic ~~810 (ASU No. 2015-02)~~842(ASC Topic 842), which ~~reduces~~provides new accounting and disclosure guidance for leasing activities, most significantly requiring that operating leases be recognized on the ~~number of consolidation models and amends certain consolidation principles related to variable interest entities.~~balance sheet. SPS ~~implemented~~adopted the guidance on Jan. 1, ~~2016,~~2019 utilizing the package of transition practical expedients provided by the new standard, including carrying forward prior conclusions on whether agreements existing before the adoption date contain leases and whether existing leases are operating or finance leases; ASC Topic 842 refers to capital leases as finance leases.

Specifically for land easement contracts, SPS has elected the practical expedient provided by ASU No. 2018-01 Leases: Land Easement Practical Expedient for Transition to Topic 842, and as a result, only those easement contracts entered on or after Jan. 1, 2019 will be evaluated to determine if lease treatment is appropriate.

SPS also utilized the transition practical expedient offered by ASU No. 2018-11 Leases: Targeted Improvements to implement the standard on a prospective basis. As a result, reporting periods in the financial statements beginning Jan. 1, 2019 reflect the implementation of ASC Topic 842, while prior periods continue to be reported in accordance with Leases, Topic 840 (ASC Topic 840). Other than first-time recognition of operating leases on its balance sheet, the implementation of ASC Topic 842 did not have a significant impact on ~~its~~SPS’ financial statements. Adoption resulted in recognition of approximately $0.5 billion of operating lease ROU assets and current/noncurrent operating lease liabilities.

See Note 10 for leasing disclosures.

~~Presentation~~

3. Property, Plant and Equipment

Major classes of ~~Debt Issuance Costs~~— ~~In April 2015, the FASB issued~~ ~~Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03)~~, which requires the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of presentation as an asset. SPS implemented the new guidance as required on Jan. 1, 2016,property, plant and ~~as a result, $12.1 million of such deferred costs were retrospectively reclassified from other non-current assets to long-term debt on the balance sheet as of Dec. 31, 2015.~~equipment



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

~~Fair Value Measurement~~— ~~In May 2015, the FASB issued~~ ~~Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07),~~ which eliminates the requirement to categorize fair value measurements using a NAV methodology in the fair value hierarchy. SPS implemented the guidance on Jan. 1, 2016, and the implementation did not have a material impact on its financial statements. For related disclosures, see Note 7 to the financial statements.

~~Presentation of Deferred Taxes —~~ ~~In November 2015, the FASB issued~~ ~~Balance Sheet Classification of Deferred Taxes, Topic 740 (ASU No. 2015-17), which eliminates the requirement to present deferred tax~~

4. Regulatory Assets and Liabilities

Regulatory assets and liabilities ~~as current and noncurrent on~~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 ~~balance sheet based on the classification~~write-off of ~~the related asset or liability, and instead requires classification of all deferred tax~~regulatory assets and liabilities ~~as noncurrent. SPS early adopted the new guidance~~in net income or other comprehensive income if changes in the ~~fourth quarter~~utility industry no longer allow for the application of ~~2016 and as a result $35.7 million~~regulatory accounting guidance under GAAP.

Components of ~~current deferred income taxes were retrospectively reclassified to long-term deferred income tax liabilities on the balance sheet as of Dec. 31, 2015.~~regulatory assets:



(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2019				Dec. 31, 2018
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations	9	Various	$	11.1	$	203.5	$	12.6	$	222.1
Excess deferred taxes — TCJA	7	Various	1.7		52.0		—		55.9
Recoverable deferred taxes on AFUDC recorded in plant		Plant lives	—		34.1		—		27.9
Net AROs ^(a)	1, 10	Plant lives	—		26.9		—		25.7
Losses on reacquired debt		Term of related debt	0.8		21.0		0.8		21.9
Conservation programs ^(b)	1	One to two years	0.6		1.1		0.7		0.6
Other		Various	5.8		25.4		11.9		12.1
Total regulatory assets			$	20.0	$	364.0	$	26.0	$	366.2

~~Stock Compensation —~~ ~~In March 2016, the FASB issued~~ ~~Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU No. 2016-09),~~ which simplifies accounting and financial statement presentation for share-based payment transactions. The guidance requires that the difference between the tax deduction available upon settlement of share-based equity awards and the tax benefit accumulated over the vesting period be recognized as an adjustment to income tax expense. SPS adopted the guidance in 2016, and the implementation did not have a material impact on its financial statements.


3. ^(a)	~~Selected Balance Sheet Data~~Includes amounts recorded for future recovery of AROs.


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

(Thousands of Dollars) Dec. 31, 2016 Dec. 31, 2015
Accounts receivable, net
Accounts receivable $ 80,569
$ 77,054
Less allowance for bad debts (6,379 ) (5,888 )
$ 74,190
$ 71,166
Components of regulatory liabilities:

(Thousands of Dollars) Dec. 31, 2016 Dec. 31, 2015
Inventories
Materials and supplies $ 25,453
$ 24,888
Fuel 13,052
12,658
$ 38,505
$ 37,546

(Thousands of Dollars) Dec. 31, 2016 Dec. 31, 2015
Property, plant and equipment, net
Electric plant $ 6,362,189
$ 5,933,764
Construction work in progress 260,327
236,697
Total property, plant and equipment 6,622,516
6,170,461
Less accumulated depreciation (1,926,697 ) (1,821,638 )
$ 4,695,819
$ 4,348,823



(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2019				Dec. 31, 2018
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Deferred income tax adjustments and TCJA refunds ^(a)	7	Various	$	6.9	$	534.9	$	2.2	$	569.8
Plant removal costs	1, 10	Plant lives	—		174.5		—		187.7
Revenue subject to refund		One to two years	14.6		1.1		11.3		8.1
Gain from asset sales		Various	—		2.4		—		2.4
Deferred electric energy costs		Less than one year	81.6		—		56.5		—
Contract valuation adjustments ^(b)	1, 8	Less than one year	11.7		—		14.7		—
Other		Various	3.3		19.4		1.1		12.9
Total regulatory liabilities^(c)			$	118.1	$	732.3	$	85.8	$	780.9


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


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


^(c)	Revenue subject to refund of $3.9 million for 2019 and none for 2018 is included in other current liabilities.

At Dec. 31, 2019 and 2018, SPS’ regulatory assets not earning a return primarily included the unfunded portion of pension and retiree medical obligations and net AROs. In addition, SPS’ regulatory assets included $56.5 million and $50.5 million at Dec. 31, 2019 and 2018, respectively, of past expenditures not earning a return. Amounts primarily related to formula rates, losses on reacquired debt and certain rate case expenditures.

5. Borrowings and Other Financing Instruments

Short-Term Borrowings

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

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

Money pool borrowings for SPS were as follows:



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

(Amounts in Millions, Except Interest Rates) Three Months Ended Dec. 31, 2016
Borrowing limit $ 100
Amount outstanding at period end —
Average amount outstanding 20
Maximum amount outstanding 64
Weighted average interest rate, computed on a daily basis 0.83 %
Weighted average interest rate at period end N/A

(Amounts in Millions, Except Interest Rates) Twelve Months Ended Dec. 31, 2016 Twelve Months Ended Dec. 31, 2015 Twelve Months Ended Dec. 31, 2014
Borrowing limit $ 100
$ 100
$ 100
Amount outstanding at period end —
—
16
Average amount outstanding 28
21
9
Maximum amount outstanding 100
100
100
Weighted average interest rate, computed on a daily basis 0.67 % 0.40 % 0.22 %
Weighted average interest rate at end of period N/A
N/A
0.45

Commercial Paper — ~~SPS meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility.~~ Commercial paper outstanding for SPS was as follows:



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

(Amounts in Millions, Except Interest Rates) Three Months Ended Dec. 31, 2016
Borrowing limit $ 400
Amount outstanding at period end 50
Average amount outstanding 19
Maximum amount outstanding 75
Weighted average interest rate, computed on a daily basis 0.74 %
Weighted average interest rate at period end 0.95

(Amounts in Millions, Except Interest Rates) Twelve Months Ended Dec. 31, 2016 Twelve Months Ended Dec. 31, 2015 Twelve Months Ended Dec. 31, 2014
Borrowing limit $ 400
$ 400
$ 400
Amount outstanding at period end 50
15
37
Average amount outstanding 43
100
83
Maximum amount outstanding 140
246
241
Weighted average interest rate, computed on a daily basis 0.67 % 0.46 % 0.26 %
Weighted average interest rate at end of period 0.95
0.60
0.47

Letters of Credit — SPS may use letters of credit, ~~generally~~typically with terms of ~~one-year,~~one year, to provide financial guarantees for certain operating obligations. At Dec. 31, ~~2016~~2019 and ~~2015,~~2018, there were ~~$5.0 million and $7.0~~$2 million of letters of credit outstanding ~~respectively,~~ under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

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

Amended Credit Agreement— In June ~~2016,~~2019, SPS entered into an amended five-year credit agreement with a syndicate of banks. The ~~total borrowing limit under the~~ amended credit ~~agreement remained at $400 million. The amended credit agreement has~~agreements have substantially the same terms and conditions as the prior credit ~~agreement~~agreements with the ~~following exceptions:~~exception of the following:

~~The maturity~~Maturity extended from ~~October 2019~~June 2021 to June ~~2021~~.2024; and

Borrowing limit increased from $400 million to $500 million.

The ~~Eurodollar borrowing margins on this~~ line of credit ~~was reduced~~provides short-term financing in the form of notes payable to ~~a range of 75 to 150 basis points per year, from a range of 87.5 to 175 basis points per year, based upon applicable long-term credit ratings.~~

~~The commitment fees, calculated on the unused portion of the line~~banks, letters of credit ~~was reduced to a range of 6 to 22.5 basis points per year, from a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.~~and back-up support for commercial paper borrowings.

~~SPS has the right to request an extension of the 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:


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

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


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

The credit facility has a ~~financial covenant 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 47 percent and 46 percent at Dec. 31, 2016 and 2015, respectively.~~ an aggregate principal amount exceeding $75 million.

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

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

Dec. 31, 2019, SPS was in compliance with all financial ~~covenants on its debt agreements as of Dec. 31, 2016 and 2015.~~covenants.

~~At Dec. 31, 2016,~~ SPS had the following committed credit ~~facility~~facilities available ~~(in millions):~~as of Dec. 31, 2019.


Credit Facility ^(a)	Credit Facility ^(a)	Drawn ^(b)		Available		Drawn ^(b)	Available
$	400	$	55.0	$	345.0
$500						$2	$498


^(a)	This credit facility matures in June ~~2021.~~2024.


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

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. SPS had no0 direct advances on the ~~credit~~ facility outstanding at Dec. 31, ~~2016~~2019 and ~~2015.~~

2018.

Long-Term Borrowings and Other Financing Instruments

Generally, all ~~real and personal~~ property of SPS is subject to the lien of its first mortgage indenture. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses ~~associated 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 (millions of dollars):



Financing Instrument	Interest Rate		Maturity Date	2019			2018
First mortgage bonds	3.30	%	June 15, 2024	$	150		$	150
First mortgage bonds	3.30		June 15, 2024	200			200
Unsecured senior notes	6.00		Oct. 1, 2033	100			100
Unsecured senior notes	6.00		Oct. 1, 2036	250			250
First mortgage bonds	4.50		Aug. 15, 2041	200			200
First mortgage bonds	4.50		Aug. 15, 2041	100			100
First mortgage bonds	4.50		Aug. 15, 2041	100			100
First mortgage bonds	3.40		Aug. 15, 2046	300			300
First mortgage bonds	3.70		Aug. 15, 2047	450			450
First mortgage bonds ^(b)	4.40		Nov. 15, 2048	300			300
First mortgage bonds ^(a)	3.75		June 15, 2049	300			—
Unamortized discount				(7		)	(4		)
Unamortized debt issuance cost				(23		)	(20		)
Total long-term debt				$	2,420		$	2,126


^(a)	2019 financing


^(b)	2018 financing

Maturities of long-term debt:



(Millions of Dollars)
2020	$	—
2021	—
2022	—
2023	—
2024	350

~~In 2016, SPS issued $300 million of 3.4 percent first mortgage bonds due Aug. 15, 2046. In 2015, SPS issued $200 million of 3.3 percent first mortgage bonds due June 15, 2024.~~

~~During the next five years, SPS has long-term debt maturities of $250 million due in 2018.~~

Deferred Financing Costs— Deferred financing costs of approximately ~~$14.5~~$23 million and ~~$12.1~~$20 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, ~~2016~~2019 and ~~2015,~~2018, respectively. SPS is amortizing these financing costs over the remaining maturity periods of the related debt.

Capital Stock — SPS has the following preferred stock:



Preferred Stock Authorized (Shares)	Par Value of Preferred Stock	Preferred Stock Outstanding (Shares) 2019 and 2018
10,000,000	1.00	—

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

~~The most restrictive dividend limitation for~~earnings. SPS is ~~imposed by its state regulatory commissions.~~ required to be current on particular interest payments before dividends can be paid.

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

Requirements and actuals as of ~~dividends that SPS can pay Xcel Energy Inc. by requiring an equity-to-total capitalization ratio (excluding short-term debt) between 45.0 percent and 55.0 percent. In addition,~~Dec. 31, 2019:



Equity to Total Capitalization Ratio - Required Range				Equity to Total Capitalization Ratio - Actual ^(a)
Low		High		2019
45.0	%	55.0	%	54.4	%


^(a)	Excludes short-term debt.



Unrestricted Retained Earnings			Total Capitalization			Limit on Total Capitalization ^(a)
$	535.0	million	$	5.3	billion	N/A

^(a) SPS may not pay a dividend that would cause it to lose its investment grade bond rating. ~~SPS’ equity-to-total capitalization ratio (excluding short-term debt) was 54.1 percent at Dec. 31, 2016 and $487 million in retained earnings was not restricted.~~


5.	~~Preferred Stock~~

~~SPS has authorized the issuance of preferred stock.~~

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

6. Revenues

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



(Millions of Dollars)	Year Ended Dec. 31, 2019
Major product lines
Revenue from contracts with customers:
Residential	$	351.9
C&I	800.3
Other	41.1
Total retail	1,193.3
Wholesale	361.0
Transmission	239.6
Other	3.3
Total revenue from contracts with customers	1,797.2
Alternative revenue and other	28.6
Total revenues	$	1,825.8



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

7. Income Taxes

~~Consolidated Appropriations Act, 2016~~Federal Tax Reform—In ~~December 2015,~~2017, the ~~Consolidated Appropriations Act, 2016 (Act)~~TCJA was signed into law. The ~~Act provides~~key provisions impacting Xcel Energy (which includes SPS), generally beginning in 2018, included:

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

Normalization of resulting plant-related excess deferred taxes;

Elimination of the corporate alternative minimum tax;

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

Limitations on certain executive compensation deductions;

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

Repeal of the ~~following:~~section 199 manufacturing deduction; and

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

~~Immediate expensing, or “bonus depreciation,”~~Xcel Energy estimated the effects of ~~50 percent~~the TCJA, which have been reflected in the consolidated financial statements.

Reductions in deferred tax assets and liabilities due to a decrease in corporate federal tax rates typically result in a net tax benefit. However, the impacts are primarily recognized as regulatory liabilities refundable to utility customers as a result of IRS requirements and past regulatory treatment.

Estimated impacts of the new tax law for ~~property placed~~SPS in ~~service in 2015, 2016, and 2017; 40 percent~~December 2017 included:

$426 million ($559 million grossed-up for ~~property placed in service in 2018; and 30 percent for property placed in service in 2019. Additionally, some longer production period property placed in service in 2020~~tax) of reclassifications of plant-related excess deferred taxes to regulatory liabilities upon valuation at the new 21% federal rate. The regulatory liabilities will be ~~eligible for bonus depreciation;~~

~~PTCs at 100 percent~~amortized consistent with IRS normalization requirements, resulting in customer refunds over the average remaining life of the ~~credit rate ($0.023 per KWh)~~related property;

$45 million and $28 million of reclassifications (grossed-up for ~~wind energy projects that begin construction by the end~~tax) of ~~2016; 80 percent~~excess deferred taxes for non-plant related deferred tax assets and liabilities, respectively, to regulatory assets and liabilities; and

$8 million 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~~total estimated income tax ~~on certain employer-provided health insurance plans.~~

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

~~Tax Increase Prevention Act of 2014~~— ~~In 2014, the Tax Increase Prevention Act (TIPA) was signed into law. The TIPA provides for the following:~~

~~The R&E credit was extended for 2014;~~

~~PTCs were extended for projects that began construction before the end of 2014 with certain projects qualifying into future years; and~~

~~50 percent bonus depreciation was extended one year through 2014. Additionally, some longer production period property placed in service in 2015 is also eligible for 50 percent bonus depreciation.~~

~~The accounting~~$2 million reduction to net income related to the ~~TIPA was recorded beginning in~~allocation of Xcel Energy Services Inc.’s tax rate change on its deferred taxes.

Xcel Energy accounted for the ~~fourth quarter~~state tax impacts of ~~2014 because a change in~~federal tax reform based on enacted state tax laws. Any future state tax law ischanges related to the TCJA will be accounted for in the ~~period of enactment.~~periods state laws are enacted.

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



Tax Year(s)		Expiration
2009 - 2013		June 2020
2014 - 2016		September 2020

In ~~2012,~~2015, the IRS commenced an examination of tax years ~~2010~~2012 and ~~2011, including~~2013. In 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy filed a ~~2009 carryback claim.~~protest with the IRS. As of Dec. 31, ~~2016,~~2019, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result 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 IRScase has been forwarded ~~the issue~~ to the Office of Appeals ~~(Appeals). In 2016 the IRS audit team~~ and Xcel Energy presented their cases to Appeals; however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy’s 2009 through 2011 federal income tax returns, following extensions, expires in December 2017. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of ~~the IRS’ proposed adjustment of the carryback claims. SPS is not expected to accrue any income tax expense related to~~ this ~~adjustment.~~

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of Dec. 31, 2016, the IRS had not proposed any material adjustments to tax years 2012 and 2013. Subsequent to year-end, the IRS proposed an adjustment to tax years 2012 through 2013 that may impact Xcel Energy’s NOL and tax credit carryforwards and ETR. However, Xcel Energy is continuing to evaluate the IRS’ proposal andissue; however, the outcome and timing of a resolution is ~~uncertain.~~unknown.

In 2018, the IRS began an audit of tax years 2014 - 2016. As of Dec. 31, 2019 0 adjustments have been proposed.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, ~~2016,~~2019, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. ~~In February 2016, Texas began an audit of years 2009 and 2010. As of Dec. 31, 2016, Texas had not proposed any adjustments, and there were~~There are currently no ~~other~~ state income tax audits in 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, 2019		Dec. 31, 2018
Unrecognized tax benefit — Permanent tax positions	$	3.7	$	3.0
Unrecognized tax benefit — Temporary tax positions	1.5		1.5
Total unrecognized tax benefit	$	5.2	$	4.5

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



(Millions of Dollars)	2019			2018			2017
Balance at Jan. 1	$	4.5		$	4.3		$	28.7
Additions based on tax positions related to the current year	0.7			0.6			0.9
Reductions based on tax positions related to the current year	(0.1		)	(0.1		)	(0.6		)
Additions for tax positions of prior years	0.2			0.1			1.3
Reductions for tax positions of prior years	(0.1		)	(0.3		)	(19.9		)
Settlements with taxing authorities	—			(0.1		)	(6.1		)
Balance at Dec. 31	$	5.2		$	4.5		$	4.3

(Millions of Dollars) Dec. 31, 2016 Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions $ 4.5
$ 2.6
Unrecognized tax benefit — Temporary tax positions 24.2
22.1
Total unrecognized tax benefit $ 28.7
$ 24.7

~~A reconciliation of the beginning and ending amount of unrecognized~~Unrecognized tax ~~benefit is as follows:~~

(Millions of Dollars) 2016 2015 2014
Balance at Jan. 1 $ 24.7
$ 13.2
$ 4.1
Additions based on tax positions related to the current year 1.4
4.2
8.6
Reductions based on tax positions related to the current year —
(0.6 ) —
Additions for tax positions of prior years 3.9
9.0
2.3
Reductions for tax positions of prior years (1.3 ) (1.1 ) (0.3 )
Settlements with taxing authorities —
—
(0.2 )
Lapse of applicable statutes of limitations —
—
(1.3 )
Balance at Dec. 31 $ 28.7
$ 24.7
$ 13.2

~~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, 2019			Dec. 31, 2018
NOL and tax credit carryforwards	$	(4.4	)	$	(3.8	)

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 $1.4 million and $0.8 million at Dec. 31, 2019 and Dec. 31, 2018, respectively.

(Millions of Dollars) Dec. 31, 2016 Dec. 31, 2015
NOL and tax credit carryforwards $ (5.9 ) $ (5.0 )

~~It is reasonably possible that SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as~~As the IRS Appeals and ~~audit progress, the Texas~~federal audit progresses and ~~other~~ state audits ~~resume. As the IRS Appeals, IRS audit, and Texas audit progress,~~resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately ~~$10 million.~~$3.7 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)	2019		2018		2017
Receivable (payable) for interest related to unrecognized tax benefits at Jan. 1	$	0.7	$	0.5	$	(0.9	)
Interest income related to unrecognized tax benefits	—		0.2		1.4
Receivable for interest related to unrecognized tax benefits at Dec. 31	$	0.7	$	0.7	$	0.5

(Millions of Dollars) 2016 2015 2014
Payable for interest related to unrecognized tax benefits at Jan. 1 $ —
$ (0.1 ) $ —
Interest (expense) income related to unrecognized tax benefits (0.9 ) 0.1
(0.1 )
Payable for interest related to unrecognized tax benefits at Dec. 31 $ (0.9 ) $ —
$ (0.1 )

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, ~~2016, 2015,~~2019, 2018, or ~~2014.~~2017.

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



(Millions of Dollars)	2019		2018
Federal tax credit carryforwards	$	29.5	$	5.7
State NOL carryforwards	1.2		2.9

(Millions of Dollars) 2016 2015
Federal NOL carryforward $ 275
$ 306
Federal tax credit carryforwards 4
3
State NOL carryforwards 60
79
Valuation allowances for state NOL carryforwards —
(11 )

~~The federal~~Federal carryforward periods expire between ~~2021~~2024 and ~~2036. The~~2039 and state carryforward periods expire between ~~2017~~2025 and ~~2035.~~

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:



	2019		2018 ^(a)		2017 ^(a)
Federal statutory rate	21.0	%	21.0	%	35.0	%
State income tax on pretax income, net of federal tax effect	2.2	%	2.3	%	2.0	%
Increases (decreases) in tax from:
Wind PTCs	(7.9	)	—		—
Plant regulatory differences ^(b)	(5.0	)	(4.8	)	(0.9	)
Amortization of excess nonplant deferred taxes	(0.9	)	(1.2	)	—
Other tax credits, net of NOL & tax credit allowances	(0.6	)	(0.7	)	(0.6	)
Adjustments attributable to tax returns	(0.1	)	(1.5	)	(0.4	)
Change in unrecognized tax benefits	0.2		0.1		(1.0	)
Tax reform	—		—		(3.5	)
Other, net	—		0.2		(0.5	)
Effective income tax rate	8.9	%	15.4	%	30.1	%


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


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

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

2016 2015 2014
Federal statutory rate 35.0 % 35.0 % 35.0 %
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit 1.5
2.6
3.4
Change in unrecognized tax benefits 0.8
0.5
0.2
Regulatory differences — utility plant items (1.0 ) (0.8 ) (1.6 )
Tax credits recognized, net of federal income tax expense (0.5 ) (0.3 ) (0.4 )
Other, net (0.7 ) 0.1
0.1
Effective income tax rate 35.1 % 37.1 % 36.7 %



(Millions of Dollars)	2019			2018			2017
Current federal tax (benefit) expense	$	(3.9	)	$	12.3		$	(20.9	)
Current state tax expense (benefit)	0.6			2.3			(12.8		)
Current change in unrecognized tax expense (benefit)	—			2.3			(24.3		)
Deferred federal tax expense	22.3			20.5			89.9
Deferred state tax expense	6.0			3.6			14.5
Deferred change in unrecognized tax expense (benefit)	0.7			(2.0		)	22.1
Deferred ITCs	(0.1		)	(0.1		)	(0.1		)
Total income tax expense	$	25.6		$	38.9		$	68.4

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

(Thousands of Dollars) 2016 2015 2014
Current federal tax benefit $ (40,853 ) $ (1,327 ) $ (57,201 )
Current state tax (benefit) expense (2,929 ) 2,448
2,512
Current change in unrecognized tax expense 3,126
11,281
6,715
Deferred federal tax expense 116,404
67,640
121,882
Deferred state tax expense 7,757
5,399
8,025
Deferred change in unrecognized tax benefit (1,178 ) (10,203 ) (6,390 )
Deferred investment tax credits (213 ) (213 ) (341 )
Total income tax expense $ 82,114
$ 75,025
$ 75,202

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



(Millions of Dollars)	2019			2018			2017
Deferred tax expense (benefit) excluding items below	$	52.7		$	44.2		$	(414.2	)
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(23.8		)	(22.0		)	540.7
Tax benefit (expense) allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other	0.1			(0.1		)	—
Deferred tax expense	$	29.0		$	22.1		$	126.5

(Thousands of Dollars) 2016 2015 2014
Deferred tax expense excluding items below $ 128,393
$ 63,453
$ 124,875
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (5,416 ) (780 ) (1,262 )
Tax benefit (expense) allocated to other comprehensive income and other 6
163
(96 )
Deferred tax expense $ 122,983
$ 62,836
$ 123,517

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


(Thousands of Dollars)		2016		2015
(Millions of Dollars)						2019		2018 ^(a)
Deferred tax liabilities:
Differences between book and tax bases of property		$	1,034,675	$	945,142	$	758.7	$	680.6
Employee benefits		42,239		50,097
Other		35,975		18,260
Operating lease assets						115.8		—
Regulatory assets						49.7		49.2
Pension expense						33.1		32.3
Total deferred tax liabilities	��	$	1,112,889	$	1,013,499	$	957.3	$	762.1

Deferred tax assets:
Regulatory liabilities						$	111.2	$	116.8
Operating lease liabilities						115.8		—
Tax credit carryforward						29.5		5.7
Deferred fuel costs						18.3		12.7
Other employee benefits						5.8		5.6
NOL carryforward		$	100,179	$	112,060	0.1		0.2
Deferred fuel costs		10,226		23,127
Regulatory liabilities		3,380		10,480
Other		9,967		7,088		4.8		2.0
Total deferred tax assets		$	123,752	$	152,755	285.5		143.0
Net deferred tax liability		$	989,137	$	860,744	$	671.8	$	619.1

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


7.
~~Benefit Plans~~8. Fair Value of Financial Assets and ~~Other Postretirement Benefits~~Liabilities

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 67 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2016, SPS had 833 bargaining employees covered under a collective-bargaining agreement, which expired in October 2014. While collective bargaining is ongoing, the terms and conditions of the expired agreement are automatically extended.

Fair Value Measurements

The ~~plans invest in various instruments which are disclosed under the~~ accounting guidance for fair value measurements ~~which establishes~~and disclosures provides a single definition of fair value and requires disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair ~~value. The three levels in the hierarchy and examples of each level are as follows:~~

value is established by this guidance.

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

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

inputs; and

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

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

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

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

~~Derivative Instruments~~ —~~Fair values for foreign currency derivatives are determined using pricing models based on the prevailing forward exchange rate of the underlying currencies.~~ The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

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

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

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of important inputs to the value of FTRs between auction processes, including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3. Non-trading monthly FTR settlements are expected to be recovered through fuel and purchased energy cost recovery mechanisms, and therefore changes in the fair value of the yet to be settled portions of FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of SPS, the numerous unobservable quantitative inputs pertinent to the value of FTRs are immaterial to the financial statements of SPS.

Derivative Fair Value Measurements

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

~~Pension Benefits~~

Interest Rate Derivatives — SPS may enter into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes. As of Dec. 31, 2019, accumulated other comprehensive losses related to interest rate derivatives included $0.1 million net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

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

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

Gross notional amounts of commodity FTRs at Dec. 31, 2019 and 2018:


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

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

SPS’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. At Dec. 31, 2019, 3 of the 10 most significant counterparties for these activities, comprising $12.2 million or 35% of this credit exposure, had investment grade ratings from Standard & Poor’s, Moody’s or Fitch Ratings. NaN of the 10 most significant counterparties, comprising $22.1 million or 65% of this credit exposure, were not rated by external rating agencies, but based on SPS’ internal analysis, had credit quality consistent with investment grade. NaN of these significant counterparties, comprising $0.1 million or less than 1% of this credit exposure, had credit quality less than investment grade, based on internal analysis. NaN of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.

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



(Millions of Dollars)	2019			2018			2017
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(0.7	)	$	(0.8	)	$	(0.7	)
After-tax net realized losses on derivative transactions reclassified into earnings	—			0.1			—
Adoption of ASU. 2018-02 ^(a)	—			—			(0.1		)
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(0.7	)	$	(0.7	)	$	(0.8	)


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

Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were immaterial, $0.1 million and $0.1 million for the years ended Dec. 31, 2019, 2018 and 2017, respectively.

Changes in the fair value of FTRs resulting in pre-tax net gains of $6.5 million, $7.0 million and $0.5 million recognized for the years ended Dec. 31, 2019, 2018 and 2017, respectively, were reclassified as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on expected recovery of FTR settlements through fuel and purchased energy cost recovery mechanisms.

FTR settlement gains of $6.0 million, $4.4 million and $0.8 million were recognized for the years ended Dec. 31, 2019, 2018 and 2017, respectively, and were recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

SPS had 0 derivative instruments designated as fair value hedges during the years ended Dec. 31, 2019, 2018 and 2017.

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



	Dec. 31, 2019												Dec. 31, 2018
	Fair Value												Fair Value
(Millions of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Netting ^(a)		Total		Level 1		Level 2		Level 3		Fair Value Total		Netting ^(a)			Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	11.8	$	11.8	$	—	$	11.8	$	—	$	—	$	14.9	$	14.9	$	(0.2	)	$	14.7
Total current derivative assets	$	—	$	—	$	11.8	$	11.8	$	—	11.8		$	—	$	—	$	14.9	$	14.9	$	(0.2	)	14.7
PPAs ^(b)											3.2													3.1
Current derivative instruments											$	15.0												$	17.8
Noncurrent derivative assets
PPAs ^(b)											12.6													15.8
Noncurrent derivative instruments											$	12.6												$	15.8
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	0.1	$	0.1	$	—	$	0.1	$	—	$	—	$	0.2	$	0.2	$	(0.2	)	$	—
Total current derivative liabilities	$	—	$	—	$	0.1	$	0.1	$	—	0.1		$	—	$	—	$	0.2	$	0.2	$	(0.2	)	—
PPAs ^(b)											3.6													3.6
Current derivative instruments											$	3.7												$	3.6
Noncurrent derivative liabilities
PPAs ^(b)											12.8													16.4
Noncurrent derivative instruments											$	12.8												$	16.4

^(a)

SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2019 and 2018. At both Dec. 31, 2019 and 2018, derivative assets and liabilities include 0 obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.


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

Changes in Level 3 commodity derivatives for the years ended Dec. 31, 2019, 2018 and 2017:



	Year Ended Dec. 31
(Millions of Dollars)	2019			2018			2017
Balance at Jan. 1	$	14.7		$	12.7		$	2.0
Purchases	26.7			32.3			41.2
Settlements	(34.2		)	(41.6		)	(55.8		)
Net transactions recorded during the period:
Net gains recognized as regulatory assets	4.5			11.3			25.3
Balance at Dec. 31	$	11.7		$	14.7		$	12.7

SPS recognizes transfers between levels as of the beginning of each period. There were 0 transfers of amounts between levels for derivative instruments for 2017 – 2019.

Fair Value of Long-Term Debt

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



	2019				2018
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	2,419.7	$	2,706.1	$	2,126.1	$	2,139.8

Fair value of SPS’ long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of Dec. 31, 2019 and 2018, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.

9. Benefit Plans and Other Postretirement Benefits

Pension and Postretirement Health Care Benefits

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

In addition to the qualified pension plans, Xcel Energy maintains a ~~supplemental executive retirement plan (SERP)~~SERP and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides ~~unfunded, nonqualified~~ benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions ~~attributable to SPS~~ funded by ~~SPS’~~Xcel Energy’s consolidated operating cash flows. ~~The total obligations~~Obligations of the SERP and nonqualified plan as of Dec. 31, ~~2016~~2019 and ~~2015~~2018 were ~~$43.5~~$39 million and ~~$41.8~~$33 million, respectively, of which ~~$2.5~~$2 million ~~and $2.6 million were~~was attributable to ~~SPS.~~SPS in both years. In ~~2016~~2019 and ~~2015,~~2018, Xcel Energy recognized net benefit cost for ~~financial reporting for~~ the SERP and nonqualified plans of ~~$7.9~~$4 million in 2019 and ~~$9.5 million, respectively,~~2018, of which ~~$0.2 million and $0.3 million~~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~~which includes SPS, ~~base~~bases the investment-return assumption on expected long-term performance for each of the ~~investment types included~~asset classes in ~~the~~its pension ~~asset portfolio~~ and ~~consider~~postretirement health care portfolios. For pension assets, Xcel Energy considers the historical returns achieved by ~~the~~its asset portfolio over the past ~~20-year~~20 years or longer period, as well as ~~the~~ long-term projected return ~~levels projected and recommended by investment experts.~~levels. Xcel Energy ~~Inc.~~ and SPS continually review ~~the~~ pension assumptions. ~~The pension~~

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

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

Investment returns in ~~2016~~2018 were below the assumed level of ~~6.78 percent;~~6.78%;

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

~~Investment returns in 2014~~2017 were above the assumed level of ~~6.90 percent;~~6.78%; and

In ~~2017, SPS’~~2020, Xcel Energy’s expected investment-return assumption is ~~6.80 percent.~~6.78%.

~~The~~Pension plan and postretirement benefit assets are invested in a portfolio according to Xcel ~~Energy Inc.’s and SPS’~~Energy’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize ~~the necessity of~~ contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the ~~projected~~asset allocation ~~of assets to selected asset classes,~~ 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 ~~pension~~the assets in any year.

~~The following table presents~~State agencies also have issued guidelines to the ~~target pension asset allocations~~funding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for ~~SPS at Dec. 31~~Texas and New Mexico amounts collected in rates. These assets are invested in a manner consistent with the investment strategy for the ~~upcoming year:~~pension plan.

2016 2015
Domestic and international equity securities 36 % 36 %
Long-duration fixed income and interest rate swap securities 31
31
Short-to-intermediate fixed income securities 15
12
Alternative investments 16
19
Cash 2
2
Total 100 % 100 %

~~The~~Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. ~~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~~For each of the fair value hierarchy levels, SPS’ pension plan assets ~~that are~~ measured at fair ~~value as of Dec. 31, 2016 and 2015:~~value:



	Dec. 31, 2019 ^(a)													Dec. 31, 2018 ^(a)
(Millions of Dollars)	Level 1			Level 2		Level 3		Measured at NAV			Total			Level 1		Level 2		Level 3		Measured at NAV			Total
Cash equivalents	$	18.9		$	—	$	—	$	—		$	18.9		$	21.6	$	—	$	—	$	—		$	21.6
Commingled funds	202.5			—		—		144.8			347.3			128.6		—		—		132.5			261.1
Debt securities	—			98.2		0.6		—			98.8			—		98.1		—		—			98.1
Equity securities	12.1			—		—		—			12.1			14.4		—		—		—			14.4
Other	(16.8		)	0.7		—		(2.8		)	(18.9		)	0.2		0.8		—		(4.0		)	(3.0		)
Total	$	216.7		$	98.9	$	0.6	$	142.0		$	458.2		$	164.8	$	98.9	$	—	$	128.5		$	392.2

Dec. 31, 2016
(Thousands of Dollars) Level 1 Level 2 Level 3
Investments Measured at NAV ^(a)
Total
Cash equivalents $ 29,237
$ —
$ —
$ —
$ 29,237
Commingled funds:
U.S. equity funds —
—
—
62,899
62,899
Non U.S. equity funds —
—
—
46,403
46,403
U.S. corporate bond funds —
—
—
41,226
41,226
Emerging market equity funds —
—
—
24,637
24,637
Emerging market debt funds —
—
—
20,399
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 $ 39,714
$ 78,664
$ —
$ 262,017
$ 380,395


^(a)	~~Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy.~~ See Note 28 for further information on ~~the adoption of ASU No. 2015-07.~~fair value measurement inputs and methods.

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

Dec. 31, 2015
(Thousands of Dollars) Level 1 Level 2 Level 3
Investments Measured at NAV ^(a)
Total
Cash equivalents $ 22,999
$ —
$ —
$ —
$ 22,999
Derivatives —
553
—
—
553
Commingled funds:
U.S. equity funds —
—
—
55,533
55,533
Non U.S. equity funds —
—
—
53,449
53,449
U.S. corporate bond funds —
—
—
32,020
32,020
Emerging market equity funds —
—
—
23,891
23,891
Emerging market debt funds —
—
—
23,169
23,169
Commodity funds —
—
—
7,884
7,884
Private equity investments —
—
—
19,114
19,114
Real estate —
—
—
27,690
27,690
Other commingled funds —
—
—
29,793
29,793
Debt securities:
Government securities —
37,495
—
—
37,495
U.S. corporate bonds —
28,826
—
—
28,826
Non U.S. corporate bonds —
4,626
—
—
4,626
Asset-backed securities —
323
—
—
323
Equity securities:
U.S. equities 13,492
—
—
—
13,492
Other —
(1,944 ) —
—
(1,944 )
Total $ 36,491
$ 69,879
$ —
$ 272,543
$ 378,913



	Dec. 31, 2019 ^(a)										Dec. 31, 2018 ^(a)
(Millions of Dollars)	Level 1		Level 2		Level 3		Measured at NAV		Total		Level 1		Level 2		Level 3		Measured at NAV		Total
Cash equivalents	$	2.2	$	—	$	—	$	—	$	2.2	$	1.8	$	—	$	—	$	—	$	1.8
Insurance contracts	—		4.9		—		—		4.9		—		4.3		—		—		4.3
Commingled funds:	6.7		—		—		7.4		14.1		12.8		—		—		3.8		16.6
Debt securities:	—		22.1		0.1		—		22.2		—		17.2		—		—		17.2
Equity securities:	—		—		—		—		—		—		—		—		—		—
Other	—		0.2		—		—		0.2		—		0.1		—		—		0.1
Total	$	8.9	$	27.2	$	0.1	$	7.4	$	43.6	$	14.6	$	21.6	$	—	$	3.8	$	40.0


^(a)	~~Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy.~~ See Note 28 for further information on ~~the adoption of ASU No. 2015-07.~~fair value measurement inputs and methods.

~~There~~Immaterial assets were ~~no assets~~ transferred in or out of Level 3 for ~~the years ended Dec. 31, 2016, 2015~~2019. No assets were transferred in or ~~2014.~~out of Level 3 for 2018.

~~Benefit Obligations~~Funded Status — ~~A comparison~~Comparisons of the actuarially computed ~~pension~~ benefit obligation, ~~and~~changes in plan assets and funded status of the pension and postretirement health care plans for ~~SPS is~~Xcel Energy are presented in the following table:

(Thousands of Dollars) 2016 2015
Accumulated Benefit Obligation at Dec. 31 $ 453,317
$ 429,726

Change in Projected Benefit Obligation:
Obligation at Jan. 1 $ 467,394
$ 500,690
Service cost 9,761
11,006
Interest cost 21,259
20,184
Actuarial loss (gain) 25,053
(35,154 )
Transfer to other plan (3,305 ) (2,843 )
Benefit payments (36,561 ) (26,489 )
Obligation at Dec. 31 $ 483,601
$ 467,394

(Thousands of Dollars) 2016 2015
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1 $ 378,913
$ 402,269
Actual return (loss) on plan assets 23,306
(6,013 )
Employer contributions 18,088
11,651
Transfer to other plan (3,351 ) (2,505 )
Benefit payments (36,561 ) (26,489 )
Fair value of plan assets at Dec. 31 $ 380,395
$ 378,913

(Thousands of Dollars) 2016 2015
Funded Status of Plans at Dec. 31:
Funded status ^(a)
$ (103,206 ) $ (88,481 )



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


^(a)	~~Amounts are recognized~~Includes approximately $6.8 million in ~~noncurrent liabilities on SPS’ balance sheets.~~2019 and $6.9 million in 2018, of lump-sum benefit payments used in the determination of a settlement charge.

Accumulated benefit obligation for the pension plan was $481.1 million and $445.8 million as of Dec. 31, 2019 and 2018, respectively.

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

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

(Thousands of Dollars) 2016 2015
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss $ 247,381
$ 236,107



	Pension Benefits									Postretirement Benefits
(Millions of Dollars)	2019			2018			2017			2019			2018			2017
Service cost	$	8.8		$	9.7		$	9.8		$	0.9		$	1.1		$	0.9
Interest cost	20.1			18.4			19.7			1.7			1.6			1.7
Expected return on plan assets	(28.6		)	(28.3		)	(27.9		)	(2.0		)	(2.5		)	(2.4		)
Amortization of prior service credit	(0.1		)	(0.1		)	—			(0.5		)	(0.4		)	(0.4		)
Amortization of net loss	11.3			14.1			13.0			(0.4		)	(0.4		)	(0.6		)
Settlement charge ^(a)	2.4			3.2			—			—			—			—
Net periodic pension cost (credit)	13.9			17.0			14.6			(0.3		)	(0.6		)	(0.8		)
Costs not recognized due to effects of regulation	0.9			(2.2		)	0.3			—			—			—
Net benefit cost (credit) recognized for financial reporting	$	14.8		$	14.8		$	14.9		$	(0.3	)	$	(0.6	)	$	(0.8	)
Significant Assumptions Used to Measure Costs:
Discount rate	4.31		%	3.63		%	4.13		%	4.32		%	3.62		%	4.13		%
Expected average long-term increase in compensation level	3.75			3.75			3.75			—			—			—
Expected average long-term rate of return on assets	6.78			6.78			6.78			5.30			5.80			5.80

^(a)

A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2019 and 2018, as a result of lump-sum distributions during the 2019 and 2018 plan years, SPS recorded a total pension settlement charge of $2.4 million and $3.2 million in 2019 and 2018, respectively. A total of $0.6 million and $0.7 million of that amount was recorded in the income statement in 2019 and 2018, respectively.


(Thousands of Dollars)	2016		2015
					Pension Benefits						Postretirement Benefits
(Millions of Dollars)					2019			2018			2019			2018
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss					$	209.7		$	230.9		$	(11.9	)	$	(9.6	)
Prior service credit					(1.1		)	(1.2		)	(1.4		)	(1.8		)
Total					$	208.6		$	229.7		$	(13.3	)	$	(11.4	)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	13,524	$	13,690	$	11.0		$	12.9		$	—		$	—
Noncurrent regulatory assets	233,857		222,417		197.6			216.8			—			—
Current regulatory liabilities					—			—			(0.8		)	(0.9		)
Noncurrent regulatory liabilities					—			—			(12.5		)	(10.5		)
Total	$	247,381	$	236,107	$	208.6		$	229.7		$	(13.3	)	$	(11.4	)



Measurement date	Dec. 31, ~~2016~~2019	Dec. 31, ~~2015~~2018	Dec. 31, 2019	Dec. 31, 2018

2016 2015
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation 4.13 % 4.66 %
Expected average long-term increase in compensation level 3.75
4.00
Mortality table RP-2014
RP-2014

~~Mortality~~ — In 2014, the Society of Actuaries published a new mortality table (RP-2014) and projection scale (MP-2014) that increased the overall life expectancy of males and females. On Dec. 31, 2014 SPS adopted the RP-2014 table, with modifications, based on its population and specific experience and a modified MP-2014 projection scale. During 2016, a new projection table was released (MP-2016). In 2016, SPS adopted a modified version of the MP-2016 table and will continue to utilize the RP-2014 base table, modified for company experience.

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 ~~2014 through~~ 2017 - 2020 to meet minimum funding requirements.

Total voluntary and required pension funding contributions across all ~~four~~4 of Xcel Energy’s pension plans were as follows:

$~~150.0~~150 million in January ~~2017,~~2020, of which ~~$23.0~~$14 million was attributable to SPS;

$~~125.2~~154 million in ~~2016,~~2019, of which ~~$18.1~~$18 million was attributable to ~~SPS~~SPS;

$~~90.1~~150 million in ~~2015,~~2018, of which ~~$11.7~~$8 million was attributable to SPS; and

$~~130.6~~162 million in ~~2014,~~2017, of which ~~$4.9~~$24 million was attributable to SPS.

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

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

Expects to contribute approximately $10 million during 2020;

$15 million during 2019;

$11 million during 2018;

$20 million during 2017; and

Amounts attributable to SPS were immaterial.

Target asset allocations:



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

Plan Amendments —Xcel Energy, which includes SPS, amended the Xcel Energy Inc. Nonbargaining Pension Plan (South) in 2017 to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans.

In ~~2016~~2019 and ~~2015,~~2018, there were no plan amendments made which affected the benefit obligation.

Projected Benefit Payments

~~Benefit Costs~~ —~~The components of~~ SPS’ ~~net periodic pension cost were:~~projected benefit payments:



(Millions of Dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
2020	$	30.7	$	2.9	$	—	$	2.9
2021	29.4		2.9		—		2.9
2022	30.3		2.9		—		2.9
2023	30.4		2.9		—		2.9
2024	30.4		2.8		—		2.8
2025-2029	153.5		13.2		0.1		13.1

(Thousands of Dollars) 2016 2015 2014
Service cost $ 9,761
$ 11,006
$ 9,184
Interest cost 21,259
20,184
20,444
Expected return on plan assets (27,602 ) (28,610 ) (26,179 )
Amortization of prior service cost —
39
54
Amortization of net loss 11,986
15,087
13,326
Net periodic pension cost 15,404
17,706
16,829
Credits not recognized due to effects of regulation 2,042
2,597
3,170
Net benefit cost recognized for financial reporting $ 17,446
$ 20,303
$ 19,999

2016 2015 2014
Significant Assumptions Used to Measure Costs:
Discount rate 4.66 % 4.11 % 4.75 %
Expected average long-term increase in compensation level 4.00
3.75
3.75
Expected average long-term rate of return on assets 6.78
7.22
6.90

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 $4.4 million, $4.8 million and $4.1 million in 2016, 2015 and 2014, 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 2017 pension cost calculations is 6.80 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~~most employees. The expense to these plans for SPS was approximately ~~$2.8~~$3 million in ~~2016,~~2019, 2018 and ~~$2.6 million in 2015 and 2014.~~2017.

~~Postretirement Health Care Benefits~~

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

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

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

~~The following table presents the target postretirement asset allocations for Xcel Energy Inc. and SPS at Dec. 31 for the upcoming year:~~

2016 2015
Domestic and international equity securities 25 % 25 %
Short-to-intermediate fixed income securities 57
57
Alternative investments 13
13
Cash 5
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 the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected allocation of assets to selected asset classes, 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, 2016 and 2015:

Dec. 31, 2016
(Thousands of Dollars) Level 1 Level 2 Level 3
Investments Measured at NAV ^(a)

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 $ 5,885
$ 20,442
$ —
$ 15,970
$ 42,297


^(a)	Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

Dec. 31, 2015
(Thousands of Dollars) Level 1 Level 2 Level 3
Investments Measured at NAV ^(a)

Total
Cash equivalents $ 1,873
$ —
$ —
$ —
$ 1,873
Insurance contracts —
4,501
—
—
4,501
Commingled funds:
U.S. equity funds —
—
—
3,643
3,643
Non U.S. equity funds —
—
—
3,204
3,204
U.S fixed income funds —
—
—
2,311
2,311
Emerging market equity funds —
—
—
1,058
1,058
Emerging market debt funds —
—
—
3,401
3,401
Other commingled funds —
—
—
5,910
5,910
Debt securities:
Government securities —
3,742
—
—
3,742
U.S. corporate bonds —
5,710
—
—
5,710
Non U.S. corporate bonds —
1,239
—
—
1,239
Asset-backed securities —
2,736
—
—
2,736
Mortgage-backed securities —
3,396
—
—
3,396
Other —
(40 ) —
—
(40 )
Total $ 1,873
$ 21,284
$ —
$ 19,527
$ 42,684


^(a)	Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

~~There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2016, 2015 or 2014.~~

~~Benefit Obligations~~ ~~— A comparison of the actuarially computed benefit obligation and plan assets for SPS is presented in the following table:~~

(Thousands of Dollars) 2016 2015
Change in Projected Benefit Obligation:
Obligation at Jan. 1 $ 40,864
$ 44,342
Service cost 775
954
Interest cost 1,821
1,745
Medicare subsidy reimbursements 31
45
Plan participants’ contributions 653
687
Actuarial loss (gain) 1,293
(3,793 )
Benefit payments (3,577 ) (3,116 )
Obligation at Dec. 31 $ 41,860
$ 40,864

(Thousands of Dollars) 2016 2015
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1 $ 42,684
$ 45,356
Actual return (loss) on plan assets 1,978
(421 )
Plan participants’ contributions 653
687
Employer contributions 559
178
Benefit payments (3,577 ) (3,116 )
Fair value of plan assets at Dec. 31 $ 42,297
$ 42,684

(Thousands of Dollars) 2016 2015
Funded Status of Plans at Dec. 31:
Funded status ^(a)
$ 437
$ 1,820


^(a)	~~Amounts are recognized in noncurrent assets on SPS’ balance sheet as of Dec. 31, 2016 and 2015.~~

(Thousands of Dollars) 2016 2015
Amounts Not Yet Recognized as Components of Net Periodic Benefit Credit:
Net gain $ (12,595 ) $ (14,870 )
Prior service credit (2,630 ) (3,031 )
Total $ (15,225 ) $ (17,901 )

(Thousands of Dollars) 2016 2015
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 $ (1,004 ) $ (985 )
Noncurrent regulatory liabilities (14,221 ) (16,916 )
Total $ (15,225 ) $ (17,901 )



~~Measurement date~~	~~Dec. 31, 2016~~	~~Dec. 31, 2015~~

2016 2015
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation 4.13 % 4.65 %
Mortality table RP 2014
RP 2014
Health care costs trend rate — initial 5.50 % 6.00 %

Effective Jan. 1, 2017, the initial medical trend rate was decreased from 6.0 percent to 5.5 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is two 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 $ 3,979
$ (3,389 )
Service and interest components 273
(231 )

~~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 $17.9 million, $18.3 million and $17.1 million during 2016, 2015 and 2014, respectively, of which $0.6 million, $0.2 million and $0.2 million were attributable to SPS. Xcel Energy expects to contribute approximately $11.8 million during 2017, of which amounts attributable to SPS will be zero.

~~Plan Amendments~~ —~~In 2016 and 2015, 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) 2016 2015 2014
Service cost $ 775
$ 954
$ 1,246
Interest cost 1,821
1,745
2,572
Expected return on plan assets (2,377 ) (2,540 ) (3,247 )
Amortization of prior service credit (401 ) (401 ) (401 )
Amortization of net gain (583 ) (639 ) (321 )
Net periodic postretirement benefit credit $ (765 ) $ (881 ) $ (151 )

2016 2015 2014
Significant Assumptions Used to Measure Costs:
Discount rate 4.65 % 4.08 % 4.82 %
Expected average long-term rate of return on assets 5.80
5.80
7.20

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
2017 $ 28,596
$ 3,420
$ 24
$ 3,396
2018 28,086
3,203
26
3,177
2019 28,545
3,008
24
2,984
2020 29,567
3,015
25
2,990
2021 29,716
3,096
26
3,070
2022-2026 156,673
14,135
148
13,987


8.	~~Other Income (Expense), Net~~

~~Other income (expense), net for the years ended Dec. 31 consisted of the following:~~

(Thousands of Dollars) 2016 2015 2014
Interest income $ 129
$ 129
$ 246
Other nonoperating income 5
11
183
Insurance policy expense (43 ) (40 ) (488 )
Other nonoperating expense —
(106 ) —
Other income (expense), net $ 91
$ (6 ) $ (59 )


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

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

~~Specific valuation methods include the following:~~

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

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

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

Electric commodity derivatives held by SPS include transmission congestion instruments, generally referred to as FTRs, purchased from SPP. FTRs purchased from an RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by overall transmission load and other transmission constraints. 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. The valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.

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 management’s forecasts for several of the inputs to this complex valuation model - 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 to the complex model used for valuation of FTRs are insignificant to the financial statements of SPS.

~~Derivative Instruments Fair Value Measurements~~

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

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

At Dec. 31, 2016, accumulated other comprehensive losses related to interest rate derivatives included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

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

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

~~The following table details the gross notional amounts of commodity FTRs at Dec. 31, 2016 and 2015:~~

(Amounts in Thousands) ^(a)
Dec. 31, 2016 Dec. 31, 2015
MWh of electricity 2,685
6,192


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

~~Consideration of Credit Risk and Concentrations~~ — SPS continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of SPS’ own credit risk when determining the fair value of derivative liabilities, the impact of considering 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, 2016, seven of the eight most significant counterparties, comprising $50.0 million or 56 percent of this credit exposure, were not rated by external rating agencies, but based on SPS’ internal analysis, had credit quality consistent with investment grade. One of these significant counterparties, comprising $1.9 million or 2 percent of this credit exposure, had credit quality less than investment grade, based on SPS’ internal analysis. Seven of these significant counterparties are municipal or cooperative electric entities, or other utilities.

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

(Thousands of Dollars) 2016 2015 2014
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (817 ) $ (989 ) $ (1,161 )
After-tax net realized losses on derivative transactions reclassified into earnings 139
172
172
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (678 ) $ (817 ) $ (989 )

Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were $0.2 million for the year ended Dec. 31, 2016 and $0.3 million each of the years ended Dec. 31, 2015 and 2014.

Changes in the fair value of FTRs resulting in pre-tax net gains of $3.0 million for the year ended Dec. 31, 2016 and pre-tax net losses of $3.1 million and $3.9 million for the years ended Dec. 31, 2015 and 2014, respectively, were reclassified as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on expected recovery of FTR settlements through fuel and purchased energy cost recovery mechanisms.

FTR settlement gains of $2.1 million were recognized for the year ended Dec. 31, 2016 and FTR settlement losses of $1.6 million and $8.2 million were recognized for the years ended Dec. 31, 2015 and Dec. 31, 2014, 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, 2016, 2015 and 2014. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

~~Recurring Fair Value Measurements~~ ~~— The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 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)

In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. 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 for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2015:~~

Dec. 31, 2015
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 $ —
$ —
$ 8,980
$ 8,980
$ (3,920 ) $ 5,060
Total current derivative assets $ —
$ —
$ 8,980
$ 8,980
$ (3,920 ) 5,060
PPAs ^(a)
7,892
Current derivative instruments $ 12,952
Noncurrent derivative assets
PPAs ^(a)
$ 25,272
Noncurrent derivative instruments $ 25,272
Current derivative liabilities
Other derivative instruments:
Electric commodity $ —
$ —
$ 3,920
$ 3,920
$ (3,920 ) $ —
Total current derivative liabilities $ —
$ —
$ 3,920
$ 3,920
$ (3,920 ) —
PPAs ^(a)
3,565
Current derivative instruments $ 3,565
Noncurrent derivative liabilities
PPAs ^(a)
$ 27,078
Noncurrent derivative instruments $ 27,078

^(a)

^(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, 2015. At Dec. 31, 2015, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

~~The following table presents the changes in Level 3 commodity derivatives for the years ended Dec. 31, 2016, 2015 and 2014:~~

Year Ended Dec. 31
(Thousands of Dollars) 2016 2015 2014
Balance at Jan. 1 $ 5,060
$ 15,884
$ 9,933
Purchases 7,616
23,425
50,244
Settlements (41,923 ) (31,703 ) (44,283 )
Net transactions recorded during the period:

Gains (losses) recognized as regulatory assets 31,202
(2,546 ) (10 )
Balance at Dec. 31 $ 1,955
$ 5,060
$ 15,884

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, 2016, 2015 and 2014.

~~Fair Value of Long-Term Debt~~

~~As of Dec. 31, 2016 and 2015, other financial instruments for which the carrying amount did not equal fair value were as follows:~~

2016 2015
(Thousands of Dollars)
Carrying
Amount
Fair Value
Carrying
Amount
Fair Value
Long-term debt, including current portion^(a)
$ 1,635,858
$ 1,741,502
$ 1,538,522
$ 1,678,673


^(a)	~~Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2,~~ ~~Accounting Pronouncements~~ ~~for more information on the adoption of ASU No. 2015-03.~~

The fair value of SPS’ long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of Dec. 31, 2016 and 2015, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.


10.	~~Rate Matters~~

~~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 $64.8 million, which it subsequently revised to $42.1 million. In 2015, the PUCT approved an overall rate decrease of approximately $4.0 million, net of rate case expenses. In April 2016, SPS filed an appeal, with the Texas State District Court, of 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. A decision by the Texas State District Court is pending.

~~Texas 2016 Electric Rate Case~~ — In February 2016, SPS filed a retail electric, base rate case in Texas with each of its Texas municipalities and the PUCT requesting an overall increase in annual base rate revenue of approximately $71.9 million, or 14.4 percent. The filing is based on a historic test year ended Sept. 30, 2015, a requested ROE of 10.25 percent, an electric rate base of approximately $1.7 billion, and an equity ratio of 53.97 percent. In September 2016, SPS revised its requested rate increase to $61.5 million and along with recovery of rate case expenses made for an overall revised request of $65.5 million.

~~In December 2016, SPS reached an unopposed settlement that resolves all issues in the rate case. The following table reflects the total estimated impact:~~

(Millions of Dollars) Settlement
Base rate increase, retroactive to July 20, 2016 $ 35.2
Power factor revenues ^(a)
12.6
Rate case expenses to be addressed in a separate proceeding 4.0
Total estimated impact $ 51.8


^(a)	SPS’ request assumed customers would adjust their power factors, which would reduce revenue. To the extent power factor revenues are less than $12.6 million, a mechanism will be established to ensure SPS recovers this amount and effectively offset lower anticipated power factor charges.

~~Additional key terms are as follows:~~

~~SPS’ next TCRF application will have a cap of $19 million in additional annual revenue and parties will make reasonable efforts to obtain PUCT approval within 100 days of SPS’ initial filing;~~

~~No disallowance of SPS’ requested capital additions; and~~

~~No restrictions on filing future rate cases or rate riders.~~

Pursuant to legislation passed in Texas in 2015, the final rates established in the case will be effective retroactive to July 20, 2016. In December 2016, an ALJ approved interim rates, effective as of Dec. 10, 2016. In the fourth quarter of 2016, SPS deferred certain costs associated with this rate case. In January 2017, the PUCT approved the settlement and no refund of interim rates was necessary. SPS expects to file a surcharge to recover the additional revenue associated with final rates, for the period of July 20, 2016 through Dec. 9, 2016, by the third quarter of 2017.

~~Texas 2016 TCRF Application~~ — In February 2017, SPS filed an application with the PUCT to recover additional annual revenue of approximately $16.1 million through its TCRF, or 1.79 percent. The filing is based upon expenses and investments through Dec. 31, 2016. Based on the settlement agreement approved in the Texas 2016 electric rate case, SPS expects a PUCT decision and implementation of TCRF rates by mid-2017.

~~Pending Regulatory Proceedings — NMPRC~~

~~New Mexico 2016 Electric Rate Case~~ — In November 2016, SPS filed an electric rate case with the NMPRC for an increase in base rates of approximately $41.4 million, representing a total revenue increase of approximately 10.9 percent. The rate filing is based on a future test year ending June 30, 2018, a requested return on equity of 10.1 percent, an equity ratio of 53.97 percent and an electric rate base of approximately $832 million.

SPS has excluded fuel and purchased power costs from base rates. This base rate case also takes into account the decline in sales of 380 MW in 2017 from certain wholesale customers and seeks to adjust the service life of SPS’ Tolk power plant to a remaining life of 2030 based on the investments to provide cooling water and the risks of investments in additional environmental controls.

~~The major components of the requested rate increase are summarized below:~~

(Millions of Dollars) Request
Capital expenditures $ 20.1
Allocator changes, including wholesale load reductions 11.5
Transmission expense, net of revenue, including charges paid to SPP for construction of regionally shared transmission projects 4.7
Depreciation, including adjustment of service life for the Tolk generating station 3.6
Rate case expenses 1.1
Other, net 0.4
Requested rate increase $ 41.4

~~Key dates in the procedural schedule are as follows:~~

~~Deadline for settlement — Feb. 28, 2017;~~

~~Staff and intervenor testimony — April 14, 2017;~~

~~Rebuttal testimony — May 3, 2017;~~

~~Hearings — May 15, 2017; and~~

~~An NMPRC decision and implementation of final rates is anticipated in the second half of 2017.~~

~~Pending Regulatory Proceedings — FERC~~

~~SPP Open Access Transmission Tariff (OATT) Upgrade Costs~~ — Under the SPP OATT, costs of participant-funded, or “sponsored,” transmission upgrades may be recovered, in part, from other SPP customers whose transmission service depends on capacity enabled by the upgrade. The SPP OATT has allowed SPP to collect charges since 2008, but SPP had not been charging its customers any amounts attributable to these upgrades.

In April 2016, SPP filed a request with the FERC for a waiver that would allow SPP to recover the charges not billed since 2008. The FERC approved the waiver request in July 2016. SPS and certain other parties requested rehearing of the FERC order. Amounts due to SPP are expected to be paid over a five-year period commencing November 2016 under an optional payment plan that was approved by the FERC in September 2016 and elected by SPS in October 2016. In October 2016, SPS filed applications for deferred accounting and future recovery of related costs in Texas and New Mexico. In November 2016, SPP billed SPS a net amount, for the period from 2008 through August 2016, of $12.8 million for these charges. In December 2016, SPS’ New Mexico application was consolidated with its base rate case and SPS’ Texas application was referred to the ALJ for hearing. A decision is expected in the first half of 2017. SPS anticipates these costs will be recoverable through regulatory mechanisms.


~~11.~~	Commitments and Contingencies

~~Commitments~~

~~Capital Commitments~~ ~~— SPS has made commitments in connection with a portion of its projected capital expenditures. SPS’ capital commitments primarily relate to transmission project plans.~~

~~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 or 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 line.

~~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 2017 and 2033. 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, 2016, are as follows:~~

(Millions of Dollars) Coal Natural gas
supply Natural gas
storage and
transportation
2017 $ 195.2
$ 16.7
$ 22.8
2018 —
—
20.8
2019 —
—
21.4
2020 —
—
21.4
2021 —
—
16.3
Thereafter —
—
58.2
Total $ 195.2
$ 16.7
$ 160.9

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 certain contract obligations, including plant availability requirements. Certain 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 $56.8 million, $56.7 million and $52.4 million in 2016, 2015 and 2014, respectively. At Dec. 31, 2016, 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
2017 $ 58.0
2018 57.0
2019 19.4
2020 11.6
2021 11.9
Thereafter 29.7
Total $ 187.6

~~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 used in the normal course of business. 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 $56.6 million, $54.5 million and $63.1 million for 2016, 2015 and 2014, respectively. These expenses include capacity payments for PPAs accounted for as operating leases of $50.6 million, $48.6 million and $57.1 million in 2016, 2015 and 2014, 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
2017 $ 5.0
$ 51.5
$ 56.5
2018 5.7
50.7
56.4
2019 5.7
50.7
56.4
2020 5.6
50.7
56.3
2021 5.4
50.7
56.1
Thereafter 67.9
593.6
661.5


^(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 and 827 MW of capacity under long-term PPAs as of Dec. 31, 2016 and 2015, respectively, 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 2017. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing, and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.

No significant financial support has been, or is required to be provided to TUCO by SPS, other than contractual payments for delivered coal. However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of certain fuel procurement costs. SPS has determined that TUCO is a variable interest entity. SPS has concluded that it is not the primary beneficiary of TUCO because SPS does not have the power to direct the activities that most significantly impact TUCO’s economic performance.

~~Environmental Contingencies~~

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

~~Site Remediation~~ — Various federal and state environmental laws impose liability, without regard to the legality of the original conduct, where hazardous substances or other regulated materials have been released to the environment. SPS may sometimes pay all or a portion of the cost to remediate sites where past activities of SPS or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former manufactured gas plants operated by SPS, its predecessors, or other entities; and third-party sites, such as landfills, for which SPS is alleged to be a PRP that sent wastes to that site.

~~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 Clean Water Act (CWA) Effluent Limitations Guidelines (ELG)~~ — In 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. SPS has reviewed the final rule and does not anticipate costs of compliance will have a material impact on the results of operations, financial position or cash flows.

~~Federal CWA Waters of the United States Rule~~ —In June 2015, the EPA and the U.S. Army Corps of Engineers published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The expansion of the term “Waters of the U.S.” will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule. In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected by June 2017.

~~Air~~

~~GHG Emission Standard for Existing Sources (Clean Power Plan or CPP)~~ — In 2015, a final rule was published by the EPA for GHG emission standards for existing power plants. Under the rule, states were required to develop implementation plans by September 2016, with the possibility of an extension to September 2018, or submit to a federal plan for the state prepared by the EPA. Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets. The CPP was challenged by multiple parties in the D.C. Circuit Court. In January 2016, the D.C. Circuit Court denied requests to stay the effectiveness of the rule. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. In September 2016, the D.C. Circuit Court heard oral arguments in the consolidated challenges to the CPP. 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. During the pendency of the stay, states are not required to submit implementation plans and the EPA will not enforce deadlines or issue a federal plan for any state. The states served by SPS have suspended formal planning efforts.

SPS has undertaken a number of initiatives that reduce GHG emissions and respond to state renewable and energy efficiency goals. The CPP could require additional emission reductions in states in which SPS operates. If state plans do not provide credit for the investments SPS has already made to reduce GHG emissions, or if they require additional initiatives or emission reductions, then their requirements would potentially impose additional substantial costs. Until SPS has more information about SIPs or the EPA finalizes its proposed federal plan for the states that do not develop related plans, SPS cannot predict the costs of compliance with the final rule once it takes effect. SPS believes compliance costs will be recoverable through regulatory mechanisms. If SPS’ regulators do not allow recovery of all or a part of the cost of capital investment or the O&M costs incurred to comply with the CPP or cost recovery is not provided in a timely manner, it could have a material impact on results of operations, financial position or cash flows.

~~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 1997 ozone NAAQS and the 1997 and 2006 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 December 2015, the EPA proposed adjustments to CSAPR emission budgets which address attainment of the more stringent 2008 ozone NAAQS. In September 2016, the EPA adopted a final rule that reduced the ozone season emission budget for NOx in Texas by approximately 22 percent, which is expected to lead to increased costs to purchase emission allowances. In November 2016, the EPA proposed to remove Texas from the particle NAAQS program. If adopted as proposed, Texas would no longer be subject to the annual SO₂ and NOx emission budgets under CSAPR. SPS does not anticipate these increased costs to purchase emission allowances will have a material impact on the results of operations, financial position or cash flows.

~~Regional Haze Rules~~ — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. The BART requirements of the EPA’s regional haze rules require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. Under BART, regional haze plans identify facilities that will have to reduce SO₂, NOx and PM emissions and set emission limits for those facilities. BART requirements can also be met through participation in interstate emission trading programs such as the CAIR and its successor, CSAPR. Texas’ first regional haze plan is still undergoing federal review as described below.

~~Actions affecting Harrington Units:~~ Texas developed a SIP that finds the CAIR equal to BART for EGUs. As a result, no additional controls beyond CAIR compliance would be required. In 2014, the EPA proposed to approve the BART portion of the SIP, with substitution of CSAPR compliance for Texas’ reliance on CAIR. In January 2016, the EPA adopted a final rule that defers its approval of CSAPR compliance as BART until the EPA considers further adjustments to CSAPR emission budgets under the D.C. Circuit Court’s remand of the Texas SO₂~~emission budgets. In June 2016, the EPA issued a memorandum which allows Texas to voluntarily adopt the CSAPR emission budgets limiting annual SO~~₂ and NOx emissions and rely on those emission budgets to satisfy Texas’ BART obligations under the regional haze rules. The Texas Commission on Environmental Quality (TCEQ) has not utilized this option. The EPA then published a proposed rule in January 2017 that could have the effect of requiring installation of dry scrubbers to reduce SO₂ emissions from Harrington Units 1 and 2. Investment costs associated with dry scrubbers for Harrington Units 1 and 2 could be approximately $400 million. The EPA’s deadline to issue a final BART rule for Texas is September 2017.

~~Actions affecting Tolk units:~~ ~~In January 2016, the EPA adopted a final rule establishing a federal implementation plan for the state of Texas, which imposed SO~~₂ emission limitations that reflect 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 requested a stay of the final rule. The Fifth Circuit granted the stay and decided that the Fifth Circuit is the appropriate venue for this case. The EPA sought a remand of its order and SPS and others have opposed the terms of that remand. A decision is expected in late 2017 or early 2018. It is likely that Texas and other affected entities including SPS would continue to challenge the determinations to date. The new Administration has not yet taken any public position regarding its views of the proposed and final regional haze regulations affecting SPS facilities in Texas. The risk of these controls being imposed along with the risk of investments to provide cooling water to Tolk have caused SPS to seek to decrease the remaining depreciable life of the Tolk units.

~~Implementation of the NAAQS for SO~~₂ ~~— The EPA adopted a more stringent NAAQS for SO~~₂ in 2010. The EPA is requiring states to evaluate areas in three phases. The first phase includes areas near SPS’ Tolk and Harrington plants. The Tolk and Harrington Plants utilize low sulfur coal to reduce SO₂ emissions. In June 2016, the EPA issued final designations which found the area near the Tolk plant to be meeting the NAAQS and 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 an area is designated nonattainment in 2020, the states will need to evaluate all SO~~₂ ~~sources in the area. The state would then submit an implementation plan, which would be due by 2022, designed to achieve the NAAQS by 2025. The TCEQ could require additional SO~~₂ controls at Harrington as part of such a plan. SPS cannot evaluate the impacts until the designation of nonattainment areas 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 areas where SPS operates, current monitored air quality concentrations meet the 70 ppb level in the Texas panhandle. In documents issued with the new standard, the EPA projects this area will meet the new standard. Therefore, SPS does not expect a material impact on results of operations, financial position or cash flows.

~~Asset Retirement Obligations~~

~~Recorded AROs~~ — AROs have been recorded for property related to the following: electric steam production, electric distribution and transmission, and general property. The electric production obligations include asbestos, ash-containment facilities, storage tanks and control panels. The asbestos recognition associated with electric production includes certain specific plants. AROs also have been recorded for steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills.

An ARO was recognized for the removal of electric transmission and distribution equipment, which consists of many small potential obligations associated with PCBs, mineral oil, storage tanks, lithium batteries, mercury and street lighting lamps. The electric general ARO includes small obligations related to storage tanks.

In April 2015, the EPA published the final rule regulating the management and disposal of coal combustion byproducts (e.g., coal ash) as a nonhazardous waste to the Federal Register. The rule became effective in October 2015. No cash flow revisions were necessary, as a result of the final rule.

~~A reconciliation of SPS’ AROs for the years ended Dec. 31, 2016 and 2015 is as follows:~~

(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.~~

(Thousands of Dollars) Beginning Balance Jan. 1, 2015 Accretion
Cash Flow
Revisions

Ending Balance
Dec. 31, 2015 ^(a)
Electric plant
Steam production asbestos $ 16,957
$ 1,024
$ —
$ 17,981
Steam production ash containment 1,609
85
(181 ) 1,513
Electric distribution 6,327
232
—
6,559
Other 1,138
42
—
1,180
Total liability $ 26,031
$ 1,383
$ (181 ) $ 27,233


^(a)	~~There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2015.~~

~~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, 2016. 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, 2016 and 2015 were $209 million and $204 million, respectively.

Legal ~~Contingencies~~

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

Management ~~is sometimes~~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.

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

Rate Matters

~~Other Contingencies~~Texas Fuel Reconciliation—In December 2018,SPS filed an application with the PUCT for reconciliation of fuel costs for the period Jan. 1, 2016, through June 30, 2018, to determine whether all fuel costs incurred were eligible for recovery. In December 2019, the PUCT issued an order disallowing recovery of costs for Texas customers related to two specific solar PPAs. These PPAs were previously approved by the NMPRC as reasonable, necessary and economic. SPS recorded a total disallowance of approximately $6 million in December 2019.

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

In July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP the right to recover previously unbilled charges was remanded to the FERC. In February 2019, the FERC reversed its 2016 decision and ordered SPP to refund charges retroactively collected from its transmission customers, including SPS, related to periods before September 2015. In April 2019, several parties, including SPP, filed requests for rehearing. Timing of a FERC response to rehearing requests is uncertain. Any refunds received by SPS are expected to be given back to SPS customers through future rates.

In October 2017, SPS filed a separate complaint against SPP asserting SPP assessed upgrade charges to SPS in violation of the SPP OATT. The FERC granted a rehearing for further consideration in May 2018. Timing of FERC action on the SPS rehearing is uncertain. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the amounts through future SPS customer rates.

SPP Filing to Assign GridLiance Facilities to SPS Rate Zone — In August 2018, SPP filed a request with the FERC to amend its OATT to include costs of the GridLiance High Plains, LLC. facilities in the SPS rate zone. In a previous filing, the FERC determined that some of these facilities did not qualify as transmission facilities under the SPP OATT.

In September 2018, SPS protested the proposed SPP tariff charges, and asked the FERC to reject the SPP filing. On Oct. 31, 2018, the FERC issued an order accepting the proposed charges, subject to refund, as of Nov. 1, 2018, and set the case for settlement hearing procedures. Hearings are scheduled for May 2020, with the ALJs’ initial decision expected in October 2020. SPS has incurred approximately $6 million in associated charges as of Dec. 31, 2019.

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

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

~~See Note 10~~

In January 2019, the FERC issued an order accepting the proposed rate changes as of Feb. 1, 2019, subject to refund and settlement procedures. On Dec. 23, 2019, SPS filed a Stipulation and Agreement of Settlement. If approved by the FERC, the settlement would implement the requested depreciation and TCJA related changes, but would not modify current treatment of wholesale regulatory commission expenses.

Environmental

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

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

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

Environmental Requirements — Water and Waste

Federal CWA WOTUS Rule—In 2015, the EPA and Corps published a final rule that significantly broadened the scope of waters under the CWA that are subject to federal jurisdiction, referred to as “WOTUS”. In 2019, the EPA repealed the 2015 rule and published a draft replacement rule. Until a final rule is issued, SPS cannot estimate potential impacts, but anticipates costs will be recoverable through regulatory mechanisms.

Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power plants that discharge treated effluent to surface waters as well as utility-owned landfills that receive CCRs. In 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport until November 2020. After 2020, SPS estimates that ELG compliance costs will be immaterial. The EPA, however, is conducting a rulemaking process to revise certain effluent limitations and pretreatment standards, which may impact compliance costs. SPS anticipates these costs will be fully recoverable through regulatory mechanisms.

Environmental Requirements — Air

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

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

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

In December 2017, the National Parks Conservation Association, Sierra Club, and Environmental Defense Fund appealed the EPA’s 2017 final BART rule to the Fifth Circuit and filed a petition for administrative reconsideration. In January 2018, the court granted SPS’ motion to intervene in the Fifth Circuit litigation in support of the EPA’s final rule. The court has held the litigation in abeyance while the EPA decided whether to reconsider the rule. In August 2018, the EPA started a reconsideration rulemaking, which was supplemented by an additional agency notice in November 2019. It is not known when the EPA will make a final decision on this proposal.

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

In March 2017, the Fifth Circuit remanded the rule to the EPA for reconsideration, leaving the stay in effect. In a future rulemaking, the EPA will address whether SO₂ emission reductions beyond those required in the BART alternative rule are needed at Tolk under the “reasonable progress” requirements. The EPA has not announced a schedule for acting on the remanded rule.

Implementation of the NAAQS for SO₂ — The EPA has designated all areas near SPS’ generating plants as attaining the SO₂ NAAQS with an exception. The EPA issued final designations, which found the area near the Harrington plant as “unclassifiable.” The area near the Harrington plant is to be monitored for three years and a final designation is expected to be made by December 2020.

If the area near the Harrington plant is designated nonattainment in 2020, the TCEQ will need to develop an implementation plan, designed to achieve the NAAQS by 2025. The TCEQ could require additional SO₂ controls at Harrington as part of such a plan. SPS cannot evaluate the impacts until the final designation is made and any required state plans are developed. SPS believes that should SO₂ control systems be required for a plant, compliance costs or the costs of alternative cost-effective generation will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial condition or cash flows.


~~12.~~	~~Regulatory Assets and Liabilities~~

AROs — AROs have been recorded for SPS’ assets.

SPS’ ~~financial statements are prepared in accordance with the applicable accounting guidance,~~AROs were as discussed in Note 1. Under this guidance, regulatory assets and liabilities are created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric rates. If changes in the utility industry or the business of SPS no longer allow for the application of regulatory accounting guidance under GAAP, SPS would be required to recognize the write-off of regulatory assets and liabilities in net income or OCI.

~~The components of regulatory assets shown on the balance sheets of SPS at Dec. 31, 2016 and 2015 are:~~follows:

(Thousands of Dollars) See
Note(s) Remaining
Amortization Period Dec. 31, 2016 Dec. 31, 2015
Regulatory Assets Current Noncurrent Current Noncurrent
Pension and retiree medical obligations ^(a)
7
Various $ 13,986
$ 234,171
$ 15,632
$ 223,122
Recoverable deferred taxes on AFUDC recorded in plant 1
Plant lives —
44,258
—
39,368
Net AROs ^(b)
11
Plant lives —
24,352
—
23,014
Renewable resources and environmental initiatives 11
One to four years 3,580
2,900
3,740
2,019
Conservation programs ^(c)
1
One to three years 3,754
2,431
5,137
3,859
Losses on reacquired debt 4
Term of related debt 127
1,617
850
1,743
Other Various 17,274
36,954
6,182
8,689
Total regulatory assets $ 38,721
$ 346,683
$ 31,541
$ 301,814



	2019
(Millions of Dollars)	Jan. 1, 2019		Amounts Incurred (a)		Amounts Settled (b)			Accretion		Cash Flow Revisions (c)			Dec. 31, 2019
Electric
Steam and other production	$	22.0	$	—	$	(1.6	)	$	1.4	$	29.5		$	51.3
Wind	—		16.0		—			0.4		—			16.4
Distribution	9.1		—		—			0.4		—			9.5
Miscellaneous	1.3		—		—			—		(1.2		)	0.1
Total liability	$	32.4	$	16.0	$	(1.6	)	$	2.2	$	28.3		$	77.3


^(a)	~~Includes~~Amounts incurred related to the ~~non-qualified pension plan.~~Hale wind farm placed in service in 2019.


^(b)	~~Includes amounts recorded for future recovery of AROs.~~Amounts settled related to asbestos abatement projects.


^(c)	~~Includes costs~~In 2019, AROs were revised for ~~conservation programs, as well as incentives allowed~~changes in ~~certain jurisdictions.~~timing and estimates of cash flows. Changes in steam production AROs primarily related to the cost estimates to remediate ponds at production facilities.

~~The components of regulatory liabilities shown on the balance sheets of SPS at Dec. 31, 2016 and 2015 are:~~

(Thousands of Dollars) See
Note(s) Remaining
Amortization Period Dec. 31, 2016 Dec. 31, 2015
Regulatory Liabilities Current Noncurrent Current Noncurrent
Plant removal costs 11
Plant lives $ —
$ 208,638
$ —
$ 203,954
Revenue subject to refund 10
One to two years 5,093
3,602
20,647
1,080
Gain from asset sales 10
Various —
2,530
2,640
2,584
Deferred electric energy costs 1
Less than one year 32,451
—
61,041
—
Contract valuation adjustments ^(a)
1, 9
Term of related contract 1,955
—
9,387
—
Renewable resources and environmental
initiatives
11
One to two years 1,075
—
2,960
880
Other Various 1,003
18,684
1,630
21,086
Total regulatory liabilities ^(b)
$ 41,577
$ 233,454
$ 98,305
$ 229,584



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


^(a)	~~Includes the fair value~~In 2018, AROs were revised for changes in timing and estimates of ~~certain long-term PPAs used~~cash flows. Changes in electric distribution AROs were primarily related to ~~meet energy capacity requirements.~~increased labor costs.


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

^(b)~~Revenue subject~~Indeterminate AROs — Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to ~~refund~~the age of $0many of SPS’ facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2019. Therefore, an ARO has not been recorded for these facilities.

Removal Costs — SPS records a regulatory liability for the plant removal costs that are recovered currently in rates. Removal costs have accumulated based on varying rates as authorized by the appropriate regulatory entities. SPS has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Removal costs as of Dec. 31, 2019 and 2018 were $174.5 million and ~~$3.9~~$187.7 million, respectively.

Leases

SPS evaluates contracts that may contain leases, including PPAs and arrangements for ~~2016~~the use of office space and ~~2015, respectively,~~other facilities, vehicles and equipment. Under ASC Topic 842, adopted by SPS on Jan. 1, 2019, a contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine if the arrangement is a finance lease.

ROU assets represent SPS’ rights to use leased assets. Starting in 2019, the present value of future operating lease payments are recognized in current and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets.

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

Operating lease ROU assets:

~~At Dec. 31, 2016 and 2015, approximately $65 million and $25 million~~



(Millions of Dollars)	Dec. 31, 2019
PPAs	$	500.3
Other	48.0
Gross operating lease ROU assets	548.3
Accumulated amortization	(25.9		)
Net operating lease ROU assets	$	522.4

Components of SPS’ regulatory assets represented past expenditures not currently earning a return, respectively. This amount primarily includes certain expenditures associated with renewable resources and environmental initiatives.lease expense:



(Millions of Dollars)	2019		2018		2017
Operating leases
PPA capacity payments	$	48.1	$	51.1	$	51.4
Other operating leases ^(a)	4.9		7.9		6.4
Total operating lease expense ^(b)	$	53.0	$	59.0	$	57.8


~~13.~~ ^(a)	Includes short-term lease expense of $1.5 million, $1.1 million and $1.2 million for 2019, 2018 and 2017, respectively.


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

Commitments under operating leases as of Dec. 31, 2019:



(Millions of Dollars)	PPA ^{(a) (b)} Operating Leases			Other Operating Leases			Total Operating Leases
2020	$	46.2		$	3.4		$	49.6
2021	46.2			3.3			49.5
2022	46.2			3.4			49.6
2023	46.2			3.4			49.6
2024	46.2			3.5			49.7
Thereafter	404.5			51.3			455.8
Total minimum obligation	635.5			68.3			703.8
Interest component of obligation	(160.0		)	(21.6		)	(181.6		)
Present value of minimum obligation	475.5			46.7			522.2
Less current portion							(26.9		)
Noncurrent operating lease liabilities							$	495.3

Weighted-average remaining lease term in years							14.1


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


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

Commitments under operating leases as of Dec. 31, 2018:



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


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


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

PPAs and Fuel Contracts

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

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

Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts, were payments for capacity of $19.9 million, $57.6 million and $58.4 million in 2019, 2018 and 2017, respectively.

At Dec. 31, 2019, the estimated future payments for capacity that SPS is obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:



(Millions of Dollars)	Capacity
2020	$	12.3
2021	12.5
2022	12.7
2023	13.0
2024	5.9
Thereafter	—
Total	$	56.4

Fuel Contracts— SPS has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal and natural gas requirements. These contracts expire between 2020 and 2033. SPS is required to pay additional amounts depending on actual quantities shipped under these agreements.

Estimated minimum purchases under these contracts as of Dec. 31, 2019:



(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2020	$	96.7	$	12.3	$	28.9
2021	67.7		—		23.3
2022	38.8		—		17.4
2023	—		—		12.7
2024	—		—		6.7
Thereafter	—		—		26.3
Total	$	203.2	$	12.3	$	115.3

VIEs

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

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

SPS evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities. SPS concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. SPS had approximately 1,197 MW of capacity under long-term PPAs at both Dec. 31, 2019 and 2018 with entities that have been determined to be VIEs. These agreements have expiration dates through 2041.

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

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

11. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. ~~31, 2016 and 2015 were as follows:~~31:



	2019
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit Pension and Postretirement Items				Total
Accumulated other comprehensive loss at Jan. 1	$	(0.7	)	$	(0.7	)		$	(1.4	)
Other comprehensive loss before reclassifications (net of taxes of $0 and $(0.1), respectfully	—			(0.2		)		(0.2		)
Losses reclassified from net accumulated other comprehensive loss:
Amortization of net actuarial loss (net of taxes of $0)	—			0.2			^(a)	0.2
Net current period other comprehensive income (loss)	—			—				—
Accumulated other comprehensive loss at Dec. 31	$	(0.7	)	$	(0.7	)		$	(1.4	)

Year Ended Dec. 31, 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 )

Year Ended Dec. 31, 2015
(Thousands of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total
Accumulated other comprehensive loss at Jan. 1 $ (989 ) $ —
$ (989 )
Other comprehensive loss before reclassifications —
(464 ) (464 )
Losses reclassified from net accumulated other comprehensive loss 172
—
172
Net current period other comprehensive income (loss) 172
(464 ) (292 )
Accumulated other comprehensive loss at Dec. 31 $ (817 ) $ (464 ) $ (1,281 )

~~Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2016 and 2015 were as follows:~~

Amounts Reclassified from Accumulated
Other Comprehensive Loss
(Thousands of Dollars) Year Ended Dec. 31, 2016 Year Ended Dec. 31, 2015
Losses on cash flow hedges:
Interest rate derivatives $ 219
^(a)
$ 269
^(a)
Total, pre-tax 219
269

Tax benefit (80 ) (97 )
Total amounts reclassified, net of tax $ 139
$ 172


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



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


^(a)	Included in interest charges.


~~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:



(Millions of Dollars)	2019		2018		2017
Operating expenses:
Purchased power	$	—	$	—	$	1.4
Other operating expenses — paid to Xcel Energy Services Inc.	192.0		195.1		196.6
Interest expense	0.2		0.6		—

(Thousands of Dollars) 2016 2015 2014
Operating revenues:
Electric $ 56
$ —
$ 23
Operating expenses:
Purchased power 8,809
8,632
9,614
Other operating expenses — paid to Xcel Energy Services Inc. 188,175
197,134
145,917
Interest expense 189
156
73
Interest income —
6
3

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



	2019				2018
(Millions of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	4.2	$	—	$	4.7	$	—
PSCo	—		0.4		—		0.7
Other subsidiaries of Xcel Energy Inc.	—		20.0		5.8		19.2
	$	4.2	$	20.4	$	10.5	$	19.9

2016 2015
(Thousands of Dollars) Accounts
Receivable Accounts
Payable Accounts
Receivable Accounts
Payable
NSP-Minnesota $ 935
$ —
$ 1,066
$ —
NSP-Wisconsin —
333
—
71
PSCo —
745
—
414
Other subsidiaries of Xcel Energy Inc. 14
13,336
13
28,650
$ 949
$ 14,414
$ 1,079
$ 29,135


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



	Quarter Ended
(Millions of Dollars)	March 31, 2019		June 30, 2019		Sept. 30, 2019		Dec. 31, 2019
Operating revenues	$	454.1	$	410.5	$	533.1	$	428.1
Operating income	74.5		81.9		135.4		54.9
Net income	54.1		58.8		105.1		45.1

Quarter Ended
(Thousands of Dollars) March 31, 2016 June 30, 2016 Sept. 30, 2016 Dec. 31, 2016
Operating revenues $ 390,839
$ 440,445
$ 554,926
$ 464,749
Operating income 53,569
68,386
122,362
62,964
Net income 22,523
32,211
68,346
29,077



	Quarter Ended
(Millions of Dollars)	March 31, 2018		June 30, 2018		Sept. 30, 2018		Dec. 31, 2018
Operating revenues	$	447.2	$	481.3	$	540.1	$	464.6
Operating income^(a)	57.1		87.6		111.0		56.0
Net income	33.1		58.5		81.5		40.2


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

Quarter Ended
(Thousands of Dollars) March 31, 2015 June 30, 2015 Sept. 30, 2015 Dec. 31, 2015
Operating revenues $ 423,829
$ 422,985
$ 530,752
$ 409,652
Operating income 49,759
53,132
117,076
54,498
Net income 20,247
22,576
61,815
22,625

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

None.

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

ITEM 9A — CONTROLS AND PROCEDURES

~~None.~~

~~Item 9A~~ — ~~Controls and Procedures~~

Disclosure Controls and Procedures

SPS maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in ~~the~~ reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the ~~chief executive officer (CEO)~~CEO and ~~chief financial officer (CFO),~~CFO, allowing timely decisions regarding required disclosure. As of Dec. 31, ~~2016,~~2019, based on an evaluation carried out under the supervision and with the participation of SPS’ management, including the CEO and CFO, of the effectiveness of its disclosure controls and ~~the~~ procedures, the CEO and CFO have concluded that SPS’ disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

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

During the year and in preparation for issuing its report for the year ended Dec. 31, ~~2016,~~2019 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, SPS conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, SPS did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board, ~~and~~ as approved by the SEC and as indicated in SPS’ Management Report on Internal Controls ~~herein.~~

In 2016, SPS implemented the general ledger modules of a new enterprise resource planning system to improve certain financial and related transaction processes. SPS plans to initiate deployment of work management systems modules, including the conversion of existing work management systems, to this same system during 2017. In connection with this ongoing implementation, SPSover Financial Reporting, which is updating 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 will have an adverse effect on its internal control over financial reporting.

contained in Item 8 herein.

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

~~Item 9B~~ — ~~Other Information~~

ITEM 9B — OTHER INFORMATION

None.

~~None.~~

PART III

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

ITEM 10 — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

~~Item 10 — Directors, Executive Officers and Corporate Governance~~

ITEM 11 — EXECUTIVE COMPENSATION

~~Item 11~~ — ~~Executive Compensation~~

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

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

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

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

Information required under this Item is contained in Xcel Energy Inc.’s definitive Proxy Statement for its ~~2017~~2020 Annual Meeting of Shareholders,

which is incorporated by reference.

~~Item 14~~ — ~~Principal Accountant Fees and Services~~

ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES

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

Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for ~~the 2017~~its 2020 Annual Meeting of ~~Stockholders~~Shareholders which

definitive Proxy Statement is expected to be filed with the SEC on or about April ~~4, 2017.~~6, 2020. Such information set forth under such

heading is incorporated herein by this reference hereto.

PART IV

~~Item 15~~ — ~~Exhibits, Financial Statement Schedules~~

ITEM 15 — EXHIBITS, FINANCIAL STATEMENT SCHEDULES



1.1	Financial Statements
	Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, ~~2016.~~2019.
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Statements of Income — For the three years ended Dec. 31, ~~2016, 2015~~2019, 2018 and ~~2014.~~2017.
	Statements of Comprehensive Income — For the three years ended Dec. 31, ~~2016, 2015~~2019, 2018 and ~~2014.~~2017.
	Statements of Cash Flows — For the three years ended Dec. 31, ~~2016, 2015~~2019, 2018 and ~~2014.~~2017.
	Balance Sheets — As of Dec. 31, ~~2016~~2019 and ~~2015.~~2018.
	Statements of Common Stockholder’s Equity — For the three years ended Dec. 31, ~~2016, 2015~~2019, 2018 and ~~2014.~~2017.
	~~Statements of Capitalization — As of Dec. 31, 2016 and 2015.~~

2.2	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, ~~2016, 2015~~2019, 2018 and ~~2014.~~2017.

3.3	Exhibits



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



3.01*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(a)(2) to~~	SPS Form ~~10-K (file no. 001-03789) dated March 3, 1998).~~10-Q for the quarter ended Sept. 30, 2017	001-03789	3.01
3.02* 3.02*	By-Laws of SPS as Amended and Restated on ~~Sept. 26, 2013. (Exhibit 3.02 to~~Jan. 25, 2019	SPS Form ~~10-Q/A~~10-K for the ~~quarter~~year ended ~~Sept. 30, 2013 (file no. 001-03789)).~~Dec. 31, 2018	001-03789	3.02
4.01* 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* 4.02*	~~Third~~ Supplemental Indenture dated Oct. 1, 2003 ~~to the indenture dated Feb. 1, 1999~~ between SPS and JPMorgan Chase Bank, as successor Trustee, creating $100 million principal amount of 6% Series C and Series D Notes ~~6 percent~~ due 2033 ~~(Exhibit 4.04 to~~	Xcel Energy Inc. Form 10-Q ~~(file no. 001-03034)~~ for the quarter ended Sept. 30, ~~2003).~~2003	001-03034	4.04
4.03* 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 Form 8-K (file no. 001-03789) dated Oct. 3, 2006).~~
4.04*	~~Red River Authority for Texas Indenture~~creating $200 million principal amount of ~~Trust dated July 1, 1991 (Form 10-K, Aug. 31, 1991 -Exhibit 4(b)).~~
4.05*	~~Fifth Supplemental Indenture dated as of Nov. 1, 2008 between SPS~~5.6% Series E Notes due 2016 and ~~The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating~~ $250 million principal amount of 6% Series ~~G Senior~~F Notes ~~8.75 percent~~ due ~~2018 (Exhibit 4.01 of~~2036	SPS Form 8-K ~~of SPS,~~ dated ~~Nov. 14, 2008 (file no. 001-03789)).~~Oct. 3, 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 Bank of New York Mellon Trust Company, N.A., as successor Trustee. (Exhibit 4.03 to SPS’ Form 8-K dated June 2, 2014 (file no. 001-03789)).~~
4.09*	~~Supplemental Indenture No. 2 dated as of June 1, 2014 between SPS and U.S. Bank National Association, as Trustee. (Exhibit 4.06 to SPS’ Form 8-K dated June 2, 2014 (file no. 001-03789)).~~
4.10*	~~Supplemental Indenture No. 3~~ dated as of June 1, 2014 between SPS and U.S. Bank National Association, as Trustee, creating $150 million principal amount of ~~3.30 percent~~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* 4.07*	Supplemental Indenture dated as of Aug. 1, 2016 between SPS and U.S. Bank National Association, as Trustee, creating $300 million principal amount of ~~3.40 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
~~10.01+~~ 4.08	Supplemental Indenture dated as of Aug. 1, 2017 between SPS and U.S. Bank National Association, as Trustee, creating $450 million principal amount of 3.70% First Mortgage Bonds, Series due 2047	SPS Form 8-K dated Aug. 9, 2017	001-03789	4.02



4.09*	Supplemental Indenture dated as of Oct. 1, 2018 between SPS and U.S. Bank National Association, as Trustee, creating $300 million principal amount of 4.40% First Mortgage Bonds, Series due 2048	SPS Form 8-K dated Nov. 5, 2018	001-03789	4.02
4.10*	Supplemental Indenture dated as of June 1, 2019 between SPS and U.S. Bank National Association, as Trustee, creating $300 million principal amount of 3.75% First Mortgage Bonds, Series due 2049	SPS Form 8-K dated June 18, 2019	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* 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* 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*+
~~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* 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* 10.06*+	~~Coal Supply Agreement (Harrington Station) between SPS and TUCO, dated May 1, 1979 (Form 8-K (file no. 001-03789) May 14, 1979 —~~ First Amendment to Exhibit ~~3).~~
10.07*	~~Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO, dated July 1, 1978 (Form 8-K (file no. 001-03789) May 14, 1979 — Exhibit 5(A)).~~
10.08*	~~Guaranty of Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO (Form 8-K (file no. 001-03789) May 14, 1979 — Exhibit 5(B)).~~
10.09*	Coal Supply Agreement (Tolk Station) between SPS and TUCO dated April 30, 1979, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q for the quarter ended Feb. 28, 1982 (file no. 001-03789) — Exhibit 10(b)).
10.10*	Master Coal Service Agreement between Wheelabrator Coal Services Co. and TUCO dated Dec. 30, 1981, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q fo4r the quarter ended Feb. 28, 1982 (file no. 001-03789) — Exhibit 10(c)).
10.11*	~~Power Purchase Agreement dated May 23, 1997 between Borger Energy Associates, L.P, and SPS.~~
~~10.12*+~~	~~Amendment~~10.02 dated Aug. 26, 2009 ~~to the~~	Xcel Energy ~~Senior Executive Severance and Change-in-Control Policy (Exhibit 10.06 to~~Inc. Form 10-Q ~~of Xcel Energy (file no. 001-03034)~~ for the quarter ended Sept. 30, ~~2009).~~2009	001-03034	10.06
10.13* 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
10.14* 10.08*+	Xcel Energy Inc. Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix A to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).
~~10.15*+~~	~~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	Appendix A
10.16* 10.09*+	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy Inc. as amended and restated effective Feb. 23, 2011 ~~(Appendix A to the~~	Xcel Energy Inc. Definitive Proxy Statement ~~(file no. 001-03034) filed Apr.~~dated April 5, ~~2011).~~2011	001-03034	Appendix A
10.17* 10.10*+	Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) ~~(Exhibit 10.07 to~~	Xcel Energy Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2008).~~2008	001-03034	10.07
10.18* 10.11*+	Second Amendment to Exhibit 10.02 dated Oct. 26, 2011 ~~to the~~	Xcel Energy ~~Senior Executive Severance and Change-in-Control Policy (Exhibit 10.18 to~~Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2011).~~2011	001-03034	10.18
10.19* 10.12*+	First Amendment to Exhibit 10.10 effective Nov. 29, 2011 ~~to the~~	Xcel Energy Inc. ~~Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.17 to~~ Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2011).~~2011	001-03034	10.17
10.20* 10.13*+	First Amendment to Exhibit 10.08 dated Feb. 20, 2013 ~~to the~~	Xcel Energy Inc. ~~Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.01 to~~ Form 10-Q ~~of Xcel Energy (file no. 001-03034)~~ for the quarter ended March 31, ~~2013).~~2013	001-03034	10.01
10.21* 10.14*+	Fourth Amendment to Exhibit 10.02 dated Feb. 20, 2013 ~~to the~~	Xcel Energy ~~Senior Executive Severance and Change-in-Control Policy (Exhibit 10.02 to~~Inc. Form 10-Q ~~of Xcel Energy (file no. 001-03034)~~ for the quarter ended March 31, ~~2013).~~2013	001-03034	10.02
10.22* 10.15*+	~~First~~ Second Amendment to Exhibit 10.10 dated May 21, 2013 ~~to the~~	Xcel Energy Inc. ~~2005 Long Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.21 to~~ Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2013).~~2013	001-03034	10.22
10.23* 10.16*+	Second Amendment dated May 21, 2013 to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.22 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013).
~~10.24*+~~	~~Xcel Energy Inc. 2005 Long-Term Incentive Plan Form of Long-Term Incentive Award Agreement (Exhibit 10.23 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013).~~



~~10.25*+~~	~~Xcel Energy Inc. 2015 Omnibus Incentive Plan (incorporated by reference to Appendix B to Schedule 14A, Definitive Proxy Statement to Xcel Energy Inc. (file no. 001-03034) dated April 6, 2015).~~
~~10.26*+~~	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 dated May 20, 2015	001-03034	10.02
10.17*+	Fifth Amendment Exhibit 10.02 dated May 3, 2016	Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2016	001-03034	10.01
10.18*+	Third Amendment to Exhibit 10.10 dated Sept. 30, 2016	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016	001-03034	10.01
10.19*+	Fourth Amendment to Exhibit 10.11 dated Oct. 23, 2017	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017	001-03034	10.1
10.20*+	Sixth Amendment to Exhibit 10.02 dated Feb. 22, 2018	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017	001-03034	10.30
10.21*+	Seventh Amendment to Exhibit 10.02 dated May ~~26, 2015 (file no. 001-03034).~~7, 2018	Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018	001-03034	10.01
10.27* 10.22*+	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
10.23*+	Form of Xcel Energy Inc. 2015 Omnibus Incentive Plan Award Agreement ~~and Award~~ Terms and Conditions ~~(Restricted Stock Units and Performance Share Units)~~ under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive ~~Plan. (Exhibit 10.03 to Form 8-K of Xcel Energy, dated May 26, 2015 (file no. 001-03034).~~
~~10.28*+~~ Plan	Xcel Energy Inc. ~~2015 Omnibus Incentive Plan Form of Award Agreement. (Exhibit 10.28 to~~ Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2015).~~2018	001-03034	10.35
10.29* 10.24*+	Stock Program for Non-Employee Directors of Xcel Energy Inc. as Amended and Restated on Dec. 12, 2017 under the 2015 Omnibus Incentive Plan	Xcel Energy Inc. ~~Executive Annual Incentive Award Sub-plan pursuant to the Xcel Energy Inc. 2015 Omnibus Incentive Plan. (Exhibit 10.29 to~~ Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2015).~~2018	001-03034	10.36
~~10.30+~~ 10.25	Fifth Amendment dated May 3, 2016 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended June 30, 2016).
10.31*	~~Second~~ Third Amended and Restated Credit Agreement, dated as of June ~~20, 2016~~7, 2019 among SPS, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, ~~and~~ Wells Fargo Bank, National Association, MUFG Bank, Ltd., and ~~The Bank of Tokyo-Mitsubishi UFJ, Ltd.~~Citibank, N.A., as Documentation ~~Agents. (Exhibit 99.04 to Form 8-K of Xcel Energy dated June 20, 2016 (file no. 001-03034)).~~
~~10.32*+~~Agents	~~Third Amendment dated Sept. 30, 2016 to the~~ Xcel Energy Inc. ~~Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.01 to~~ Form ~~10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2016).~~8-K dated June 7, 2019	001-03034	99.04
10.33* 10.26*+	Form of Xcel Energy Inc. 2015 Omnibus Incentive ~~Plan~~ Award Agreement ~~and Award~~ Terms and Conditions ~~(Restricted Stock Units and Performance Share Units)~~ under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive ~~Plan. (Exhibit 10.33 to~~Plan	Xcel Energy Inc. Form 10-K ~~of Xcel Energy (file no. 001-03034)~~ for the year ended Dec. 31, ~~2016).~~2019	001-03034	10.33
~~12.01~~23.01	~~Statement of Computation of Ratio of Earnings to Fixed Charges.~~
~~23.01~~	Consent of Independent Registered Public Accounting Firm.
31.01	Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
~~99.01~~ 101.INS	~~Statement pursuant to Private Securities Litigation Reform Act of 1995.~~XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
~~101~~101.SCH	~~The following materials from SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2016 are formatted in~~ XBRL (eXtensible Business Reporting Language): (i) the Statements of Income, (ii) the Statements of Comprehensive Income, (iii) the Statements of Cash Flows, (iv) the Balance Sheets, (v) the Statements of Stockholder’s Equity, (vi) the Statements of Capitalization, (vii) Notes to Financial Statements, (viii) document and entity information, and (ix) Schedule II.Schema
101.CAL	XBRL Calculation
101.DEF	XBRL Definition
101.LAB	XBRL Label



101.PRE	XBRL Presentation
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

SCHEDULE II

~~SOUTHWESTERN PUBLIC SERVICE CO.~~

~~VALUATION AND QUALIFYING ACCOUNTS~~

~~YEARS ENDED DEC.~~Southwestern Public Service Co. Valuation and Qualifying Accounts Years Ended Dec. 31 ~~2016, 2015 AND 2014~~

~~(amounts in thousands)~~

Additions

Balance at
Jan. 1

Charged to
Costs and
Expenses

Charged to
Other
Accounts^(a)

Deductions
from
Reserves ^(b)

Balance at
Dec. 31
Allowance for bad debts:
2016 $ 5,888
$ 6,066
$ 907
$ 6,482
$ 6,379
2015 5,839
4,655
1,036
5,642
5,888
2014 5,475
4,137
1,089
4,862
5,839



	Allowance for bad debts
(Millions of Dollars)	2019			2018			2017
Balance at Jan. 1	$	5.6		$	6.4		$	6.4
Additions charged to costs and expenses	5.7			4.9			5.1
Additions charged to other accounts ^(a)	1.5			1.0			1.2
Deductions from reserves ^(b)	(7.5		)	(6.7		)	(6.3		)
Balance at Dec. 31	$	5.3		$	5.6		$	6.4


^(a)	Recovery of amounts previously written off.


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

ITEM 16 — FORM 10-K SUMMARY

None.

~~SIGNATURES~~

Signatures

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



		SOUTHWESTERN PUBLIC SERVICE COMPANY

Feb. ~~24, 2017~~21, 2020		/s/ ROBERT C. FRENZEL
		Robert C. Frenzel
		Executive Vice President, Chief Financial Officer and Director
		(Principal Financial Officer)

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



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

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

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

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

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

7745



	Coal				Natural Gas				Weighted Average Owned Fuel Cost
SPS Generating Plants	Cost		Percent		Cost		Percent		Weighted Average Owned Fuel Cost
2016	$	2.12	70	%	$	2.81	30	%	$	2.32
2015	2.12		73		3.11		27		2.39
2014	2.07		71		4.76		29		2.85



Electric Utility Generating Stations:
Station, Location and Unit	Fuel	Installed	Summer 2016 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	338
Maddox-Hobbs, N.M., 1 Unit	Natural Gas	1963-1976	61
		Total	4,416



(Millions of Dollars)	2016 vs. 2015
Transmission revenue	$	38
Fuel and purchase power cost recovery	17
Retail rate increases ^(a)	11
Estimated impact of weather	2
Trading	(5		)
Other, net	1
Total increase in electric revenues	$	64



(Thousands of Dollars)	Dec. 31, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	80,569		$	77,054
Less allowance for bad debts	(6,379		)	(5,888		)
	$	74,190		$	71,166



(Amounts in Millions, Except Interest Rates)	Three Months Ended Dec. 31, 2016
Borrowing limit	$	100
Amount outstanding at period end	—
Average amount outstanding	20
Maximum amount outstanding	64
Weighted average interest rate, computed on a daily basis	0.83		%
Weighted average interest rate at period end	N/A



(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2016			Twelve Months Ended Dec. 31, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	100		$	100		$	100
Amount outstanding at period end	—			—			16
Average amount outstanding	28			21			9
Maximum amount outstanding	100			100			100
Weighted average interest rate, computed on a daily basis	0.67		%	0.40		%	0.22		%
Weighted average interest rate at end of period	N/A			N/A			0.45



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



	One-Percentage Point
(Thousands of Dollars)	Increase		Decrease
APBO	$	3,979	$	(3,389	)
Service and interest components	273		(231		)



	Dec. 31, 2016
	Fair Value						Fair Value Total		Counterparty Netting ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting ^(b)				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



(Millions of Dollars)	Settlement
Base rate increase, retroactive to July 20, 2016	$	35.2
Power factor revenues ^(a)	12.6
Rate case expenses to be addressed in a separate proceeding	4.0
Total estimated impact	$	51.8



(Millions of Dollars)	Request
Capital expenditures	$	20.1
Allocator changes, including wholesale load reductions	11.5
Transmission expense, net of revenue, including charges paid to SPP for construction of regionally shared transmission projects	4.7
Depreciation, including adjustment of service life for the Tolk generating station	3.6
Rate case expenses	1.1
Other, net	0.4
Requested rate increase	$	41.4



(Millions of Dollars)	Operating Leases		PPA ^{(a) (b)} Operating Leases		Total Operating Leases
2017	$	5.0	$	51.5	$	56.5
2018	5.7		50.7		56.4
2019	5.7		50.7		56.4
2020	5.6		50.7		56.3
2021	5.4		50.7		56.1
Thereafter	67.9		593.6		661.5



(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



(Thousands of Dollars)	Beginning Balance Jan. 1, 2015		Accretion		Cash Flow Revisions			Ending Balance Dec. 31, 2015 ^(a)
Electric plant
Steam production asbestos	$	16,957	$	1,024	$	—		$	17,981
Steam production ash containment	1,609		85		(181		)	1,513
Electric distribution	6,327		232		—			6,559
Other	1,138		42		—			1,180
Total liability	$	26,031	$	1,383	$	(181	)	$	27,233



	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	)



	Year Ended Dec. 31, 2015
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(989	)	$	—		$	(989	)
Other comprehensive loss before reclassifications	—			(464		)	(464		)
Losses reclassified from net accumulated other comprehensive loss	172			—			172
Net current period other comprehensive income (loss)	172			(464		)	(292		)
Accumulated other comprehensive loss at Dec. 31	$	(817	)	$	(464	)	$	(1,281	)



	Quarter Ended
(Thousands of Dollars)	March 31, 2016		June 30, 2016		Sept. 30, 2016		Dec. 31, 2016
Operating revenues	$	390,839	$	440,445	$	554,926	$	464,749
Operating income	53,569		68,386		122,362		62,964
Net income	22,523		32,211		68,346		29,077



	Quarter Ended
(Thousands of Dollars)	March 31, 2015		June 30, 2015		Sept. 30, 2015		Dec. 31, 2015
Operating revenues	$	423,829	$	422,985	$	530,752	$	409,652
Operating income	49,759		53,132		117,076		54,498
Net income	20,247		22,576		61,815		22,625



			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:
2016	$	5,888	$	6,066	$	907	$	6,482	$	6,379
2015	5,839		4,655		1,036		5,642		5,888
2014	5,475		4,137		1,089		4,862		5,839

Wind Farms

Wind Farms