10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2018

or

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

001-03789	75-0575400
(Commission File Number)	(I.R.S. Employer Identification No.)

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

SOUTHWESTERN PUBLIC SERVICE COMPANY

(a New Mexico company)

790 South Buchanan Street

Amarillo, Texas 79101

303-571-7511

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

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

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  ¨ Yes x No

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  x Yes  ¨ No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act. ¨ Large accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨ Smaller Reporting Company ¨ Emerging growth company

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  ¨ Yes   x No

As of Feb. 22, 2019, 100 shares of common stock, par value $1 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm – Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the 2019 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 1, 2019. Such information set forth under such heading is incorporated herein by this reference hereto.

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

TABLE OF CONTENTS

PART I		3
Item 1 —	Business	3
	ABBREVIATIONS AND INDUSTRY TERMS	3
	FORWARD LOOKING STATEMENTS	4
	WHERE TO FIND MORE INFORMATION	4
	COMPANY OVERVIEW	4
	ELECTRIC UTILITY OPERATIONS	5
	Electric Operating Statistics	5
	Energy Sources	6
	Capacity and Demand	6
	Public Utility Regulation	7
	GENERAL	7
	ENVIRONMENTAL MATTERS	8
	EMPLOYEES	8
Item 1A —	Risk Factors	8
Item 1B —	Unresolved Staff Comments	13
Item 2 —	Properties	13
Item 3 —	Legal Proceedings	13
Item 4 —	Mine Safety Disclosures	13
PART II	PART II	14
Item 5 —	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	14
Item 6 —	Selected Financial Data	14
Item 7 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
Item 7A —	Quantitative and Qualitative Disclosures About Market Risk	16
Item 8 —	Financial Statements and Supplementary Data	16
Item 9 —	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	40
Item 9A —	Controls and Procedures	40
Item 9B —	Other Information	41
PART III	PART III	41
Item 10 —	Directors, Executive Officers and Corporate Governance	41
Item 11 —	Executive Compensation	41
Item 12 —	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	41
Item 13 —	Certain Relationships and Related Transactions, and Director Independence	41
Item 14 —	Principal Accountant Fees and Services	41
PART IV	PART IV	41
Item 15 —	Exhibits, Financial Statement Schedules	41
Schedule II	Valuation and Qualifying Accounts	43
Item 16 —	Form 10-K Summary	43
SIGNATURES		44

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

2

PART I

Item l — Business

ABBREVIATIONS AND INDUSTRY TERMS

Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
NCE	New Century Energies, Inc.
NSP-Minnesota	Northern States Power Company, a Minnesota corporation
NSP-Wisconsin	Northern States Power Company, a Wisconsin corporation
PSCo	Public Service Company of Colorado
SPS	Southwestern Public Service Company
Utility subsidiaries	NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
Xcel Energy	Xcel Energy Inc. and its subsidiaries
Federal and State Regulatory Agencies
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
TCRF	Transmission cost recovery factor (recovers transmission infrastructure improvement costs and changes in wholesale transmission charges)
Other
AFUDC	Allowance for funds used during construction
ARAM	Average rate assumption method
ARO	Asset retirement obligation
ASU	FASB Accounting Standards Update
BART	Best available retrofit technology
CAA	Clean Air Act
C&I	Commercial and Industrial
CO2	Carbon dioxide
Corps	U.S. Army Corps of Engineers
CPP	Clean Power Plan
CSAPR	Cross-State Air Pollution Rule
CWIP	Construction work in progress
EGU	Electric generating unit
ELG	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 producing entity
ITC	Investment tax credit
MGP	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
OATT	Open Access Transmission Tariff
Paris Agreement	Establishes a framework for GHG mitigation actions by all countries (“nationally determined contributions”)
PM	Particulate matter
PPA	Purchased power agreement
PRP	Potentially responsible party
PTC	Production tax credit
QF	Qualifying facilities
REC	Renewable energy credit
ROE	Return on equity
ROFR	Right-of-first-refusal
RPS	Renewable portfolio standards
RTO	Regional Transmission Organization
SERP	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

3

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including the TCJA’s impact to SPS and its customers, as well as assumptions and other statements identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2018 (including risk factors listed from time to time by SPS in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K hereto), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: changes in environmental laws and regulations; climate change and other weather, natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; ability to recover costs from customers; reductions in our credit ratings and the costs of maintaining certain contractual relationships; actions of credit rating agencies; general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of SPS to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; tax laws; operational safety; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices; costs of potential regulatory penalties; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; fuel costs; and employee work force and third party contractor factors.

Where To Find More Information

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

COMPANY OVERVIEW

SPS was incorporated in 1921 under the laws of New Mexico. SPS conducts business in Texas and New Mexico and generates, purchases, transmits, distributes and sells electricity.

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

4

ELECTRIC UTILITY OPERATIONS

Electric Operating Statistics

	Year Ended Dec. 31
	2018			2017			2016
Electric sales (Millions of KWh)
Residential	3,645			3,356			3,478
Large C&I	11,214			10,721			10,518
Small C&I	5,041			4,701			4,708
Public authorities and other	550			527			555
Total retail	20,450			19,305			19,259
Sales for resale	10,060			7,759			8,689
Total energy sold	30,510			27,064			27,948
Number of customers at end of period
Residential	308,884			306,248			305,076
Large C&I	232			221			219
Small C&I	77,269			77,351			77,319
Public authorities and other	6,322			6,316			6,377
Total retail	392,707			390,136			388,991
Wholesale	7			7			8
Total customers	392,714			390,143			388,999
Electric revenues (Millions of Dollars)
Residential	$	361.5		$	367.2		$	343.5
Large C&I	457.2			516.8			462.6
Small C&I	364.0			376.0			322.6
Public authorities and other	44.1			48.0			44.9
Total retail	1,226.8			1,308.0			1,173.6
Wholesale	427.9			388.7			414.8
Other electric revenues	278.5			221.3			262.6
Total electric revenues	$	1,933.2		$	1,918.0		$	1,851.0
KWh sales per retail customer	52,074			49,483			49,510
Revenue per retail customer	$	3,124		$	3,353		$	3,017
Residential revenue per KWh		9.92	¢		10.94	¢		9.88	¢
Large C&I revenue per KWh	4.08			4.82			4.40
Small C&I revenue per KWh	7.22			8.00			6.85
Total retail revenue per KWh	6.00			6.78			6.09
Wholesale revenue per KWh	4.25			5.01			4.77

5

Energy Sources 2018

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

Energy Source Statistics

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

Renewable Sources

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

SPS

Renewable energy as a percentage of SPS’ total:

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

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

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

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

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

Non-Renewable Sources

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

	Coal				Natural Gas
	Cost		Percent		Cost		Percent
2018	$	2.04	56	%	$	2.24	44	%
2017	2.18		74		3.39		26

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

See Items 1A and 7 for further information.

Coal — Inventory maintained (in days):

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

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

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

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

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

Contracts and commitments at Dec. 31:

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

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

Capacity and Demand

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

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

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

6

SPS

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — The PUCT and NMPRC regulate SPS’ retail electric operations and have jurisdiction over its retail rates and services and the construction of transmission or generation in their respective states. The municipalities in which SPS operates in Texas have original jurisdiction over SPS’ rates in those communities. The municipalities’ rate setting decisions are subject to PUCT review, which has ultimate authority to set the rates SPS charges in the municipalities.

SPS is regulated by the FERC for its wholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. SPS is a transmission-owning member of the SPP RTO and operates within the SPP RTO and SPP IM wholesale market. SPS is authorized to make wholesale electric sales at market-based prices.

Fuel, Purchased Energy and Conservation Cost-Recovery

Mechanisms —

• 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 the actual fuel and purchased power costs in New Mexico.

• PCRF — Recovers purchased power costs not included in rates in Texas.

• RPS — Recovers deferred costs for renewable energy programs in New Mexico.

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

The fixed fuel and purchased energy recovery factor provides for the over- or under-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.

SPS recovers 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.

Energy Sources and Transmission Service Providers

SPS expects to use electric generating stations, power purchases, DSM and new generation options to meet its system capacity requirements. In addition, it has evaluated water supply issues at the Tolk facility, concluding additional resource investment will be required to operate the plant through its existing life. The Ogallala aquifer has depleted more rapidly than expected. SPS installed a horizontal water well that may help delay the need for a more substantial investment solution. As a result of this issue and future environmental rules facing the plant, it sought a decrease to the remaining life of the facility in the 2017 Texas and New Mexico rate case proceedings.

Purchased Power — SPS purchases power from other utilities and IPPs. Long-term purchased power contracts typically require periodic capacity and energy charges.

SPS also makes short-term purchases to meet system load and energy requirements to replace owned generation, meet operating reserve obligations or obtain energy at a lower cost.

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

Wind Development — In 2018, the NMPRC and PUCT approved SPS’ proposal to add 1,230 MW of new wind generation, including ownership of 1,000 MW.

In March 2018, the NMPRC approved SPS’ petition to build and own Sagamore, a 522 MW wind project in New Mexico which is expected to be placed into service in 2020. In May 2018, the PUCT approved SPS’ petition to build and own Hale County, a 478 MW wind project in Texas which is expected to be placed into service in 2019. Both projects qualify for 100% of PTCs. SPS’ capital investment for these wind projects is expected to be approximately $1.6 billion.

Texas State ROFR Request for Declaratory Order —In 2017, SPS and SPP filed a joint petition with the PUCT for a declaratory order regarding SPS’ ROFR. SPS contended that Texas law grants an incumbent electric utility the ROFR to construct new transmission facilities located in the utility’s service area. The PUCT subsequently issued an order finding that SPS does not possess an exclusive right to construct and operate transmission facilities. In January 2018, SPS and two other parties filed appeals in the Texas State District Court. In September 2018, the District Court affirmed the PUCT’s ROFR order. SPS has filed an additional appeal.

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 natural gas transactions in interstate commerce, and to the jurisdiction of the PHMSA and the PUCT for pipeline safety compliance.

Wholesale and Commodity Marketing Operations

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

GENERAL

Seasonality

Demand for electric power is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, SPS’ operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.

See Item 7 for further information.

Competition

SPS is a vertically integrated utility subject to traditional cost-of-service regulation by state public utilities commissions. SPS is subject to public policies that promote competition and development of energy markets. SPS’ industrial and large commercial customers have the ability to generate their own electricity. In addition, customers may have the option of substituting other fuels or relocating their facilities to a lower cost region.

7

Customers have the opportunity to supply their own power with distributed generation including, but not limited to, solar generation and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them. Several states, including Texas and New Mexico, have policies designed to promote the development of solar and other distributed energy resources through incentive policies. With these incentives and federal tax subsidies, distributed generating resources are potential competitors to SPS’ electric service business.

The FERC has continued to promote competitive wholesale markets through open access transmission and other means. As a result, SPS can purchase generation resources from competing wholesale suppliers and use the transmission systems of Xcel Energy Inc.’s utility subsidiaries on a comparable basis to serve their native load.

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

SPS has franchise agreements with cities subject to periodic renewal, however, a city could seek alternative means to access electric power or gas, such as municipalization.

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

ENVIRONMENTAL MATTERS

SPS’ facilities are regulated by federal and state environmental agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. SPS has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. SPS’ facilities have been designed and constructed to operate in compliance with applicable environmental standards 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. SPS may be required to incur capital expenditures in the future to comply with requirements for remediation of MGP and other legacy sites. The scope and timing of these expenditures cannot be determined until more information is obtained regarding the need for remediation at legacy sites.

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

There are significant present and future environmental regulations to encourage use of clean energy technologies and regulate emissions of GHGs. SPS has undertaken numerous initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. If future environmental regulations do not provide credit for the investments SPS has already made or if they require additional initiatives or emission reductions, substantial costs may be incurred. The EPA, as an alternative to the CPP, has proposed a new regulation that, if adopted, would require implementation of heat rate improvement projects at our coal-fired power plants. It is not known what those costs might be until a final rule is adopted and state plans are developed to implement a final regulation.

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

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

EMPLOYEES

As of Dec. 31, 2018, SPS had 1,151 full-time employees and no part-time employees, of which 775 were covered under collective-bargaining agreements.

Item 1A — Risk Factors

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

Oversight of Risk and Related Processes

A key accountability of the Board of Directors is the oversight of material risk, and our Board of Directors employs an effective process for doing so. Management and the Board of Directors have responsibility for overseeing the identification and mitigation of key risks.

Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Identification and analysis occurs formally through a key risk assessment process by senior management, the financial disclosure process, hazard risk management procedures and internal auditing and compliance with financial and operational controls. Management also identifies and analyzes risk through its business planning process and development of goals and key performance indicators, which include risk identification to determine barriers to implementing SPS’ strategy. The business planning process also identifies areas in which there is a potential for a business area to assume inappropriate risk to meet goals, and determines how to prevent inappropriate risk-taking.

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

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

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

8

Risks Associated with Our Business

Operational Risks

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

Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric transmission and distribution activities also include inherent hazards and operating risks such as contact, fire and outages which could cause substantial financial losses. These natural gas and electric risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial 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, for natural gas costs that may be required in order to comply with potential new regulations, including the Pipeline Safety Act, could be significant. The Pipeline Safety Act requires verification of pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. We have programs in place to comply with the Pipeline Safety Act and for systematic infrastructure monitoring and renewal over time. A significant incident could increase regulatory scrutiny and result in penalties and higher costs of operations.

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

Most electric utility investments are 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.

The electric utility sector is undergoing a period of significant change. For example, increases in appliance, lighting and energy efficiency, wider adoption and lower cost of renewable generation and distributed generation, shifts away from coal generation to decrease CO₂ 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 as well as stranded costs if SPS is not able to fully recover the costs and investments. These changes also introduce additional uncertainty into long-term planning which gives rise to a risk that the magnitude and timing of resource additions and growth in customer demand may not coincide, and that the preference for the types of additions may change from planning to execution. In addition, we are subject to longer-term availability of the natural resource inputs such as coal, natural gas, uranium and water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.

Changing customer expectations and technologies are requiring significant investments in advanced grid infrastructure. This increases the exposure to potential outdating of technologies and resultant risks. The inability of coal mining companies to attract capital could disrupt longer-term supplies. Decreasing use per customer driven by appliance and lighting efficiency and the availability of cost-effective distributed generation places downward pressure on sales growth. This may lead to under recovery of costs, excess resources to meet customer demand and increases in electric rates.

Finally, multiple states may not agree as to the appropriate resource mix and the differing views may lead to costs incurred to comply with one jurisdiction that are not recoverable across all of the jurisdictions served by the same assets.

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

If fuel costs increase, customer demand could decline and bad debt expense may rise, which could have a material impact on our results of operations. While we have fuel clause recovery mechanisms, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows. Low fuel costs have a positive impact on sales, however low oil and natural gas prices could negatively impact oil and gas production activities and subsequently our sales volumes and revenue.

A significant disruption in supply could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Significantly higher energy or fuel costs relative to sales commitments have a negative impact on our cash flows and potentially result in economic losses. Potential market supply shortages may not be fully resolved through alternative supply sources and could cause disruptions in our ability to provide electric services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process.

We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, 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. Actual settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability.

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, 2018, Xcel Energy Inc. and its utility subsidiaries had approximately $15.8 billion of long-term debt and $1.4 billion of short-term debt and current maturities. Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.

9

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, 2018, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $17.8 million and immaterial exposure. Xcel Energy also had additional guarantees of $51 million at Dec. 31, 2018 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time. If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

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

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

We have historically paid quarterly dividends to Xcel Energy Inc. In 2018, 2017 and 2016 we paid $131.0 million, $108.8 million and $85.1 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs. This could adversely affect our liquidity. The most restrictive dividend limitation for SPS is imposed by its state regulatory commissions. State regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy Inc., by requiring a minimum equity-to-total capitalization ratio. See Note 5 to the financial statements for further information.

Financial Risks

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

We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.

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

Changes in the long-term cost-effectiveness or changes to the operating conditions of our assets may result in early retirements of utility facilities and while regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs leaving all or a portion of these asset costs stranded. Higher than expected inflation or tariffs may increase costs of construction and operations. Rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers. Furthermore, there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers, or these factors could cause us to exceed commitments made regarding cost caps and result in less than full recovery. Overall, management currently believes prudently incurred costs are recoverable given the existing regulatory mechanisms in place.

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

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

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

We are subject to capital market and interest rate risks.

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

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

We are subject to credit risks.

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

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

10

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

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

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

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

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

Our self-insured costs of health care benefits for eligible employees have increased in recent years. Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our operating results, financial condition and cash flows. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future liabilities and benefit costs. Legislation related to health care could also significantly change our benefit programs and costs.

Federal tax law may significantly impact our business.

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

Macroeconomic Risks

Economic conditions impact our business.

Our operations are affected by local, national and worldwide economic conditions. Growth in customers and sales are correlated with economic conditions.

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 additional bad debt expense.

Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may impact our ability to acquire sufficient supplies. We operate in a capital intensive industry and federal policy on trade could significantly impact the cost of materials we use. We could be at risk for higher costs for materials and our workforce. There may be delays before these additional costs can be recovered in rates.

Our operations could be impacted by war, acts of terrorism, and threats of terrorism or disruptions due to events.

Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows. The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have already incurred increased costs for security and capital expenditures in response to these risks.

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

A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, our brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility or an event (e.g., severe storm, severe temperature extremes, wildfires, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a disruption of work force) within our operating systems or on a neighboring system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material impact on our results of operations, financial condition or cash flows.

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

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

Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error.

Our industry has 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 causing the release of customer information, all of which could expose us to liability.

11

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

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

We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including the resulting disability, or failures of assets or unauthorized access to assets or information. If our technology systems or those of our third-party service providers were to fail or be breached, we may be unable to fulfill critical business functions. We are unable to quantify the potential impact of cyber security incidents on our business, our brand and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network monitoring may not be effective given the constant changes to threat vulnerability.

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 to perform work both for operations, maintenance and construction. We have contractual arrangements with these contractors which typically include performance standards, progress payments, insurance requirements and security for performance.

Cyber security breaches have at times exploited third party equipment or software in order to gain access. Poor vendor performance could impact on going operations, restoration operations, our reputation and could introduce financial risk or risks of fines.

Public Policy Risks

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

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

We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant.

Such payments or expenditures could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.

Although the United States has not adopted any international or federal GHG emission reduction targets, many states and localities may continue to pursue climate policies in the absence of federal mandates. All of the steps that Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation or retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. While those actions likely would have put Xcel Energy in a good position to meet federal or international standards being discussed, the lack of federal action does not adversely impact these state-endorsed actions and plans.

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

Increased risks of regulatory penalties could negatively impact our business.

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

Environmental Risks

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

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

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

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

12

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

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

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

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

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

Item 1B — Unresolved Staff Comments

None.

Item 2 —Properties

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

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

^(a)  Summer 2018 net dependable capacity.

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

Conductor Miles
345 KV	9,028
230 KV	9,675
115 KV	14,493
Less than 115 KV	25,820

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

Natural gas utility mains at Dec. 31, 2018:

Miles
Transmission	20
Distribution	—

Item 3 —Legal Proceedings

SPS is involved in various litigation matters that are being defended and handled in the ordinary course of business. Assessment of whether a loss is probable or is a reasonable possibility, and whether a loss or a range of loss is estimable, often involves a series of complex judgments regarding future events. Management maintains accruals for losses that are probable of being incurred and subject to reasonable estimation. Management may be unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) damages sought are indeterminate, (2) proceedings are in the early stages or (3) 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.

See Note 10 to the financial statements, Item 1 and Item 7 for further information.

Item 4 — Mine Safety Disclosures

None.

13

PART II

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

SPS is a wholly owned subsidiary of Xcel Energy Inc. and there is no market for its common equity securities. See Note 5 to the financial statements for further information.

The dividends declared during 2018 and 2017 were as follows:

(Millions of Dollars)	2018		2017
First quarter	$	33.4	$	26.7
Second quarter	30.7		25.0
Third quarter	40.1		26.2
Fourth quarter	45.2		26.8

Item 6 —Selected Financial Data

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

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

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

Non-GAAP Financial Measures

The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as, electric margin and ongoing earnings. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from measures calculated and presented in accordance with GAAP. SPS’ management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation, and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.

Electric Margins

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

Earnings Adjusted for Certain Items (Ongoing Earnings)

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

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

Results of Operations

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

Electric Margin

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

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

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

Electric Margin

(Millions of Dollars)	2018 vs. 2017
Wholesale transmission revenue (net of costs)	$	21.6
Estimated impact of weather	19.9
Non-fuel riders	12.7
Demand revenue	8.7
Sales growth	8.3
Retail rate increase (New Mexico)	3.1
Firm wholesale	(10.8		)
Other (net)	11.8
Total increase in electric margin before TCJA impact	$	75.3
TCJA impact (offset as a reduction in income tax)	(48.3		)
Total increase in electric margin	$	27.0

Non-Fuel Operating Expense and Other Items

Depreciation and Amortization — Depreciation and amortization expense increased $15.7 million, or 8.1%, for 2018. The increase was primarily due to increased capital investments.

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

Income Taxes — Income tax expense decreased $29.5 million for 2018 compared with the same period in 2017. The decrease in income tax expense was primarily due to a lower federal tax rate due to the TCJA, an increase in plant-related regulatory difference related to ARAM (net of deferrals), and 2018 non-plant excess accumulated deferred income tax amortization.

14

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

Regulation

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

Xcel Energy, which includes SPS, attempts to mitigate the risk of regulatory penalties through formal training on prohibited practices and a compliance function that reviews interaction with the markets under FERC and Commodity Futures Trading Commission jurisdictions. Public campaigns are conducted to raise awareness of the public safety issues of interacting with our electric systems.

While programs to comply with regulatory requirements are in place, there is no guarantee the compliance programs or other measures will be sufficient to ensure against violations. Decisions by these regulators can significantly impact SPS’ results of operations.

Tax Reform — Regulatory Proceedings

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

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

See Note 7 to the financial statements for further information.

Pending and Recently Concluded Regulatory Proceedings

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

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

15

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 8 to the financial statements for further information.

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

Distress in the financial markets may impact counterparty risk, the fair value of the securities in the pension fund, and SPS’ ability to earn a return on short-term investments.

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

SPS’ risk management policy allows it to manage commodity price risk per commission approved hedge plans.

Wholesale and Commodity Trading Risk — SPS conducts wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments, including derivatives. SPS’ risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee.

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

A 100-basis-point change in the benchmark rate on SPS’ variable rate debt would impact annual pretax interest expense by approximately $0.4 million in 2018 and no impact in 2017.

See Note 8 to the financial statements for further information.

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

At Dec. 31, 2018, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $1.5 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $1.5 million. At Dec. 31, 2017, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $1.3 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $1.3 million.

SPS conducts credit reviews for all counterparties and employ credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase SPS’ credit risk.

Fair Value Measurements

SPS uses derivative contracts such as futures, forwards, interest rate swaps, options and FTRs to manage commodity price and interest rate risk. Derivative contracts, with the exception of those designated as normal purchase-normal sale contracts, are reported at fair value. SPS’ investments held in rabbi trusts, pension and other postretirement funds are also subject to fair value accounting.

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

Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are recorded as other comprehensive income or deferred as regulatory assets and liabilities. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. The impact of discounting commodity derivative liabilities for credit risk was immaterial at Dec. 31, 2018.

Item 8 — Financial Statements and Supplementary Data

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

See Note 13 to the financial statements for further information.

16

Management Report on Internal Controls Over Financial Reporting

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

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

SPS management assessed the effectiveness of SPS’ internal control over financial reporting as of Dec. 31, 2018. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2018, SPS’ internal control over financial reporting is effective at the reasonable assurance level based on those criteria.

/s/ BEN FOWKE	/s/ ROBERT C. FRENZEL
Ben Fowke	Robert C. Frenzel
Chairman and Chief Executive Officer	Executive Vice President, Chief Financial Officer
Feb. 22, 2019	Feb. 22, 2019

17

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Southwestern Public Service Company

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Southwestern Public Service Company (the "Company") as of December 31, 2018 and 2017, the related statements of income, comprehensive income, cash flows and, common stockholder's equity for each of the three years in the period ended December 31, 2018, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 22, 2019

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

18

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF INCOME

(amounts in millions)

	Year Ended Dec. 31
	2018			2017			2016
Operating revenues	$	1,933.2		$	1,918.0		$	1,851.0
Operating expenses
Electric fuel and purchased power	1,043.5			1,055.3			1,035.0
Operating and maintenance expenses	282.7			285.4			265.5
Demand side management program expenses	17.7			15.5			16.0
Depreciation and amortization	209.6			193.9			162.4
Taxes (other than income taxes)	68.0			67.0			60.8
Total operating expenses	1,621.5			1,617.1			1,539.7
Operating income	311.7			300.9			311.3
Other expense, net	(3.0		)	(1.8		)	(3.9		)
Allowance for funds used during construction — equity	19.1			9.3			10.0
Interest charges and financing costs
Interest charges — includes other financing costs of $2.9, $2.5 and $3.1, respectively	84.5			86.2			88.7
Allowance for funds used during construction — debt	(8.9		)	(5.4		)	(5.6		)
Total interest charges and financing costs	75.6			80.8			83.1
Income before income taxes	252.2			227.6			234.3
Income taxes	38.9			68.4			82.1
Net income	$	213.3		$	159.2		$	152.2

See Notes to Financial Statements

19

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF COMPREHENSIVE INCOME

(amounts in millions)

	Year Ended Dec. 31
	2018		2017		2016
Net income	$	213.3	$	159.2	$	152.2
Other comprehensive income (loss)
Pension and retiree medical benefits:
Amortization of losses (gains) included in net periodic benefit cost (net of tax of $0, $0, and $(0.1), respectively)	—		0.1		(0.1		)
Derivative instruments:
Reclassification of losses to net income (net of tax of $0, $0.1, and $0.1, respectively)	0.1		—		0.1
Other comprehensive income	0.1		0.1		—
Comprehensive income	$	213.4	$	159.3	$	152.2

See Notes to Financial Statements

20

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF CASH FLOWS

(amounts in millions)

	Year Ended Dec. 31
	2018			2017			2016
Operating activities
Net income	$	213.3		$	159.2		$	152.2
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	210.0			193.9			163.0
Demand side management program amortization	1.7			1.7			—
Deferred income taxes	22.1			126.5			123.0
Allowance for equity funds used during construction	(19.1		)	(9.3		)	(10.0		)
Provision for bad debts	4.9			5.1			6.1
Net derivative losses	0.1			0.1			0.2
Changes in operating assets and liabilities:
Accounts receivable	(19.5		)	(10.4		)	(8.9		)
Accrued unbilled revenues	15.3			(10.4		)	(15.6		)
Inventories	(16.0		)	(1.9		)	(1.0		)
Prepayments and other	0.5			4.3			22.7
Accounts payable	(6.6		)	11.8			13.8
Net regulatory assets and liabilities	38.2			38.1			(55.7		)
Other current liabilities	11.6			3.4			5.2
Pension and other employee benefit obligations	(16.0		)	(21.7		)	(15.3		)
Other, net	5.8			(19.9		)	8.1
Net cash provided by operating activities	446.3			470.5			387.8
Investing activities
Utility capital/construction expenditures	(1,020.9		)	(550.6		)	(502.5		)
Proceeds from insurance recoveries	—			—			3.9
Investments in utility money pool arrangement	(285.0		)	(142.0		)	(75.0		)
Receipts from utility money pool arrangement	350.0			77.0			75.0
Other	—			(0.5		)	(1.3		)
Net cash used in investing activities	(955.9		)	(616.1		)	(499.9		)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	42.0			(50.0		)	35.0
Proceeds from issuance of long-term debt	295.0			442.3			296.0
Repayment of long-term debt, including reacquisition premiums	—			(271.6		)	(200.0		)
Borrowings under utility money pool arrangement	595.0			335.0			636.5
Repayments under utility money pool arrangement	(595.0		)	(335.0		)	(636.5		)
Capital contributions from parent	336.8			143.7			66.2
Dividends paid to parent	(131.0		)	(108.8		)	(85.1		)
Net cash provided by financing activities	542.8			155.6			112.1
Net change in cash and cash equivalents	33.2			10.0			—
Cash and cash equivalents at beginning of year	10.8			0.8			0.8
Cash and cash equivalents at end of year	$	44.0		$	10.8		$	0.8
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(71.2	)	$	(76.0	)	$	(78.2	)
Cash (paid) received for income taxes, net	(10.6		)	41.5			61.8
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	71.5		$	85.1		$	49.5
Inventory transfer additions in PPE	22.5			13.7			22.6
Allowance for equity funds used during construction	19.1			9.3			10.0

See Notes to Financial Statements

21

SOUTHWESTERN PUBLIC SERVICE CO.

BALANCE SHEETS

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

	Dec. 31
	2018			2017
Assets
Current assets
Cash and cash equivalents	$	44.0		$	10.8
Accounts receivable, net	90.7			79.6
Accounts receivable from affiliates	10.5			1.3
Investments in money pool arrangements	—			65.0
Accrued unbilled revenues	114.5			129.8
Inventories	33.9			40.4
Regulatory assets	26.0			31.5
Derivative instruments	17.8			15.9
Prepaid taxes	14.2			15.0
Prepayments and other	10.7			10.4
Total current assets	362.3			399.7
Property, plant and equipment, net	5,946.4			5,095.6
Other assets
Regulatory assets	366.2			362.9
Derivative instruments	15.8			19.0
Other	5.1			11.3
Total other assets	387.1			393.2
Total assets	$	6,695.8		$	5,888.5
Liabilities and Equity
Current liabilities
Short-term debt	$	42.0		$	—
Accounts payable	191.8			211.8
Accounts payable to affiliates	19.9			22.6
Regulatory liabilities	85.8			68.8
Taxes accrued	41.6			35.2
Accrued interest	25.8			23.3
Dividends payable	45.2			26.8
Derivative instruments	3.6			3.6
Other	28.3			29.6
Total current liabilities	484.0			421.7
Deferred credits and other liabilities
Deferred income taxes	619.1			574.9
Regulatory liabilities	780.9			784.6
Asset retirement obligations	32.4			28.5
Derivative instruments	16.4			20.0
Pension and employee benefit obligations	92.4			90.3
Other	7.9			8.3
Total deferred credits and other liabilities	1,549.1			1,506.6
Commitments and contingencies
Capitalization
Long-term debt	2,126.1			1,829.9
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2018 and 2017, respectively	—			—
Additional paid in capital	1,932.3			1,590.2
Retained earnings	605.7			541.6
Accumulated other comprehensive loss	(1.4		)	(1.5		)
Total common stockholder’s equity	2,536.6			2,130.3
Total liabilities and equity	$	6,695.8		$	5,888.5

See Notes to Financial Statements

22

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

(amounts in millions, except share data)

	Common Stock Issued								Accumulated Other Comprehensive Income (Loss)			Total Common Stockholder’s Equity
	Shares	Par Value		Additional Paid In Capital		Retained Earnings
Balance at Dec. 31, 2015	100	$	—	$	1,371.2	$	438.0		$	(1.3	)	$	1,807.9
Net income						152.2						152.2
Common dividends declared to parent						(103.5		)				(103.5		)
Contribution of capital by parent				75.0								75.0
Balance at Dec. 31, 2016	100	$	—	$	1,446.2	$	486.7		$	(1.3	)	$	1,931.6
Net income						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 income									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

See Notes to Financial Statements

23

NOTES TO FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

General— SPS is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity.

SPS’ financial statements 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.

SPS has evaluated the impact of events occurring after Dec. 31, 2018 up to the date of issuance of these financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.

Use of Estimates— SPS uses estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used on items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. Recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results.

Regulatory Accounting— SPS accounts for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

• Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and

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

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

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

See Note 4 for further information.

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

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

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

Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized.

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

Recognition of changes in uncertain tax positions are reflected as a component of income tax.

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

Xcel Energy Inc. and its subsidiaries, including SPS, files consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.

See Notes 4 and 7 for further information.

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

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

24

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

See Note 3 for further information.

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

See Note 10 for further information.

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

Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.

See Note 9 for further information.

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

Estimated remediation costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for SPS’ expected share of the cost.

Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 10 for further information.

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

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

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

See Note 6 for further information.

Cash and Cash Equivalents— SPS considers investments in instruments with a remaining maturity of three months or less at the time of purchase, to be cash equivalents.

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

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

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

See Notes 8 and 9 for further information.

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

Normal Purchases and Normal Sales — SPS 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.

25

Other Utility Items

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

Alternative Revenue — Certain rate rider mechanisms (including DSM programs) qualify as alternative revenue programs under GAAP. 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, such as collection within 24 months, revenue is recognized equal to the revenue requirement, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between the total amount collected and the revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers in the period earned.

See Note 6 for further information.

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

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

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

RECs — Cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. SPS reduces recoverable fuel costs for the cost of RECs and records that cost as a regulatory asset when the amount is recoverable in future rates.

Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.

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

2. Accounting Pronouncements

Recently Issued

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

Recently Adopted

Revenue Recognition — In 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 implemented the guidance on a modified retrospective basis on Jan. 1, 2018. Results for reporting periods beginning after Dec. 31, 2017 are presented in accordance with Topic 606, while prior period results have not been adjusted and continue to be reported in accordance with prior accounting guidance. The implementation did not have a material impact on SPS’ financial statements, other than increased disclosures regarding revenues related to contracts with customers.

Classification and Measurement of Financial Instruments — In 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which eliminated the available-for-sale classification for marketable equity securities and also replaced the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. SPS implemented the guidance on Jan. 1, 2018 and the adoption impacts were not material.

Presentation of Net Periodic Benefit Cost —In 2017, the FASB issued Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715 (ASU No. 2017-07), which establishes that only the service cost portion of pension cost may be presented as a component of operating income. In addition, only the service cost portion of pension cost is eligible for capitalization. As a result of regulatory accounting treatment, a similar amount of pension cost, including non-service components, will be recognized consistent with historical ratemaking and the impacts of adoption are limited to changes in classification of non-service costs in the statement of income.

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

26

3. Property, Plant and Equipment

Major classes of property, plant and equipment:

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

4. Regulatory Assets and Liabilities

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

Components of regulatory assets:

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

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

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

Components of regulatory liabilities:

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

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

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

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

27

5. Borrowings and Other Financing Instruments

Short-Term Borrowings

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

Money pool borrowings for SPS were as follows:

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

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

Commercial paper outstanding for SPS was as follows:

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

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

Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, SPS must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility.

The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

Features of SPS’ credit facility:

Debt-to-Total Capitalization Ratio(a)		Amount Facility May Be Increased (millions)	Additional Periods For Which a One-Year Extension May Be Requested (b)
2018	2017
46%	46%	$50	2

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

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

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

If SPS does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2018, SPS was in compliance with all financial covenants.

SPS had the following committed credit facilities available as of Dec. 31, 2018.

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

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

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

28

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

Long-Term Borrowings and Other Financing Instruments

Generally, all property of SPS is subject to the lien of its first mortgage indenture. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance.

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

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

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

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

2018 financings:

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

2017 financings:

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

Capital Stock — SPS has the following preferred stock:

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

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

SPS’ state regulatory commission imposes the most restrictive dividend limitations.

Requirements and actuals as of Dec. 31, 2018:

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

^(a)  SPS excludes short-term debt.

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

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

6. Revenues

Revenue is classified by the type of goods/services rendered and market/customer type. SPS’ operating revenues (subsequent to adoption of the revised revenue guidance) consists of the following:

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

7. Income Taxes

Federal Tax Reform— In 2017, the TCJA was signed into law. The key provisions impacting Xcel Energy (which includes SPS), generally beginning in 2018, include:

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

• Normalization of resulting plant-related excess deferred taxes;

• Elimination of the corporate alternative minimum tax;

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

• Limitations on certain executive compensation deductions;

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

• Repeal of the section 199 manufacturing deduction; and,

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

Xcel Energy estimated the effects of the TCJA, which have been reflected in the consolidated financial statements.

29

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

Estimated impacts of the new tax law for SPS in December 2017 included:

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

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

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

Xcel Energy accounted for the state tax impacts of federal tax reform based on enacted state tax laws. Any future state tax law changes related to the TCJA will be accounted for in the periods state laws are enacted.

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

Tax Year(s)	Expiration
2009 - 2014	October 2019
2015	September 2019
2016	September 2020
2017	September 2021

In 2012, the IRS commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. In 2017, Xcel Energy and the Office of Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. SPS did not accrue any income tax benefit related to this adjustment. In the second quarter of 2018, the Joint Committee on Taxation completed its review and took no exception to the agreement. As a result, the remaining unrecognized tax benefit was released and recorded as a payable to the IRS.

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy filed a protest with the IRS. As of Dec. 31, 2018, the case has been forwarded to the Office of Appeals and Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.

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

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2018, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2010. There are currently no state income tax audits in progress.

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

Unrecognized tax benefits - permanent vs temporary:

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

Changes in unrecognized tax benefits:

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

Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:

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

Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $0.8 million and $2.7 million at Dec. 31, 2018 and Dec. 31, 2017, respectively.

As the IRS Appeals and federal audit progress and state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $3.6 million in the next 12 months.

Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.

Interest payable related to unrecognized tax benefits:

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

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

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

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

30

Federal carryforward periods expire between 2021 and 2038 and state carryforward periods expire between 2021 and 2036.

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.

Effective income tax rate for years ended Dec. 31:

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

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

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

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

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

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

Components of deferred income tax expense as of Dec. 31:

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

Components of the net deferred tax liability as of Dec. 31:

(Millions of Dollars)	2018		2017
Deferred tax liabilities:
Differences between book and tax bases of property	$	680.6	$	654.4
Regulatory assets	49.2		46.8
Pension expense	32.3		33.8
Other	2.9		4.6
Total deferred tax liabilities	$	765.0	$	739.6
Deferred tax assets:
Regulatory liabilities	116.8		114.6
NOL carryforward	0.2		26.2
Deferred fuel costs	12.7		10.4
Other employee benefits	5.6		5.8
Tax credit carryforward	5.7		5.2
Other	4.9		2.5
Total deferred tax assets	$	145.9	$	164.7
Net deferred tax liability	$	619.1	$	574.9

8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance.

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

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

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

Specific valuation methods include:

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

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

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

31

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 insignificant 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.

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, 2018, accumulated other comprehensive losses related to interest rate derivatives included $0.1 million net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

Wholesale and Commodity Trading Risk — SPS conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments, including derivatives. SPS 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, 2018 and 2017:

(Amounts in Millions)(a)	Dec. 31, 2018	Dec. 31, 2017
MWh of electricity	5.5	4.3

^(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, 2018, two of the eight most significant counterparties for these activities, comprising $11.6 million or 28% of this credit exposure, had investment grade ratings from Standard & Poor’s, Moody’s or Fitch Ratings. Five of the eight most significant counterparties, comprising $8.7 million or 21% of this credit exposure, were not rated by external rating agencies, but based on SPS’ internal analysis, had credit quality consistent with investment grade. Another of these significant counterparties, comprising $0.6 million or less than 1% of this credit exposure, had credit quality less than investment grade, based on external analysis. Six of these significant counterparties are municipal or cooperative electric entities, 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)	2018			2017			2016
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(0.8	)	$	(0.7	)	$	(0.8	)
After-tax net realized losses on derivative transactions reclassified into earnings	0.1			—			0.1
Adoption of ASU. 2018-02 (a)	—			(0.1		)	—
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(0.7	)	$	(0.8	)	$	(0.7	)

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

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

Changes in the fair value of FTRs resulting in pre-tax net gains of $7.0 million, $0.5 million and $3.0 million recognized for the years ended Dec. 31, 2018, 2017 and 2016, respectively, were reclassified as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on expected recovery of FTR settlements through fuel and purchased energy cost recovery mechanisms.

FTR settlement gains of $4.4 million, $0.8 million and $2.1 million were recognized for the years ended Dec. 31, 2018, 2017 and 2016, respectively, and 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 no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2018, 2017 and 2016.

32

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2018 and 2017:

	Dec. 31, 2018													Dec. 31, 2017
	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	$	—	$	—	$	14.9	$	14.9	$	(0.2	)	$	14.7	$	—	$	—	$	14.7	$	14.7	$	(2.0	)	$	12.7
Total current derivative assets	$	—	$	—	$	14.9	$	14.9	$	(0.2	)	14.7		$	—	$	—	$	14.7	$	14.7	$	(2.0	)	12.7
PPAs (b)												3.1													3.2
Current derivative instruments												$	17.8												$	15.9
Noncurrent derivative assets
PPAs (b)												15.8													19.0
Noncurrent derivative instruments												$	15.8												$	19.0
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	0.2	$	0.2	$	(0.2	)	$	—	$	—	$	—	$	2.0	$	2.0	$	(2.0	)	$	—
Total current derivative liabilities	$	—	$	—	$	0.2	$	0.2	$	(0.2	)	—		$	—	$	—	$	2.0	$	2.0	$	(2.0	)	—
PPAs (b)												3.6													3.6
Current derivative instruments												$	3.6												$	3.6
Noncurrent derivative liabilities
PPAs (b)												16.4													19.9
Noncurrent derivative instruments												$	16.4												$	19.9

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

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

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

	Year Ended Dec. 31
(Millions of Dollars)	2018			2017			2016
Balance at Jan. 1	$	12.7		$	2.0		$	5.1
Purchases	32.3			41.2			7.6
Settlements	(41.6		)	(55.8		)	(41.9		)
Net transactions recorded during the period:
Net gains recognized as regulatory assets	11.3			25.3			31.2
Balance at Dec. 31	$	14.7		$	12.7		$	2.0

SPS recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for 2016 - 2018.

Fair Value of Long-Term Debt

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

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

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, 2018 and 2017, 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

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

In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions funded by Xcel Energy’s consolidated operating cash flows. Obligations of the SERP and nonqualified plan as of Dec. 31, 2018 and 2017 were $33 million and $37 million, respectively, of which $2 million was attributable to SPS in 2018 and 2017. In 2018 and 2017, Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $4 million and $5 million, respectively, of which immaterial amounts were attributable to SPS.

33

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’s operating cash flows.

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

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

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

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

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

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

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

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

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

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

State agencies also have issued guidelines to the funding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for Texas and New Mexico amounts collected in rates. These assets are invested in a manner consistent with the investment strategy for the pension plan.

Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios.

Pension Plan Assets

The following presents, for each of the fair value hierarchy levels, SPS’ pension plan assets measured at fair value:

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

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

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

^(a)  See Note 8 for further information on fair value measurement inputs and methods.

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

34

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

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

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

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

35

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

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

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

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

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

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

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 2016 - 2019 to meet minimum funding requirements.

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

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

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

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

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

For future years, Xcel Energy and SPS 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 $11 million during 2019;

• $11 million during 2018;

• $20 million during 2017; and,

• $18 million during 2016.

• Amounts attributable to SPS were immaterial.

36

Target asset allocations:

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

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

Projected Benefit Payments

SPS’ projected benefit payments:

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

Defined Contribution Plans

Xcel Energy, which includes SPS, maintains 401(k) and other defined contribution plans that cover most employees. The expense to these plans for SPS was approximately $3 million in 2018, 2017 and 2016.

10. Commitments and Contingencies

Legal

SPS is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves complex judgments about future events. Management maintains accruals for losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

For current proceedings not specifically reported herein, management does not anticipate 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

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.  The SPP OATT has allowed SPP to charge for these upgrades since 2008, but SPP had not been charging its customers for these upgrades.  In 2016, the FERC granted SPP’s request to recover the charges not billed since 2008.  SPP subsequently billed SPS approximately $13 million for these charges.

In July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP the right to recover these charges was remanded to the FERC. SPS’ recovery of these charges (from 2008 through 2016) is being reviewed by the FERC, which is expected to rule in the first quarter of 2019.

In October 2017, SPS filed a complaint against SPP regarding the amounts billed asserting that SPP has assessed upgrade charges to SPS in violation of the SPP OATT. The FERC has granted a rehearing of further consideration in May 2018. The timing of the FERC action on the SPS rehearing is uncertain. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the differential in future rate proceedings.

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

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

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

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

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

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 its 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.

37

MGP, Landfill or Disposal Sites— SPS is currently investigating or remediating one MGP, landfill or other disposal site across its service territories, and these activities will continue through at least 2019. SPS accrued $0.1 million as of Dec. 31, 2018 and 2017, respectively, for this site. There may be insurance recovery and/or recovery from other potentially responsible parties, offsetting some 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”. The Rule has been subject to significant litigation and is currently stayed in a portion of the country. SPS cannot estimate potential impacts until the legal and administrative processes are finalized, but expects 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 will be immaterial.

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

Environmental Requirements — Air

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

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

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

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

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

AROs — AROs have been recorded for SPS’ assets.

SPS’ AROs were as follows:

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

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

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

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

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

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

Indeterminate AROs — Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of SPS’ facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2018. 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. 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.

38

These 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, 2018 and 2017 were $188 million and $197 million respectively.

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

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

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

Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases.

Future commitments under operating leases are:

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

^(a)  Amounts do not include PPAs accounted for as executory contracts.

^(b)  PPA operating leases contractually expire through 2033.

Non-Lease PPAs — SPS has entered into PPAs with other utilities and energy suppliers with expiration dates through 2033 for purchased power to meet system load and energy requirements and meet operating reserve obligations.

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 our financial results are mitigated through purchased energy cost recovery mechanisms.

Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts, were payments for capacity of $57.6 million, $58.4 million and $56.8 million in 2018, 2017 and 2016, respectively.

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

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

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

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

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

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

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

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

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

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

39

11. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the year ended Dec. 31:

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

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

^(a)  Included in interest charges.

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

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

12. Related Party Transactions

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

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

See Note 5 for further information.

Significant affiliate transactions among the companies and related parties for the years ended Dec. 31:

(Millions of Dollars)	2018		2017		2016
Operating expenses:
Purchased power	$	—	$	1.4	$	8.8
Other operating expenses — paid to Xcel Energy Services Inc.	195.1		196.6		188.2
Interest expense	0.6		—		0.2

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

	2018				2017
(Millions of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	4.7	$	—	$	1.0	$	—
PSCo	—		0.7		—		0.3
Other subsidiaries of Xcel Energy Inc.	5.8		19.2		0.3		22.3
	$	10.5	$	19.9	$	1.3	$	22.6

13. Summarized Quarterly Financial Data (Unaudited)

	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	57.1		87.6		111.0		56.0
Net income	33.1		58.5		81.5		40.2

	Quarter Ended
(Millions of Dollars)	March 31, 2017		June 30, 2017		Sept. 30, 2017		Dec. 31, 2017
Operating revenues	$	460.1	$	479.8	$	551.6	$	426.5
Operating income (a)	59.2		75.2		123.1		43.4
Net income	25.1		35.3		67.8		31.0

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

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

None.

Item 9A — Controls and Procedures

Disclosure Controls and Procedures

SPS maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in 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 and chief financial officer, allowing timely decisions regarding required disclosure.

As of Dec. 31, 2018, based on an evaluation carried out under the supervision and with the participation of SPS’ management, including the chief executive officer and chief financial officer, of the effectiveness of its disclosure controls and the procedures, the chief executive officer and chief financial officer have concluded that SPS’ disclosure controls and procedures were effective.

40

Internal Control Over Financial Reporting

No change in SPS’ internal control over financial reporting has occurred during SPS’ most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, SPS’ internal control over financial reporting. SPS maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. SPS has evaluated and documented its controls in process activities, general computer activities, and on an entity-wide level. During the year and in preparation for issuing its report for the year ended Dec. 31, 2018, on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, SPS conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, SPS did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board and as approved by the SEC and as indicated in Management Report on Internal Controls herein.

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

Item 9B — Other Information

None.

PART III

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

Item 10 — Directors, Executive Officers and Corporate Governance

Item 11 — Executive Compensation

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

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

Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2019 Annual Meeting of Shareholders, which is incorporated by reference.

Item 14 — Principal Accountant Fees and Services

The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm – Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the 2019 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 1, 2019. Such information set forth under such heading is incorporated herein by this reference hereto.

PART IV

Item 15 — Exhibits, Financial Statement Schedules

1	Financial Statements
	Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2018.
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Statements of Income — For the three years ended Dec. 31, 2018, 2017 and 2016.
	Statements of Comprehensive Income — For the three years ended Dec. 31, 2018, 2017 and 2016.
	Statements of Cash Flows — For the three years ended Dec. 31, 2018, 2017 and 2016.
	Balance Sheets — As of Dec. 31, 2018 and 2017.
	Statements of Common Stockholder’s Equity — For the three years ended Dec. 31, 2018, 2017 and 2016.
2	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2018, 2017 and 2016.
3	Exhibits

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

Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.01*	Amended and Restated Articles of Incorporation dated Sept. 30, 1997	SPS Form 10-Q for the quarter ended Sept. 30, 2017	001-03789	3.01
3.02	By-Laws of SPS as Amended and Restated on Jan. 25, 2019
4.01*	Indenture dated Feb. 1, 1999 between SPS and the Chase Manhattan Bank	SPS Form 8-K dated Feb. 25, 1999	001-03789	99.2
4.02*	Third Supplemental Indenture dated Oct. 1, 2003 to the indenture dated Feb. 1, 1999 between SPS and JPMorgan Chase Bank, as successor Trustee, creating $100 million principal amount of Series C and Series D Notes, 6% due 2033	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2003	001-03034	4.04
4.03*	Fourth Supplemental Indenture dated Oct. 1, 2006 between SPS and the Bank of New York, as successor Trustee	SPS Form 8-K dated Oct. 3, 2006	001-03789	4.01
4.04*	Indenture dated as of Aug. 1, 2011 between SPS and U.S. Bank National Association, as Trustee	SPS Form 8-K dated Aug. 10, 2011	001-03789	4.01
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% First Mortgage Bonds, Series No. 1 due 2041	SPS Form 8-K dated Aug. 10, 2011	001-03789	4.02
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	SPS Form 8-K dated June 2, 2014	001-03789	4.03

41

4.07*	Supplemental Indenture No. 3 dated as of June 1, 2014 between SPS and U.S. Bank National Association, as Trustee, creating $150 million principal amount of 3.30% First Mortgage Bonds, Series No. 3 due 2024	SPS Form 8-K dated June 9, 2014	001-03789	4.02
4.08*	Supplemental Indenture dated as of Aug. 1, 2016 between SPS and U.S. Bank National Association, as Trustee, creating $300 million principal amount of 3.40% First Mortgage Bonds, Series No. 4 due 2046	SPS Form 8-K dated Aug. 12, 2016	001-03789	4.02
4.09*	Supplemental Indenture dated as of Aug. 1, 2017 between SPS and U.S. Bank National Association, as Trustee, creating $450 million principal amount of 3.70% First Mortgage Bonds, Series No. 5 due 2047	SPS Form 8-K dated Aug. 9, 2017	001-03789	4.02
4.10*	Supplemental Indenture No. 6 dated as of Oct. 1, 2018 between SPS and U.S. Bank National Association, as Trustee, creating 4.40% First Mortgage Bonds, Series No. 6 due 2048	SPS Form 8-K dated Nov. 5, 2018	001-03789	4.02
10.01*+	Xcel Energy Inc. Nonqualified Pension Plan (2009 Restatement)	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	001-03034	10.02
10.02*+	Xcel Energy Senior Executive Severance and Change-in-Control Policy (2009 Restatement)	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	001-03034	10.05
10.03*+	Xcel Energy Inc. Non-Employee Directors Deferred Compensation Plan as amended and restated Jan. 1, 2009	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	001-03034	10.08
10.04*+	Form of Services Agreement between Xcel Energy Services Inc. and utility companies	Xcel Energy Inc. Form U5B dated Nov. 16, 2000	001-03034	H-1
10.05*+	Xcel Energy Inc. Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	001-03034	10.17
10.06*+	Amendment dated Aug. 26, 2009 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009	001-03034	10.06
10.07*+	Xcel Energy Inc. Executive Annual Incentive Award Plan Form of Restricted Stock Agreement	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009	001-03034	10.08
10.08*+	Xcel Energy Inc. Executive Annual Incentive Plan (as amended and restated effective Feb. 17, 2010)	Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010	001-03034	Schedule 14A
10.09*+	Xcel Energy Inc. 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010)	Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010	001-03034	Schedule 14A
10.10*+	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy Inc. as amended and restated effective Feb. 23, 2011	Xcel Energy Inc. Definitive Proxy Statement dated April 5, 2011	001-03034	Schedule 14A
10.11*+	Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement)	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008	001-03034	10.07
10.12*+	Second Amendment to Exhibit 10.02 dated Oct. 26, 2011	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011	001-03034	10.18
10.13*+	First Amendment to Exhibit 10.11 effective Nov. 29, 2011	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011	001-03034	10.17
10.14*+	First Amendment to Exhibit 10.08 dated Feb. 20, 2013	Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013	001-03034	10.01
10.15*+	Fourth Amendment to Exhibit 10.02 dated Feb. 20, 2013	Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013	001-03034	10.02
10.16*+	First Amendment to Exhibit 10.09 dated May 21, 2013	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013	001-03034	10.21
10.17*+	Second Amendment to Exhibit 10.11 dated May 21, 2013	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013	001-03034	10.22
10.18*+	Xcel Energy Inc. 2005 Long-Term Incentive Plan Form of Long-Term Incentive Award Agreement	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013	001-03034	10.23
10.19*+	Xcel Energy Inc. 2015 Omnibus Incentive Plan	Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2015	001-03034	Schedule 14A
10.20*+	Stock Equivalent Program for Non-Employee Directors of Xcel Energy Inc. under the Xcel Energy Inc. 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 8-K dated May 20, 2015	001-03034	10.02
10.21*+	Form of Xcel Energy Inc. 2015 Omnibus Incentive Plan Award Agreement and Award Terms and Conditions under the Xcel Energy Inc. 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 8-K dated May 20, 2015	001-03034	10.03
10.22*+	Xcel Energy Inc. 2015 Omnibus Incentive Plan Form of Award Agreement	Xcel Energy inc. Form 10-K for the year ended Dec. 31, 2015	001-03034	10.28
10.23*+	Xcel Energy Inc. Executive Annual Incentive Award Sub-plan pursuant to the Xcel Energy Inc. 2015 Omnibus Incentive Plan	Xcel Energy inc. Form 10-K for the year ended Dec. 31, 2015	001-03034	10.29
10.24*+	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
10.25*	Second Amended and Restated Credit Agreement, dated as of June 20, 2016 among SPS, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Documentation Agents	Xcel Energy Inc. Form 8-K dated June 20, 2016	001-03034	99.04
10.26*+	Third Amendment to Exhibit 10.11 dated Sept. 30, 2016	Xcel Energy inc. Form 10-Q for the quarter ended Sept. 30, 2016	001-03034	10.01
10.27*+	Form of Xcel Energy, Inc. 2015 Omnibus Incentive Plan Award Agreement and Award Terms and Conditions under the Xcel Energy inc. 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2016	001-03034	10.27
10.28*+	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
10.29*+	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

42

10.30*+	Seventh Amendment to Exhibit 10.02 dated May 7, 2018	Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018	001-03034	10.01
10.31*+	Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	001-03034	10.34
10.32*+	Form of Xcel Energy Inc. 2015 Omnibus Incentive Plan Award Agreement Terms and Conditions under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	001-03034	10.35
10.33*+	Stock Program for Non-Employee Directors of Xcel Energy Inc. as Amended and Restated on Dec. 12, 2017 under the 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	001-03034	10.36
23.01	Consent of Independent Registered Public Accounting Firm.
31.01	Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101	The following materials from SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2018 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Statements of Income, (ii) the Statements of Comprehensive Income, (iii) the Statements of Cash Flows, (iv) the Balance Sheets, (v) the Statements of Stockholder’s Equity, (vi) Notes to Financial Statements, (vii) document and entity information, and (viii) Schedule II.

SCHEDULE II

SOUTHWESTERN PUBLIC SERVICE CO.

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DEC. 31, 2018, 2017 AND 2016

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

^(a)  Recovery of amounts previously written off.

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

Item 16 — Form 10-K Summary

None.

43

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

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

/s/ BEN FOWKE	/s/ DAVID T. HUDSON
Ben Fowke	David T. Hudson
Chairman, Chief Executive Officer and Director	President and Director
(Principal Executive Officer)
/s/ ROBERT C. FRENZEL	/s/ JEFFREY S. SAVAGE
Robert C. Frenzel	Jeffrey S. Savage
Executive Vice President, Chief Financial Officer and Director	Senior Vice President, Controller
(Principal Financial Officer)	(Principal Accounting Officer)
/s/ DAVID L. EVES
David L. Eves
Executive Vice President and Director

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

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

44

EX-3.02

Exhibit 3.02

SOUTHWESTERN PUBLIC SERVICE COMPANY

AMENDED AND RESTATED BYLAWS

(as amended and restated January 25, 2019)

ARTICLE I

Shareholders

Section 1.    Annual Meeting. The annual meeting of the shareholders of the Company for the election of directors and for the transaction of any other business that may be properly brought before the meeting shall be held at a place, date, and hour designated by either the Chairman of the Board or the President or by resolution of the Board of Directors.

Section 2.    Special Meetings. Special meetings of the shareholders for any purpose or purposes shall be called by the Secretary upon receipt of a written request from the Chairman of the Board, the President, a majority of the directors, or any person or persons authorized by the New Mexico Business Corporation Act (the “Act”) to request such a meeting. Special meetings of the shareholders shall be held at a place, date, and hour designated by the Chairman of the Board, the President, or by resolution of the Board of Directors.

Section 3.    Notice. Written notice of all meetings of shareholders stating the place, date, and hour of the meeting and, in the case of special meetings, the purpose or purposes for which the meeting is called, shall be given to each shareholder entitled to vote at such meeting not less than ten or more than 50 days before the date of the meeting, either by mail, electronic mail, facsimile telephone, personal service or any other means as may be permitted by law. Attendance at a meeting constitutes a waiver of notice, except where the shareholder attends a meeting for the express purpose of objecting to the transaction of any business because the meeting is not lawfully called or convened.

Section 4.    Procedure. At each meeting of the shareholders, the Chairman of the Board or, in his or her absence, the President shall act as chairman of the meeting. The chairman of the meeting shall determine the order of business and all other matters of procedure. The chairman of the meeting may establish rules to maintain order and to conduct the meeting. The chairman of the meeting shall act in his or her absolute discretion, and his or her rulings are not subject to appeal.

Section 4.    Action Without a Meeting. An action required or permitted to be taken at a meeting of the shareholders may be taken without a meeting by written action signed, or consented to by authenticated electronic communication, by all of the shareholders entitled to a vote on such action. The written action is effective when it

has been signed, or consented to, by all of those shareholders, unless a different time is provided in the written action.

ARTICLE II

Directors

Section 1.    Board of Directors. The business of the Company shall be managed by a Board of Directors. The number of directors constituting the Board of Directors shall be established from time to time by resolution of the Board of Directors, subject to any limitations set forth in the Amended and Restated Articles of Incorporation. A Chairman of the Board may be chosen from among the directors.

Section 2.    Regular Meetings. Regular meetings of the Board of Directors may be held without notice at times and places determined by the Board of Directors. Attendance of a director at a meeting constitutes a waiver of notice of the meeting, except where a director attends a meeting for the express purpose of objecting to the transaction of any business because the meeting is not lawfully called or convened.

Section 3.    Special Meetings. Special meetings of the Board of Directors may be called by a director or by the chief executive officer of the Company on 24 hours’ notice to all directors of the date, time and place of the meeting. The notice shall be given to each director by mail, electronic mail, facsimile telephone, personal service or any other means as may be permitted by law and need not state the purpose of the meeting.

Section 4.    Adjournment of Meetings. The directors may adjourn from time to time any regular or special meeting at which a quorum is present, without notice other than announcement at the meeting. The adjourned meeting may be called to order at any time without further notice, and any business may be transacted which might have been transacted at the original meeting.

Section 5.    Authority to Appoint Committees and Delegate Authority. The Board of Directors, by resolution adopted by a majority of the full Board of Directors, may designate from among its members one or more committees, each of which, except to the extent limited by law, the Amended and Restated Articles of Incorporation, these Bylaws, and the resolution establishing the committee, shall have and may exercise all of the authority of the Board of Directors, and may also prescribe rules of operation of the committee. Regular meetings of any committee may be held without notice at times and places determined by the Board of Directors or the committee. Special meetings of any committee shall be called by the Secretary upon the receipt of a request from the Chairman of the Board, the President, the chairman of the committee, or any member of the committee. Notice of special meetings shall be given in the same manner as provided in Section 3 of this Article II.

Section 6.Action Without a Meeting. An action required or permitted to be

2

taken at a board meeting or by a lawfully appointed committee thereof may be taken by written action signed, or consented to by authenticated electronic communication, by all of the directors or by all of the members of such committee, unless the action need not be approved by the shareholders and the Amended and Restated Articles of Incorporation so provide, in which case, the action may be taken by written action signed, or consented to by authenticated electronic communication, by the number of directors that would be required to take the same action at a meeting of the Board of Directors or the committee at which all directors or committee members were present. The written action is effective when signed or consented to by the required number of directors or committee members unless a different effective time is provided in the written action. When written action is permitted to be taken by less than all directors or committee members, all directors and committee members shall be notified immediately of its text and effective date.

ARTICLE III

Officers

Section 1.     Number. The officers of the Company shall be a President, a Secretary, and a Treasurer, and may include a Chairman of the Board, a chief executive officer, a chief financial officer, one or more Vice Presidents (one or more of whom may be designated Executive Vice President, Senior Vice President or as otherwise determined by the Board of Directors), a Controller, and/or a chief accounting officer.

Section 2.     Election and Term of Office. Each officer shall be elected by the Board of Directors and shall hold office until his or her successor has been elected and qualified or until his or her earlier retirement, disability, death, resignation, or removal.

Section 3.     Removal and Vacancies. Any officer may be removed at any time with or without cause by the Board of Directors. A vacancy in any office may be filled for the unexpired portion of the term in the same manner as provided for election to the office.

Section 4.     Assistant Officers. The Company may have such assistant officers as the Board of Directors may elect. Each assistant officer shall hold office at the pleasure of, and may be removed at any time with or without cause by, the Board of Directors. Assistant officers may include one or more Assistant Vice Presidents, Assistant Secretaries, Assistant Treasurers, and Assistant Controllers.

Section 5.     Duties. Each officer shall have the authority and shall perform the duties as may be assigned by the Board of Directors, the Chairman of the Board, or the President, or as shall be conferred or required by law or these Bylaws, or as shall be normally incidental to the office. The President, the chief executive officer, the chief financial officer, and any Vice President of the Company may execute and deliver instruments and contracts on behalf of the Company and otherwise may bind the Company. Unless prohibited by the Board of Directors, an officer may, without the

3

approval of the Board of Directors, delegate in writing to any other person some or all of the duties and powers of his or her office to other persons. The President, the chief executive officer, the chief financial officer, any Vice President of the company, and any other person or persons pursuant to delegated authority or as may be designated or authorized from time to time by the Board of Directors of the chief executive officer may execute and deliver contracts, deeds, mortgages, notes checks, conveyances, releases of mortgages and other instruments on behalf of the Company and otherwise may bind the Company.

ARTICLE IV

Indemnification of Directors, Officers, Employees, and Agents

Section 1.    Mandatory Indemnification. Each person who is a party or is threatened to be made a party, either as plaintiff, defendant, respondent, or otherwise, to any action, suit, or proceeding, whether civil, criminal, administrative, or investigative (a “Proceeding”), based upon, arising from, relating to, or by reason of the fact that such person, or a person of whom such person is the legal representative, is or was a director or officer of the Company, or is or was serving at the request of the Company as a director, officer, partner, trustee, employee, or agent of another foreign or domestic corporation or non‑profit corporation, cooperative, partnership, joint venture, trust, or other incorporated or unincorporated enterprise, or any employee benefit plan or trust (each, a “Company Affiliate”), shall be indemnified and held harmless by the Company to the fullest extent authorized by the Act, as the same exists on the date of the adoption of these Bylaws or as may hereafter be amended (but, in the case of any such amendment, only to the extent that such amendment permits the Company to provide broader indemnification rights than permitted by the Act prior to such amendment), against any and all expenses, liability, and loss (including, without limitation, investigation expenses and expert witnesses’ and attorneys’ fees and expenses, judgments, penalties, fines, and amounts paid or to be paid in settlement) actually incurred by such person in connection therewith. The right to indemnification conferred in this Article IV shall be a contract right and shall include the right to be paid by the Company for expenses incurred in defending or prosecuting any Proceeding in advance of its final disposition.

Any person seeking indemnification pursuant to this Section 1 of Article IV shall submit a written claim and include the undertakings and/or affirmations required by Section 53-11-4.1 of the Act; provided that no person shall be indemnified unless the Company has determined that indemnification is proper under the Act.

For purposes of this Article IV, references to “fines” shall include any excise taxes assessed on a person with respect to any employee benefit plan or trust; and references to “serving at the request of the Company” shall include any service as a director, officer, employee, or agent of the Company which imposes duties on, or involves services by, such director, officer, employee, or agent with respect to an employee benefit plan or trust, its participants, or beneficiaries; and a person who acted

4

in good faith and in a manner such person reasonably believed to be in the interest of the participants and beneficiaries of an employee benefit plan or trust shall be deemed to have acted in a manner “not opposed to the best interests of the Company.”

The Company’s indemnity of any person who was or is serving at its request as a director, officer, partner, trustee, employee, or agent of a Company Affiliate shall be reduced by any amounts such person may collect as indemnification from such Company Affiliate.

Section 2.    Recovery Against the Company. If a claim under Section 1 of this Article IV is not paid in full by the Company within thirty days after a written claim has been received by the Company, except in the case of a claim for expenses to be incurred in defending a Proceeding in advance of its final disposition (in which case the applicable period shall be ten days), the claimant may at any time thereafter bring suit against the Company to recover the unpaid amount of the claim and, if wholly successful, on the merits or otherwise, the claimant shall be entitled to be paid also the expense of prosecuting such claim. The claimant shall be presumed to be entitled to indemnification under this Article IV upon submission of a written claim (and any required undertaking and/or affirmations required by the Act) and thereafter the Company shall have the burden of proof to overcome the presumption that the claimant is not so entitled. Neither the failure of the Company (including its Board of Directors, independent legal counsel, or its shareholders) to have made a determination prior to the commencement of such action that indemnification of the claimant is proper in the circumstances because such person has met the applicable standard of conduct set forth in the Act, nor an actual determination by the Company (including its Board of Directors, independent legal counsel, or its shareholders) that the claimant has not met such applicable standard of conduct, shall be a defense to the action or create a presumption that the claimant has not met the applicable standard of conduct.

Section 3.    Non-Exclusive Right. The right to indemnification and the payment of expenses incurred in defending a Proceeding in advance of its final disposition conferred in this Article IV shall not be exclusive of any other right to which any person may be entitled under any statute, provision of the Amended and Restated Articles of Incorporation, or Bylaw, any agreement, a resolution of shareholders or directors, or otherwise both as to action in such person’s official capacity and as to action in another capacity while holding such office.

Section 4.    Insurance. The Company may purchase and maintain insurance or furnish similar protection, including, but not limited to, providing a trust fund, letter of credit, or self‑insurance, on behalf of any person who is a director, officer, employee, or agent of the Company or who, while a director, officer, employee, or agent of the Company, is serving at the request of the Company as a director, officer, partner, trustee, employee, or agent of a Company Affiliate, against any liability asserted against and incurred by such director, officer, employee, or agent in such capacity or arising out of such director’s, officer’s, employee’s, or agent’s status as such, whether or not the Company would have the power to indemnify such director, officer, employee, or agent

5

against such liability under the Act.

Section 5.    Delegation of Authority. The Company may, by action of its Board of Directors, authorize one or more officers to grant rights to indemnification and advancement of expenses to employees or agents of the Company on such terms and conditions as such officer or officers deem appropriate under the circumstances.

Section 6.     Continuing Effect. The indemnification and advancement of expenses provided by, or granted pursuant to, this Article IV shall, unless otherwise provided when authorized, continue as to a person who has ceased to be a director, officer, employee, or agent and shall inure to the benefit of the heirs, executors, and administrators of such persons. Anything in this Article IV to the contrary notwithstanding, no elimination or amendment of this Bylaw adversely affecting the right of any person to indemnification or advancement of expenses hereunder shall be effective until the sixtieth day following notice to such indemnified person of such action, and no elimination or amendment of these Bylaws shall deprive any such person of such person’s rights hereunder arising out of alleged or actual occurrences, acts, or failures to act which had their origin prior to such sixtieth day.

Section 7.     Severability. In case any provision in this Article IV shall be determined at any time to be unenforceable in any respect, the other provisions shall not in any way be affected or impaired thereby, and the affected provision shall be given the fullest possible enforcement in the circumstances, it being the intention of the Company to afford indemnification and advancement of expenses to the persons indemnified hereby to the fullest extent permitted by law.

ARTICLE V

Share Certificates and Transfer of Shares

Section 1.    Share Certificates. Shares of stock of the Company may, at the discretion of the Board of Directors, be represented by certificates or may be uncertificated. Any share certificates of the Company shall be in the form and contain the provisions determined by the Board of Directors and required by the Act.

Section 2.    Transfer Rules. The Board of Directors, the Chairman of the Board, the President, or the Secretary may from time to time promulgate rules or regulations as it or such officer may deem advisable concerning the issue, transfer, registration, or replacement of share certificates of the Company.

Section 3.    Registered Shareholders. The Company shall be entitled to treat the holder of record of any share or shares as the holder in fact of those shares. The Company shall not be bound to recognize any equitable or other claim to or interest in any shares on the part of any other person, regardless of whether the Company has actual or imputed knowledge of a claim of interest, except as otherwise required by the Act.

6

ARTICLE VI

General Provisions

Section 1.    Fiscal Year. The fiscal year of the Company shall begin on the first day of January and end on the last day of December each year.

Section 2.    Seal. The Company may, but need not, have a corporate seal. If the Company has a corporate seal, the use of the seal by the Company on a document is not required, and the use or nonuse of the seal does not affect the validity, recordability, or enforceability of a document or act. The seal of the Company need only include the name of the Company. If a corporate seal is used, it or a facsimile of it may be affixed, engraved, printed, placed, stamped with indelible ink, or in any other manner reproduced on any document.

Section 3.     Voting of Shares of Other Corporations. The shares of any other corporation owned by the Company may be voted at any meeting of the shareholders of such other corporation by such proxy as the Board of Directors of the Company may appoint, or if no such appointment be made, by the chief executive officer.

Section 4.    Dividends. Subject to any restrictions set forth in the Amended and Restated Articles of Incorporation, dividends on the shares of the Company may be declared by the Board of Directors at any regular or special meeting, pursuant to the Act.

ARTICLE VII

Amendments

These Bylaws may be altered, amended, or repealed by the affirmative vote of a majority of the Board of Directors then in office. These Bylaws may also be altered, amended, or repealed by the shareholders by the affirmative vote of the holders of a majority in interest of the shares issued and outstanding and entitled to vote.

* * * * *

7

EX-23.01

Exhibit 23.01

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-224333-01 on Form S-3 of our report dated February 22, 2019, relating to the financial statements and financial statement schedule of Southwestern Public Service Company appearing in this Annual Report on Form 10-K of Southwestern Public Service Company for the year ended December 31, 2018.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 22, 2019

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Ben Fowke, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: Feb. 22, 2019

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

1

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Robert C. Frenzel, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: Feb. 22, 2019

/s/ ROBERT C. FRENZEL

Robert C. Frenzel

Executive Vice President, Chief Financial Officer and Director

2

EX-32.01

Exhibit 32.01

OFFICER CERTIFICATION

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Southwestern Public Service Company (SPS) on Form 10-K for the year ended Dec. 31, 2018, as filed with the SEC on the date hereof (Form 10-K), each of the undersigned officers of SPS certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

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

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

Date: Feb. 22, 2019

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

/s/ ROBERT C. FRENZEL

Robert C. Frenzel

Executive Vice President, Chief Financial Officer and Director

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

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

1

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 22, 2019	Jun. 29, 2018
Document and Entity Information [Abstract]
Entity Registrant Name	SOUTHWESTERN PUBLIC SERVICE CO
Entity Central Index Key	0000092521
Current Fiscal Year End Date	--12-31
Entity Well-Known Season Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Public Float			$ 0
Entity Common Stock, Shares Outstanding		100
Entity Small Business	false
Entity Shell Company	false
Entity Emerging Growth Company	false

XML

STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating activities
Net income	$ 213,300	$ 159,200	$ 152,200
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	210,000	193,900	163,000
Deferred income taxes	22,100	126,500	123,000
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(19,100)	(9,300)	(10,000)
Amortization of Regulatory Asset	1,700	1,700	0
Provision for bad debts	4,900	5,100	6,100
Net derivative losses	100	100	200
Changes in operating assets and liabilities:
Accounts receivable	19,500	10,400	8,900
Accrued unbilled revenues	(15,300)	10,400	15,600
Inventories	(16,000)	1,900	1,000
Prepayments and other	(500)	(4,300)	(22,700)
Accounts payable	(6,600)	11,800	13,800
Net regulatory assets and liabilities	(38,200)	(38,100)	55,700
Other current liabilities	11,600	3,400	5,200
Pension and other employee benefit obligations	(16,000)	(21,700)	(15,300)
Other	(5,800)	19,900	(8,100)
Net cash provided by operating activities	446,300	470,500	387,800
Investing activities
Utility capital/construction expenditures	(1,020,900)	(550,600)	(502,500)
Proceeds from insurance recoveries	0	0	3,900
Investments in utility money pool arrangement	(285,000)	(142,000)	(75,000)
Receipts from utility money pool arrangement	350,000	77,000	75,000
Other	0	(500)	1,300
Net cash used in investing activities	(955,900)	(616,100)	(499,900)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	42,000	(50,000)	35,000
Proceeds from issuance of long-term debt	295,000	442,300	296,000
Repayment of long-term debt, including reacquisition premiums	0	(271,600)	(200,000)
Borrowings under utility money pool arrangement	595,000	335,000	636,500
Repayments under utility money pool arrangement	(595,000)	(335,000)	(636,500)
Capital contributions from parent	336,800	143,700	66,200
Dividends paid to parent	(131,000)	(108,800)	(85,100)
Net cash provided by financing activities	542,800	155,600	112,100
Net change in cash and cash equivalents	33,200	10,000	0
Cash and cash equivalents at beginning of period	10,800	800	800
Cash and cash equivalents at end of period	44,000	10,800	800
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(71,200)	(76,000)	(78,200)
Cash paid for income taxes, net	10,600	(41,500)	(61,800)
Supplemental disclosure of non-cash investing transactions:
Inventory transfers to plant, property and equipment	0	13,700	22,600
Property, plant and equipment additions in accounts payable	71,500	85,100	49,500
Allowance for Funds Used During Construction, Investing Activities	$ 19,100	$ 9,300	$ 10,000

XML

STATEMENTS OF COMMON STOCKHOLDER'S EQUITY - USD ($) $ in Thousands	Total	Common stock	Additional Paid In Capital	Retained Earnings	AOCI Attributable to Parent
Beginning Balance at Dec. 31, 2015	$ 1,807,900	$ 0	$ 1,371,200	$ 438,000	$ (1,300)
Beginning Balance (in shares) at Dec. 31, 2015		100
Comprehensive income:
Net income	152,200			152,200
Other comprehensive income	0
Common dividends declared to parent	(103,500)			103,500
Contribution of capital by parent	75,000		75,000
Ending Balance at Dec. 31, 2016	1,931,600	$ 0	1,446,200	486,700	(1,300)
Ending Balance (in shares) at Dec. 31, 2016		100
Comprehensive income:
Net income	159,200			159,200
Other comprehensive income	100				100
Common dividends declared to parent	(104,600)			104,600
Contribution of capital by parent	144,000		144,000
Adoption of ASU No. 2018-02	0			0	(300)
Ending Balance at Dec. 31, 2017	$ 2,130,300	$ 0	1,590,200	541,600	(1,500)
Ending Balance (in shares) at Dec. 31, 2017	100	100
Comprehensive income:
Net income	$ 213,300			213,300
Other comprehensive income	100				100
Common dividends declared to parent	(149,200)			149,200
Contribution of capital by parent	342,100		342,100
Ending Balance at Dec. 31, 2018	$ 2,536,600	$ 0	$ 1,932,300	$ 605,700	$ (1,400)
Ending Balance (in shares) at Dec. 31, 2018	100	100

XML

STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues [Abstract]
Revenues	$ 1,933,200	$ 1,918,000	$ 1,851,000
Operating expenses
Electric fuel and purchased power	1,043,500	1,055,300	1,035,000
Operating and maintenance expenses	282,700	285,400	265,500
Demand side management program expenses	17,700	15,500	16,000
Depreciation and amortization	209,600	193,900	162,400
Taxes (other than income taxes)	68,000	67,000	60,800
Total operating expenses	1,621,500	1,617,100	1,539,700
Operating income	311,700	300,900	311,300
Other income (expense), net	(3,000)	(1,800)	(3,900)
Allowance for funds used during construction — equity	19,100	9,300	10,000
Interest charges and financing costs
Interest charges — includes other financing costs of $2.9, $2.5 and $3.1, respectively	84,500	86,200	88,700
Public Utilities, Allowance For Funds Used During Construction, Capitalized Cost Of Debt	(8,900)	(5,400)	(5,600)
Total interest charges and financing costs	75,600	80,800	83,100
Income before income taxes	252,200	227,600	234,300
Income taxes	38,900	68,400	82,100
Net income	$ 213,300	$ 159,200	$ 152,200

XML

STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Interest charges and financing costs
Other financing costs	$ 2,900	$ 2,500	$ 3,100

XML

BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 44,000	$ 10,800
Accounts receivable, net	90,700	79,600
Accounts receivable from affiliates	10,500	1,300
Investments in money pool arrangements	0	65,000
Accrued unbilled revenues	114,500	129,800
Inventory	33,900	40,400
Regulatory assets	26,000	31,500
Derivative instruments	17,800	15,900
Prepaid taxes	14,200	15,000
Prepayments and other	10,700	10,400
Total current assets	362,300	399,700
Property, plant and equipment, net	5,946,400	5,095,600
Other assets
Regulatory assets	366,200	362,900
Derivative instruments	15,800	19,000
Other	5,100	11,300
Total other assets	387,100	393,200
Total assets	6,695,800	5,888,500
Current liabilities
Short-term debt	42,000	0
Accounts payable	191,800	211,800
Accounts payable to affiliates	19,900	22,600
Regulatory liabilities	85,800	68,800
Taxes accrued	41,600	35,200
Accrued interest	25,800	23,300
Dividends payable	45,200	26,800
Derivative instruments	3,600	3,600
Other	28,300	29,600
Total current liabilities	484,000	421,700
Deferred credits and other liabilities
Deferred income taxes	619,100	574,900
Regulatory liabilities	780,900	784,600
Asset retirement obligations	32,400	28,500
Derivative instruments	16,400	20,000
Pension and employee benefit obligations	92,400	90,300
Other	7,900	8,300
Total deferred credits and other liabilities	1,549,100	1,506,600
Commitments and contingencies
Capitalization
Long-term debt	2,126,100	1,829,900
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2018 and 2017, respectively	0	0
Additional paid in capital	1,932,300	1,590,200
Retained earnings	605,700	541,600
Accumulated other comprehensive loss	(1,400)	(1,500)
Total common stockholder’s equity	2,536,600	2,130,300
Total liabilities and equity	$ 6,695,800	$ 5,888,500

XML

BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
Capitalization, Long-term Debt and Equity [Abstract]
Common stock, shares authorized (in shares)	200	200
Common stock, par value (in dollars per share)	$ 1.00	$ 1.00
Common stock, shares outstanding (in shares)	100	100

XML

STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	$ 100	$ 0	$ 100
Other comprehensive income	100	100	0
Comprehensive income:
Net income	213,300	159,200	152,200
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), Reclassification Adjustment from AOCI, after Tax	0	100	(100)
Derivative instruments:
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ 213,400	$ 159,300	$ 152,200

XML

STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative instruments:
Reclassification of losses to net income, tax	$ 0	$ (100)	$ (100)
Amortization of losses (gains) included in net periodic benefit cost, tax	$ 0	$ 0	$ (100)

XML

STATEMENTS OF CAPITALIZATION - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Common Stockholder's Equity
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2018 and 2017, respectively	$ 0.0	$ 0.0
Additional paid in capital	1,932.3	1,590.2
Retained earnings	605.7	541.6
Accumulated other comprehensive loss	(1.4)	(1.5)
Total common stockholder’s equity	$ 2,536.6	$ 2,130.3

XML

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

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.

SPS has evaluated the impact of events occurring after Dec. 31, 2018 up to the date of issuance of these financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.

Use of Estimates— SPS uses estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used on items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. Recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results.

Regulatory Accounting— SPS accounts for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

• Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and

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

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

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

See Note 4 for further information.

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

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

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

Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized.

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

Recognition of changes in uncertain tax positions are reflected as a component of income tax.

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

Xcel Energy Inc. and its subsidiaries, including SPS, files consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.

See Notes 4 and 7 for further information.

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

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

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

See Note 3 for further information.

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

See Note 10 for further information.

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

Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.

See Note 9 for further information.

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

Estimated remediation costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for SPS’ expected share of the cost.

Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 10 for further information.

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

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

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

See Note 6 for further information.

Cash and Cash Equivalents— SPS considers investments in instruments with a remaining maturity of three months or less at the time of purchase, to be cash equivalents.

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

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

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

See Notes 8 and 9 for further information.

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

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

See Note 8 for further information.

Other Utility Items

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

Alternative Revenue — Certain rate rider mechanisms (including DSM programs) qualify as alternative revenue programs under GAAP. 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, such as collection within 24 months, revenue is recognized equal to the revenue requirement, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between the total amount collected and the revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers in the period earned.

See Note 6 for further information.

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

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

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

RECs — Cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. SPS reduces recoverable fuel costs for the cost of RECs and records that cost as a regulatory asset when the amount is recoverable in future rates.

Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.

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

XML

Accounting Pronouncements

12 Months Ended

Dec. 31, 2018

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Accounting Pronouncements

Accounting Pronouncements

Recently Issued

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

Recently Adopted

Revenue Recognition — In 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 implemented the guidance on a modified retrospective basis on Jan. 1, 2018. Results for reporting periods beginning after Dec. 31, 2017 are presented in accordance with Topic 606, while prior period results have not been adjusted and continue to be reported in accordance with prior accounting guidance. The implementation did not have a material impact on SPS’ financial statements, other than increased disclosures regarding revenues related to contracts with customers.

Classification and Measurement of Financial Instruments — In 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which eliminated the available-for-sale classification for marketable equity securities and also replaced the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. SPS implemented the guidance on Jan. 1, 2018 and the adoption impacts were not material.

Presentation of Net Periodic Benefit Cost —In 2017, the FASB issued Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715 (ASU No. 2017-07), which establishes that only the service cost portion of pension cost may be presented as a component of operating income. In addition, only the service cost portion of pension cost is eligible for capitalization. As a result of regulatory accounting treatment, a similar amount of pension cost, including non-service components, will be recognized consistent with historical ratemaking and the impacts of adoption are limited to changes in classification of non-service costs in the statement of income.

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

XML

Property Plant and Equipment Property Plant and Equipment

12 Months Ended

Dec. 31, 2018

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment Disclosure

Property, Plant and Equipment

Major classes of property, plant and equipment:

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

XML

Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2018

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

Regulatory Assets and Liabilities

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

Components of regulatory assets:

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

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

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

Components of regulatory liabilities:

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

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

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

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

XML

Borrowings and Other Financing Instruments

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Borrowings and Other Financing Instruments

Borrowings and Other Financing Instruments

Short-Term Borrowings

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

Money pool borrowings for SPS were as follows:

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

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

Commercial paper outstanding for SPS was as follows:

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

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

Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, SPS must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility.

The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

Features of SPS’ credit facility:

Debt-to-Total Capitalization Ratio(a)		Amount Facility May Be Increased (millions)	Additional Periods For Which a One-Year Extension May Be Requested (b)
2018	2017
46%	46%	$50	2

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

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

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

If SPS does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2018, SPS was in compliance with all financial covenants.

SPS had the following committed credit facilities available as of Dec. 31, 2018.

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

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

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

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

Long-Term Borrowings and Other Financing Instruments

Generally, all property of SPS is subject to the lien of its first mortgage indenture. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance.

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

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

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

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

2018 financings:

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

2017 financings:

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

Capital Stock — SPS has the following preferred stock:

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

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

SPS’ state regulatory commission imposes the most restrictive dividend limitations.

Requirements and actuals as of Dec. 31, 2018:

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

^(a)  SPS excludes short-term debt.

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

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

XML

Revenues

12 Months Ended

Dec. 31, 2018

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer [Text Block]

Revenues

Revenue is classified by the type of goods/services rendered and market/customer type. SPS’ operating revenues (subsequent to adoption of the revised revenue guidance) consists of the following:

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

XML

Income Taxes

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Federal Tax Reform— In 2017, the TCJA was signed into law. The key provisions impacting Xcel Energy (which includes SPS), generally beginning in 2018, include:

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

• Normalization of resulting plant-related excess deferred taxes;

• Elimination of the corporate alternative minimum tax;

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

• Limitations on certain executive compensation deductions;

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

• Repeal of the section 199 manufacturing deduction; and,

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

Xcel Energy estimated the effects of the TCJA, which have been reflected in the consolidated financial statements.

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

Estimated impacts of the new tax law for SPS in December 2017 included:

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

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

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

Xcel Energy accounted for the state tax impacts of federal tax reform based on enacted state tax laws. Any future state tax law changes related to the TCJA will be accounted for in the periods state laws are enacted.

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

Tax Year(s)	Expiration
2009 - 2014	October 2019
2015	September 2019
2016	September 2020
2017	September 2021

In 2012, the IRS commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. In 2017, Xcel Energy and the Office of Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. SPS did not accrue any income tax benefit related to this adjustment. In the second quarter of 2018, the Joint Committee on Taxation completed its review and took no exception to the agreement. As a result, the remaining unrecognized tax benefit was released and recorded as a payable to the IRS.

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy filed a protest with the IRS. As of Dec. 31, 2018, the case has been forwarded to the Office of Appeals and Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.

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

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2018, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2010. There are currently no state income tax audits in progress.

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

Unrecognized tax benefits - permanent vs temporary:

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

Changes in unrecognized tax benefits:

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

Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:

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

Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $0.8 million and $2.7 million at Dec. 31, 2018 and Dec. 31, 2017, respectively.

As the IRS Appeals and federal audit progress and state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $3.6 million in the next 12 months.

Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.

Interest payable related to unrecognized tax benefits:

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

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

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

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

Federal carryforward periods expire between 2021 and 2038 and state carryforward periods expire between 2021 and 2036.

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.

Effective income tax rate for years ended Dec. 31:

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

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

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

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

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

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

Components of deferred income tax expense as of Dec. 31:

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

Components of the net deferred tax liability as of Dec. 31:

(Millions of Dollars)	2018		2017
Deferred tax liabilities:
Differences between book and tax bases of property	$	680.6	$	654.4
Regulatory assets	49.2		46.8
Pension expense	32.3		33.8
Other	2.9		4.6
Total deferred tax liabilities	$	765.0	$	739.6
Deferred tax assets:
Regulatory liabilities	116.8		114.6
NOL carryforward	0.2		26.2
Deferred fuel costs	12.7		10.4
Other employee benefits	5.6		5.8
Tax credit carryforward	5.7		5.2
Other	4.9		2.5
Total deferred tax assets	$	145.9	$	164.7
Net deferred tax liability	$	619.1	$	574.9

XML

Fair Value of Financial Assets and Liabilities

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

Fair Value of Financial Assets and Liabilities

8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance.

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

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

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

Specific valuation methods include:

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

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

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

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

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

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, 2018, accumulated other comprehensive losses related to interest rate derivatives included $0.1 million net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

Wholesale and Commodity Trading Risk — SPS conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments, including derivatives. SPS 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, 2018 and 2017:

(Amounts in Millions)(a)	Dec. 31, 2018	Dec. 31, 2017
MWh of electricity	5.5	4.3

^(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, 2018, two of the eight most significant counterparties for these activities, comprising $11.6 million or 28% of this credit exposure, had investment grade ratings from Standard & Poor’s, Moody’s or Fitch Ratings. Five of the eight most significant counterparties, comprising $8.7 million or 21% of this credit exposure, were not rated by external rating agencies, but based on SPS’ internal analysis, had credit quality consistent with investment grade. Another of these significant counterparties, comprising $0.6 million or less than 1% of this credit exposure, had credit quality less than investment grade, based on external analysis. Six of these significant counterparties are municipal or cooperative electric entities, 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)	2018			2017			2016
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(0.8	)	$	(0.7	)	$	(0.8	)
After-tax net realized losses on derivative transactions reclassified into earnings	0.1			—			0.1
Adoption of ASU. 2018-02 (a)	—			(0.1		)	—
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(0.7	)	$	(0.8	)	$	(0.7	)

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

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

Changes in the fair value of FTRs resulting in pre-tax net gains of $7.0 million, $0.5 million and $3.0 million recognized for the years ended Dec. 31, 2018, 2017 and 2016, respectively, were reclassified as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on expected recovery of FTR settlements through fuel and purchased energy cost recovery mechanisms.

FTR settlement gains of $4.4 million, $0.8 million and $2.1 million were recognized for the years ended Dec. 31, 2018, 2017 and 2016, respectively, and 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 no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2018, 2017 and 2016.

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2018 and 2017:

	Dec. 31, 2018													Dec. 31, 2017
	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	$	—	$	—	$	14.9	$	14.9	$	(0.2	)	$	14.7	$	—	$	—	$	14.7	$	14.7	$	(2.0	)	$	12.7
Total current derivative assets	$	—	$	—	$	14.9	$	14.9	$	(0.2	)	14.7		$	—	$	—	$	14.7	$	14.7	$	(2.0	)	12.7
PPAs (b)												3.1													3.2
Current derivative instruments												$	17.8												$	15.9
Noncurrent derivative assets
PPAs (b)												15.8													19.0
Noncurrent derivative instruments												$	15.8												$	19.0
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	0.2	$	0.2	$	(0.2	)	$	—	$	—	$	—	$	2.0	$	2.0	$	(2.0	)	$	—
Total current derivative liabilities	$	—	$	—	$	0.2	$	0.2	$	(0.2	)	—		$	—	$	—	$	2.0	$	2.0	$	(2.0	)	—
PPAs (b)												3.6													3.6
Current derivative instruments												$	3.6												$	3.6
Noncurrent derivative liabilities
PPAs (b)												16.4													19.9
Noncurrent derivative instruments												$	16.4												$	19.9

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

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

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

	Year Ended Dec. 31
(Millions of Dollars)	2018			2017			2016
Balance at Jan. 1	$	12.7		$	2.0		$	5.1
Purchases	32.3			41.2			7.6
Settlements	(41.6		)	(55.8		)	(41.9		)
Net transactions recorded during the period:
Net gains recognized as regulatory assets	11.3			25.3			31.2
Balance at Dec. 31	$	14.7		$	12.7		$	2.0

SPS recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for 2016 - 2018.

Fair Value of Long-Term Debt

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

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

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, 2018 and 2017, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.

XML

Benefit Plans and Other Postretirement Benefits

12 Months Ended

Dec. 31, 2018

Retirement Benefits [Abstract]

Benefit Plans and Other Postretirement Benefits

Benefit Plans and Other Postretirement Benefits

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

In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions funded by Xcel Energy’s consolidated operating cash flows. Obligations of the SERP and nonqualified plan as of Dec. 31, 2018 and 2017 were $33 million and $37 million, respectively, of which $2 million was attributable to SPS in 2018 and 2017. In 2018 and 2017, Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $4 million and $5 million, respectively, of which immaterial amounts were attributable to SPS.

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

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

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

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

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

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

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

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

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

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

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

State agencies also have issued guidelines to the funding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for Texas and New Mexico amounts collected in rates. These assets are invested in a manner consistent with the investment strategy for the pension plan.

Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios.

Pension Plan Assets

The following presents, for each of the fair value hierarchy levels, SPS’ pension plan assets measured at fair value:

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

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

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

^(a)  See Note 8 for further information on fair value measurement inputs and methods.

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

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

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

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

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

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

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

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

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

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

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

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 2016 - 2019 to meet minimum funding requirements.

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

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

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

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

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

For future years, Xcel Energy and SPS 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 $11 million during 2019;

• $11 million during 2018;

• $20 million during 2017; and,

• $18 million during 2016.

• Amounts attributable to SPS were immaterial.

Target asset allocations:

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

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

Projected Benefit Payments

SPS’ projected benefit payments:

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

Defined Contribution Plans

Xcel Energy, which includes SPS, maintains 401(k) and other defined contribution plans that cover most employees. The expense to these plans for SPS was approximately $3 million in 2018, 2017 and 2016.

XML

Commitments and Contingencies

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Legal

SPS is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves complex judgments about future events. Management maintains accruals for losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

For current proceedings not specifically reported herein, management does not anticipate 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

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.  The SPP OATT has allowed SPP to charge for these upgrades since 2008, but SPP had not been charging its customers for these upgrades.  In 2016, the FERC granted SPP’s request to recover the charges not billed since 2008.  SPP subsequently billed SPS approximately $13 million for these charges.

In July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP the right to recover these charges was remanded to the FERC. SPS’ recovery of these charges (from 2008 through 2016) is being reviewed by the FERC, which is expected to rule in the first quarter of 2019.

In October 2017, SPS filed a complaint against SPP regarding the amounts billed asserting that SPP has assessed upgrade charges to SPS in violation of the SPP OATT. The FERC has granted a rehearing of further consideration in May 2018. The timing of the FERC action on the SPS rehearing is uncertain. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the differential in future rate proceedings.

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

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

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

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

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

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 its 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 investigating or remediating one MGP, landfill or other disposal site across its service territories, and these activities will continue through at least 2019. SPS accrued $0.1 million as of Dec. 31, 2018 and 2017, respectively, for this site. There may be insurance recovery and/or recovery from other potentially responsible parties, offsetting some 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”. The Rule has been subject to significant litigation and is currently stayed in a portion of the country. SPS cannot estimate potential impacts until the legal and administrative processes are finalized, but expects 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 will be immaterial.

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

Environmental Requirements — Air

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

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

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

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

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

AROs — AROs have been recorded for SPS’ assets.

SPS’ AROs were as follows:

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

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

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

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

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

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

Indeterminate AROs — Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of SPS’ facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2018. 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. 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 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, 2018 and 2017 were $188 million and $197 million respectively.

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

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

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

Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases.

Future commitments under operating leases are:

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

^(a)  Amounts do not include PPAs accounted for as executory contracts.

^(b)  PPA operating leases contractually expire through 2033.

Non-Lease PPAs — SPS has entered into PPAs with other utilities and energy suppliers with expiration dates through 2033 for purchased power to meet system load and energy requirements and meet operating reserve obligations.

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 our financial results are mitigated through purchased energy cost recovery mechanisms.

Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts, were payments for capacity of $57.6 million, $58.4 million and $56.8 million in 2018, 2017 and 2016, respectively.

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

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

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

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

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

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

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

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

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

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

XML

Other Comprehensive Income

12 Months Ended

Dec. 31, 2018

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the year ended Dec. 31:

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

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

^(a)  Included in interest charges.

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

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

XML

Related Party Transactions

12 Months Ended

Dec. 31, 2018

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

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

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

See Note 5 for further information.

Significant affiliate transactions among the companies and related parties for the years ended Dec. 31:

(Millions of Dollars)	2018		2017		2016
Operating expenses:
Purchased power	$	—	$	1.4	$	8.8
Other operating expenses — paid to Xcel Energy Services Inc.	195.1		196.6		188.2
Interest expense	0.6		—		0.2

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

	2018				2017
(Millions of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	4.7	$	—	$	1.0	$	—
PSCo	—		0.7		—		0.3
Other subsidiaries of Xcel Energy Inc.	5.8		19.2		0.3		22.3
	$	10.5	$	19.9	$	1.3	$	22.6

XML

Summarized Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Data (Unaudited)

Summarized Quarterly Financial Data (Unaudited)

	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	57.1		87.6		111.0		56.0
Net income	33.1		58.5		81.5		40.2

	Quarter Ended
(Millions of Dollars)	March 31, 2017		June 30, 2017		Sept. 30, 2017		Dec. 31, 2017
Operating revenues	$	460.1	$	479.8	$	551.6	$	426.5
Operating income (a)	59.2		75.2		123.1		43.4
Net income	25.1		35.3		67.8		31.0

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

XML

Schedule II, Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2018

SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]

Schedule II, Valuation and Qualifying Accounts

SOUTHWESTERN PUBLIC SERVICE CO.

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DEC. 31, 2018, 2017 AND 2016

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

^(a)  Recovery of amounts previously written off.

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

XML

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

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.

Subsequent Events

SPS has evaluated the impact of events occurring after Dec. 31, 2018 up to the date of issuance of these financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.

Use of Estimates

Use of Estimates— SPS uses estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used on items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. Recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results.

Regulatory Accounting

Regulatory Accounting— SPS accounts for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

• Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and

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

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

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

See Note 4 for further information.

Income Taxes

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

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

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

Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized.

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

Recognition of changes in uncertain tax positions are reflected as a component of income tax.

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

Xcel Energy Inc. and its subsidiaries, including SPS, files consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.

See Notes 4 and 7 for further information.

Property, Plant and Equipment and Depreciation

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

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

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

See Note 3 for further information.

Asset Retirement Obligations

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

See Note 10 for further information.

Benefit Plans and Other Postretirement Benefits

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

Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.

See Note 9 for further information.

Environmental Costs

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

Estimated remediation costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for SPS’ expected share of the cost.

Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 10 for further information.

Revenue From Contracts With Customers

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

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

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

See Note 6 for further information.

Cash and Cash Equivalents

Cash and Cash Equivalents— SPS considers investments in instruments with a remaining maturity of three months or less at the time of purchase, to be cash equivalents.

Accounts Receivable and Allowance for Bad Debts

Accounts Receivable 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, 2018 and 2017, the allowance for bad debts was $5.6 million and $6.3 million, respectively.

Inventory

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

Fair Value Measurements

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

See Notes 8 and 9 for further information.

Derivative Instruments

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

Normal Purchases and Normal Sales — SPS 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.

AFUDC

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

Alternative Revenue Programs

Alternative Revenue — Certain rate rider mechanisms (including DSM programs) qualify as alternative revenue programs under GAAP. 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, such as collection within 24 months, revenue is recognized equal to the revenue requirement, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between the total amount collected and the revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers in the period earned.

See Note 6 for further information.

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

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

Emission Allowances

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

Renewable Energy Credits

RECs — Cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. SPS reduces recoverable fuel costs for the cost of RECs and records that cost as a regulatory asset when the amount is recoverable in future rates.

Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.

Segment Reporting, Policy [Policy Text Block]

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.

XML

Property Plant and Equipment Property Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2018

Property, Plant and Equipment [Abstract]

Public Utility Property, Plant, and Equipment

Major classes of property, plant and equipment:

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

XML

Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2018

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets

Components of regulatory assets:

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

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

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

Regulatory Liabilities

Components of regulatory liabilities:

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

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

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

XML

Borrowings and Other Financing Instruments (Tables)

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Money Pool [Table Text Block]

Money pool borrowings for SPS were as follows:

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

Short-Term Borrowings

Commercial paper outstanding for SPS was as follows:

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

Schedule Of Debt To Total Capitalization Ratio [Table Text Block]

Features of SPS’ credit facility:

Debt-to-Total Capitalization Ratio(a)		Amount Facility May Be Increased (millions)	Additional Periods For Which a One-Year Extension May Be Requested (b)
2018	2017
46%	46%	$50	2

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

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

Credit Facilities

SPS had the following committed credit facilities available as of Dec. 31, 2018.

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

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

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

Schedule of Capitalization [Table Text Block]

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

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

Schedule of Long-Term Debt Issuances [Table Text Block]

2018 financings:

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

2017 financings:

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

Schedule of Long-term Debt Instruments [Table Text Block]

SPS has the following preferred stock:

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

Dividend Payment Restrictions [Text Block]

Requirements and actuals as of Dec. 31, 2018:

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

^(a)  SPS excludes short-term debt.

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

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

XML

Revenues (Tables)

12 Months Ended

Dec. 31, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue [Table Text Block]

SPS’ operating revenues (subsequent to adoption of the revised revenue guidance) consists of the following:

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

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Interest Payable related to Unrecognized Tax Benefits

Interest payable related to unrecognized tax benefits:

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

Summary of Statute of Limitations Applicable to Open Tax Years

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

Tax Year(s)	Expiration
2009 - 2014	October 2019
2015	September 2019
2016	September 2020
2017	September 2021

Reconciliation of Unrecognized Tax Benefits

Unrecognized tax benefits - permanent vs temporary:

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

Changes in unrecognized tax benefits:

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

Tax Benefits Associated with NOL and Tax Credit Carryforwards

Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:

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

NOL and Tax Credit Carryforwards

NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:

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

Schedule of Effective Income Tax Rate Reconciliation

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.

Effective income tax rate for years ended Dec. 31:

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

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

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

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

Schedule of Components of Income Tax Expense (Benefit)

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

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

Components of deferred income tax expense as of Dec. 31:

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

Schedule of Deferred Tax Assets and Liabilities

Components of the net deferred tax liability as of Dec. 31:

(Millions of Dollars)	2018		2017
Deferred tax liabilities:
Differences between book and tax bases of property	$	680.6	$	654.4
Regulatory assets	49.2		46.8
Pension expense	32.3		33.8
Other	2.9		4.6
Total deferred tax liabilities	$	765.0	$	739.6
Deferred tax assets:
Regulatory liabilities	116.8		114.6
NOL carryforward	0.2		26.2
Deferred fuel costs	12.7		10.4
Other employee benefits	5.6		5.8
Tax credit carryforward	5.7		5.2
Other	4.9		2.5
Total deferred tax assets	$	145.9	$	164.7
Net deferred tax liability	$	619.1	$	574.9

XML

Fair Value of Financial Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

Gross Notional Amounts of Commodity FTRs

Gross notional amounts of commodity FTRs at Dec. 31, 2018 and 2017:

(Amounts in Millions)(a)	Dec. 31, 2018	Dec. 31, 2017
MWh of electricity	5.5	4.3

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

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

Financial impact of qualifying 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)	2018			2017			2016
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(0.8	)	$	(0.7	)	$	(0.8	)
After-tax net realized losses on derivative transactions reclassified into earnings	0.1			—			0.1
Adoption of ASU. 2018-02 (a)	—			(0.1		)	—
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(0.7	)	$	(0.8	)	$	(0.7	)

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

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

The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2018 and 2017:

	Dec. 31, 2018													Dec. 31, 2017
	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	$	—	$	—	$	14.9	$	14.9	$	(0.2	)	$	14.7	$	—	$	—	$	14.7	$	14.7	$	(2.0	)	$	12.7
Total current derivative assets	$	—	$	—	$	14.9	$	14.9	$	(0.2	)	14.7		$	—	$	—	$	14.7	$	14.7	$	(2.0	)	12.7
PPAs (b)												3.1													3.2
Current derivative instruments												$	17.8												$	15.9
Noncurrent derivative assets
PPAs (b)												15.8													19.0
Noncurrent derivative instruments												$	15.8												$	19.0
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	0.2	$	0.2	$	(0.2	)	$	—	$	—	$	—	$	2.0	$	2.0	$	(2.0	)	$	—
Total current derivative liabilities	$	—	$	—	$	0.2	$	0.2	$	(0.2	)	—		$	—	$	—	$	2.0	$	2.0	$	(2.0	)	—
PPAs (b)												3.6													3.6
Current derivative instruments												$	3.6												$	3.6
Noncurrent derivative liabilities
PPAs (b)												16.4													19.9
Noncurrent derivative instruments												$	16.4												$	19.9

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

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

Changes in Level 3 Commodity Derivatives

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

	Year Ended Dec. 31
(Millions of Dollars)	2018			2017			2016
Balance at Jan. 1	$	12.7		$	2.0		$	5.1
Purchases	32.3			41.2			7.6
Settlements	(41.6		)	(55.8		)	(41.9		)
Net transactions recorded during the period:
Net gains recognized as regulatory assets	11.3			25.3			31.2
Balance at Dec. 31	$	14.7		$	12.7		$	2.0

Carrying Amount and Fair Value of Long-term Debt

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

XML

Benefit Plans and Other Postretirement Benefits (Tables)

12 Months Ended

Dec. 31, 2018

Benefit Plans and Other Postretirement Benefits [Abstract]

Target Asset Allocations and Plan Assets Measured at Fair Value

The following presents, for each of the fair value hierarchy levels, SPS’ pension plan assets measured at fair value:

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

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

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

^(a)  See Note 8 for further information on fair value measurement inputs and methods.

Target asset allocations:

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

Funded Status of Plans

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

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

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

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

Components of Net Periodic Benefit Costs

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

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

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

Projected Benefit Payments for the Pension and Postretirement Benefit Plans

Projected Benefit Payments

SPS’ projected benefit payments:

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

Other Postretirement Benefits Plan [Member]

Benefit Plans and Other Postretirement Benefits [Abstract]

Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost

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

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

XML

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Total expense for energy and capacity payments table text block [Table Text Block]

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

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

Estimated Minimum Purchases Under Fuel Contracts

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

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

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

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

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

Future Commitments Under Operating Leases

Future commitments under operating leases are:

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

^(a)  Amounts do not include PPAs accounted for as executory contracts.

^(b)  PPA operating leases contractually expire through 2033.

Asset Retirement Obligations

SPS’ AROs were as follows:

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

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

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

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

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

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

XML

Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2018

Stockholders' Equity Note [Abstract]

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

Changes in accumulated other comprehensive loss, net of tax, for the year ended Dec. 31:

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

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

XML

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2018

Related Party Transactions [Abstract]

Related Party Transactions

Significant affiliate transactions among the companies and related parties for the years ended Dec. 31:

(Millions of Dollars)	2018		2017		2016
Operating expenses:
Purchased power	$	—	$	1.4	$	8.8
Other operating expenses — paid to Xcel Energy Services Inc.	195.1		196.6		188.2
Interest expense	0.6		—		0.2

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

	2018				2017
(Millions of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	4.7	$	—	$	1.0	$	—
PSCo	—		0.7		—		0.3
Other subsidiaries of Xcel Energy Inc.	5.8		19.2		0.3		22.3
	$	10.5	$	19.9	$	1.3	$	22.6

XML

Summarized Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information Disclosure [Abstract]

Summarized Quarterly Financial Data (Unaudited)

	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	57.1		87.6		111.0		56.0
Net income	33.1		58.5		81.5		40.2

	Quarter Ended
(Millions of Dollars)	March 31, 2017		June 30, 2017		Sept. 30, 2017		Dec. 31, 2017
Operating revenues	$	460.1	$	479.8	$	551.6	$	426.5
Operating income (a)	59.2		75.2		123.1		43.4
Net income	25.1		35.3		67.8		31.0

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

XML

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Depreciation expense expressed as a percentage of average depreciable property	2.90%	2.80%	2.70%
Cash and Cash Equivalents [Abstract]
Maximum number of months of remaining maturity at time of purchase to consider investments in certain instruments as cash equivalents	three months
Accounts, Notes, Loans and Financing Receivable, Classified [Abstract]
Allowance for Doubtful Accounts Receivable, Current	$ 5.6	$ 6.3
Alternative Revenue Programs [Abstract]
Maximum number of months following end of annual period in which revenues are earned to be included in incentive programs	24 months
Public Utilities, Inventory [Line Items]
Inventory	$ 33.9	40.4
Supplies
Public Utilities, Inventory [Line Items]
Inventory	25.7	26.2
Fuel
Public Utilities, Inventory [Line Items]
Inventory	$ 8.2	$ 14.2

XML

Accounting Pronouncements Adoption of New Accounting Pronouncements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Other Expense | Accounting Standards Update 2017-07
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Net benefit cost recognized for financial reporting	$ 4.1	$ 4.0

XML

Property Plant and Equipment Property Plant and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 8,075.0	$ 7,117.2
Property, plant and equipment, net	5,946.4	5,095.6
Electric plant
Property, Plant and Equipment [Line Items]
Property, plant and equipment	7,227.7	6,765.3
CWIP
Property, Plant and Equipment [Line Items]
Property, plant and equipment	847.3	351.9
Nuclear Fuel [Member]
Property, Plant and Equipment [Line Items]
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	$ 2,128.6	$ 2,021.6

XML

Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 26,000	$ 31,500
Regulatory Asset, Noncurrent		366,200	362,900
Past expenditures not currently earning a return		48,000	64,000
Pension and Retiree Medical Obligations
Regulatory Assets [Line Items]
Regulatory Asset, Current		12,600	12,700
Regulatory Asset, Noncurrent		$ 222,100	223,000
Regulatory asset, remaining amortization period		Various
Excess deferred taxes - TCJA
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 0	0
Regulatory Asset, Noncurrent		$ 55,900	44,700
Regulatory asset, remaining amortization period		Various
Recoverable Deferred Taxes on AFUDC Recorded in Plant
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 0	0
Regulatory Asset, Noncurrent		$ 27,900	23,900
Regulatory asset, remaining amortization period		Plant lives
Net AROs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[1]	$ 0	0
Regulatory Asset, Noncurrent	[1]	$ 25,700	24,200
Regulatory asset, remaining amortization period		Plant lives
Losses on Reacquired Debt
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 800	800
Regulatory Asset, Noncurrent		$ 21,900	22,700
Regulatory asset, remaining amortization period		Term of related debt
Conservation Programs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[2]	$ 700	2,700
Regulatory Asset, Noncurrent	[2]	$ 600	700
Regulatory Asset Amortization Period, minimum		1 year
Regulatory Asset Amortization Period, maximum		2 years
Other Regulatory Assets
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 11,900	15,300
Regulatory Asset, Noncurrent		$ 12,100	$ 23,700
Regulatory asset, remaining amortization period		Various

[1] Includes amounts recorded for future recovery of AROs.

[2] Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

XML

Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 85.8	$ 68.8
Regulatory Liability, Noncurrent		780.9	784.6
Deferred Income Tax Adjustments and TCJA Refunds
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[1]	2.2	0.0
Regulatory Liability, Noncurrent	[1]	$ 569.8	568.6
Regulatory liability, remaining amortization period		Various
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 0.0	0.0
Regulatory Liability, Noncurrent		$ 187.7	196.9
Regulatory liability, remaining amortization period		Plant lives
Revenue Subject to Refund
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 11.3	6.8
Regulatory Liability, Noncurrent		$ 8.1	6.5
Regulatory liability, remaining amortization period, minimum		1 year
Regulatory liability, remaining amortization period, maximum		2 years
Gain From Asset Sales
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 0.0	0.0
Regulatory Liability, Noncurrent		$ 2.4	2.5
Regulatory liability, remaining amortization period		Various
Deferred Electric Energy Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 56.5	48.5
Regulatory Liability, Noncurrent		$ 0.0	0.0
Regulatory liability, remaining amortization period, maximum		1 year
Contract Valuation Adjustments
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[2]	$ 14.7	12.7
Regulatory Liability, Noncurrent	[2]	$ 0.0	0.0
Regulatory liability, remaining amortization period, maximum		1 year
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 1.1	0.8
Regulatory Liability, Noncurrent		$ 12.9	$ 10.1
Regulatory liability, remaining amortization period		Various

[1] Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.

[2] Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

XML

Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Short-term Debt [Line Items]
Amount outstanding at period end	$ 42.0	$ 42.0	$ 0.0
Money Pool
Short-term Debt [Line Items]
Borrowing limit	100.0	100.0	100.0	$ 100.0
Amount outstanding at period end	0.0	0.0	0.0	0.0
Average amount outstanding	14.0	29.0	13.0	28.0
Maximum amount outstanding	$ 74.0	$ 100.0	$ 100.0	$ 100.0
Weighted average interest rate, computed on a daily basis (percentage)	2.13%	1.96%	1.12%	0.67%
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	$ 400.0	$ 400.0	$ 400.0	$ 400.0
Amount outstanding at period end	42.0	42.0	0.0	50.0
Average amount outstanding	20.0	30.0	69.0	43.0
Maximum amount outstanding	$ 100.0	$ 144.0	$ 176.0	$ 140.0
Weighted average interest rate, computed on a daily basis (percentage)	2.45%	2.27%	1.13%	0.67%
Weighted average interest rate at period end (percentage)	2.80%	2.80%		0.95%

XML

Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 42.0	$ 0.0
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 2.0	$ 3.0
Letter of Credit | Letter of Credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Period	1 year

XML

Borrowings and Other Financing Instruments, Credit Facility (Details) - Credit Facility	12 Months Ended
	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio	46.00%	46.00%
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased	$ 50,000,000
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	2
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	1
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed	65.00%
Line Of Credit Facility Minimum Threshhold Percentage Of Subsidiary Assets To Consolidated Assets Required To Initiate Cross Default Provisions	15.00%
Line of Credit Facility, Minimum Amount of Indebtedness in Default to Initiate Cross Default Provisions	$ 75,000,000
Credit facility	400,000,000
Drawn	44,000,000
Available	$ 356,000,000
Debt Instrument, Maturity Date	Jun. 30, 2021
Direct advances on the credit outstanding	$ 0	$ 0

XML

Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium), Net	$ (4.0)	$ (2.0)
Unamortized Debt Issuance Expense	(20.0)	(18.0)
Long-term Debt, Current Maturities	0.0	0.0
Long-term Debt, Excluding Current Maturities	2,126.1	1,829.9
Deferred Finance Costs, Noncurrent, Net	20.0	18.0
First Mortgage Bonds, Series due:
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,800.0	$ 1,500.0
Debt Instrument, Maturity Date Range, End	Jan. 01, 2048
Debt Instrument, Maturity Date Range, Start	Jun. 15, 2024
First Mortgage Bonds, Series due: | Series Due June 15, 2048 [Member]
Debt Instrument [Line Items]
Interest Rate, Stated Percentage (in hundredths)	4.40%
Face Amount	$ 300.0
Debt Instrument, Maturity Date	Nov. 15, 2048
First Mortgage Bonds, Series due: | Series Due August 15, 2047
Debt Instrument [Line Items]
Interest Rate, Stated Percentage (in hundredths)		3.70%
Face Amount		$ 450.0
Debt Instrument, Maturity Date		Aug. 15, 2047
Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 350.0	$ 350.0
Debt Instrument, Maturity Date Range, End	Oct. 01, 2036
Debt Instrument, Maturity Date Range, Start	Oct. 01, 2033
Combined Total
Debt Instrument [Line Items]
Long-term Debt, Excluding Current Maturities	$ 2,126.0	$ 1,830.0
Maximum | First Mortgage Bonds, Series due:
Debt Instrument [Line Items]
Interest Rate, Stated Percentage (in hundredths)	4.50%	4.50%
Maximum | Unsecured Debt [Member]
Debt Instrument [Line Items]
Interest Rate, Stated Percentage (in hundredths)	6.00%	8.75%
Minimum | First Mortgage Bonds, Series due:
Debt Instrument [Line Items]
Interest Rate, Stated Percentage (in hundredths)	3.30%	3.30%
Minimum | Unsecured Debt [Member]
Debt Instrument [Line Items]
Interest Rate, Stated Percentage (in hundredths)	6.00%	6.00%
Credit Facility
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Jun. 30, 2021

XML

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Preferred Stock (Details)	Dec. 31, 2018 $ / shares shares
Preferred Stock [Abstract]
Preferred Stock, Shares Authorized	10,000,000
Preferred Stock, Par or Stated Value Per Share | $ / shares	$ 1.00
Preferred Stock, Shares Outstanding	0

XML

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Dividend and Other Restrictions (Details) $ in Millions	Dec. 31, 2018 USD ($)
Dividend and Other Restrictions [Abstract]
Equity to total capitalization ratio (excluding short-term debt), low end of range	45.00%
Equity to total capitalization ratio (excluding short-term debt), high end of range	55.00%
Equity to total capitalization ratio (excluding short-term debt)	54.40%
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 605.7
Capitalization, Short term debt, long term debt and equity	$ 4,700.0

XML

Revenues (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disaggregation of Revenue [Line Items]
Revenues	$ 464.6	$ 540.1	$ 481.3	$ 447.2	$ 426.5	$ 551.6	$ 479.8	$ 460.1	$ 1,933.2	$ 1,918.0	$ 1,851.0
Regulated Electric [Member] | Retail
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									1,236.7
Regulated Electric [Member] | Retail | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									363.7
Regulated Electric [Member] | Retail | Commercial and industrial (C&I)
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									828.3
Regulated Electric [Member] | Retail | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									44.7
Regulated Electric [Member] | Wholesale
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									426.0
Regulated Electric [Member] | Transmission
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									231.1
Regulated Electric [Member] | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									12.8
Regulated Electric [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax									1,906.6
Regulated Electric [Member] | Alternative and Other [Member]
Disaggregation of Revenue [Line Items]
Revenues									26.6
Operating Segments [Member] | Regulated Electric [Member]
Disaggregation of Revenue [Line Items]
Revenues									$ 1,933.2

XML

Income Taxes (Details) - USD ($)		1 Months Ended	3 Months Ended			12 Months Ended
		Dec. 31, 2017	Dec. 31, 2018	Sep. 30, 2017	Sep. 30, 2015	Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2012	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Federal Tax Reform [Abstract]
Tax Cuts and Jobs Act of 2017, Corporate Federal Tax Rate		21.00%				21.00%
Tax Cuts and Jobs Act of 2017, Net Operating Loss Deduction Limitation, Percent of Taxable income						80.00%
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Liability, Provisional Income Tax (Expense) Benefit, Gross							$ 559,000,000
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Provisional Income Tax Expense (Benefit)							8,000,000
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Net Income Reduction							2,000,000
Tax Audits [Abstract]
Unrecognized Tax Benefits, Interest on Income Taxes Accrued												$ (700,000)	$ (500,000)	$ (900,000)	$ 0
Interest Income (Expense) related to unrecognized tax benefits						$ (200,000)	(1,400,000)		$ 900,000
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions												3,000,000	2,300,000
Unrecognized tax benefit — Temporary tax positions												1,500,000	2,000,000
Total unrecognized tax benefit		$ 4,300,000	$ 4,500,000			4,300,000	28,700,000		24,700,000			4,500,000	4,300,000	28,700,000	$ 24,700,000
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at Jan. 1						4,300,000	28,700,000		24,700,000
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions						600,000	900,000		1,400,000
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions						(100,000)	(600,000)		0
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions						100,000	1,300,000		3,900,000
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions						(300,000)	(19,900,000)		(1,300,000)
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities						(100,000)	(6,100,000)		0
Balance at Dec. 31		$ 4,300,000	$ 4,500,000			$ 4,500,000	$ 4,300,000		$ 28,700,000
Tax Benefits Associated With NOL And Tax Credit Carryforwards [Abstract]
NOL and tax credit carryforwards												(3,800,000)	(5,900,000)
Net Deferred Tax Liability associated with the Unrecognized Tax Benefit Amounts and Related NOLs and Tax Credit Carryforwards												(800,000)	(2,700,000)
Decrease in Unrecognized Tax Benefits is Reasonably Possible												3,600,000
Unrecognized Tax Benefits, Income Tax Penalties Accrued												0	0	$ 0
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent						21.00%	35.00%	[1]	35.00%	[1]
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent						2.30%	2.00%	[1]	2.20%	[1]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent	[2]					(4.20%)	0.00%	[1]	0.00%	[1]
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent						0.00%	(3.50%)	[1]	0.00%	[1]
Effective Income Tax Reconciliation, Adjustments Attributable to Tax Returns, Percent						(1.50%)	(0.40%)	[1]	(1.10%)	[1]
Effective Income Tax Rate Reconciliation, Other Regulatory Items, Percent						(1.30%)	(0.80%)	[1]	(1.00%)	[1]
Amortization of excess nonplant deferred taxes						(1.20%)	(0.00%)	[1]	(0.00%)	[1]
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items						(0.70%)	(0.70%)	[1]	(0.50%)	[1]
Effective Income Tax Rate Reconciliation, Tax Cuts and Jobs Act of 2017, Change in Tax Rate, Percent	[3]					0.70%	0.00%	[1]	0.00%	[1]
Effective Income Tax Rate Reconciliation Change In Unrecognized Tax Benefits						0.10%	(1.00%)	[1]	0.80%	[1]
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent						0.20%	(0.50%)	[1]	(0.40%)	[1]
Effective Income Tax Rate Reconciliation, Percent						15.40%	30.10%	[1]	35.00%	[1]
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)						$ 12,300,000	$ (20,900,000)		$ (40,900,000)
Current State and Local Tax Expense (Benefit)						2,300,000	(12,800,000)		(2,900,000)
Current Change In Unrecognized Tax Expense (Benefit)						2,300,000	(24,300,000)		3,100,000
Deferred Federal Income Tax Expense (Benefit)						20,500,000	89,900,000		116,400,000
Deferred State and Local Income Tax Expense (Benefit)						3,600,000	14,500,000		7,800,000
Deferred Change In Unrecognized Tax Expense (Benefit)						(2,000,000)	22,100,000		(1,200,000)
Deferred investment tax credits						(100,000)	(100,000)		(200,000)
Income Tax Expense (Benefit)						38,900,000	68,400,000		82,100,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred tax expense (benefit) excluding selected items						44,200,000	(414,200,000)		128,400,000
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities						(22,000,000)	540,700,000		(5,400,000)
Other Comprehensive Income (Loss), Tax						(100,000)	0		0
Deferred Income Tax Expense (Benefit)						$ 22,100,000	126,500,000		$ 123,000,000
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment												680,600,000	654,400,000
Deferred Tax Liabilities, Regulatory Assets												49,200,000	46,800,000
Deferred Tax Liabilities, Compensation and Benefits, Employee Benefits												32,300,000	33,800,000
Deferred Tax Liabilities, Other												2,900,000	4,600,000
Deferred Tax Liabilities, Gross												765,000,000	739,600,000
Deferred Tax Assets, Gross [Abstract]
Deferred Tax Assets Regulatory Liabilities												116,800,000	114,600,000
Deferred Tax Assets, Operating Loss Carryforwards												200,000	26,200,000
Deferred Tax Assets Unbilled Revenue Fuel Costs												12,700,000	10,400,000
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Employee Benefits												5,600,000	5,800,000
Deferred Tax Assets, Tax Credit Carryforwards												5,700,000	5,200,000
Deferred Tax Assets, Other												4,900,000	2,500,000
Deferred Tax Assets, Net of Valuation Allowance												145,900,000	164,700,000
Deferred Tax Liabilities, Net												619,100,000	574,900,000
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Operating Loss Carryforwards												0	115,000,000
Tax Credit Carryforward, Amount												5,700,000	5,200,000
Carryforward expiration date range, low						2021
Carryforward expiration date range, high						2038
Tax years under examination, Concluded				2012 and 2013
Year(s) under examination			2014 - 2016		2012 and 2013						2010 and 2011
Year of carryback claim under examination											2009
Potential Tax Adjustments			$ 0
TEXAS
Tax Audits [Abstract]
Earliest year subject to examination						2010
State and Local Jurisdiction
Tax Audits [Abstract]
Operating Loss Carryforwards												$ 2,900,000	$ 40,500,000
Carryforward expiration date range, low						2021
Carryforward expiration date range, high						2036
Plant Related Regulatory Liability [Member]
Federal Tax Reform [Abstract]
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Liability, Provisional Income Tax (Expense) Benefit							426,000,000
Non-Plant Related Regulated Liability [Member]
Federal Tax Reform [Abstract]
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Liability, Provisional Income Tax (Expense) Benefit							28,000,000
Non-Plant Related Regulatory Asset [Member]
Federal Tax Reform [Abstract]
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Asset, Provisional Income Tax Expense (Benefit)							$ 45,000,000

[1] Prior periods have been reclassified to conform to current year presentation.

[2] ARAM is a method to flow back excess deferred taxes to customers.

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

XML

Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) MWh in Millions, $ in Millions		Dec. 31, 2018 USD ($) MWh Counterparty	Dec. 31, 2017 MWh
Credit Concentration Risk
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		8
Credit Concentration Risk | Municipal or Cooperative Entities or Other Utilities [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		6
Credit Concentration Risk | External Credit Rating, Investment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		2
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 11.6
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		28.00%
Credit Concentration Risk | No Investment Grade Ratings from External Credit Rating Agencies [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		5
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 8.7
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		21.00%
Credit Concentration Risk | External Credit Rating, Non Investment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		1
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 0.6
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		1.00%
Interest Rate Swap
Interest Rate Derivatives [Abstract]
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months | $		$ (0.1)
Electric Commodity (in megawatt hours)
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract]
Derivative, Nonmonetary Notional Amount | MWh	[1]	5.5	4.3

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

XML

Fair Value of Financial Assets and Liabilities, Financial Impact of Qualifying Cash Flow Hedges (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1		$ (800)	$ (700)	$ (800)
After-tax net realized losses on derivative transactions reclassified into earnings		(100)	0	(100)
Adoption of ASU. 2018-02 (a)	[1]	0	(100)	0
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31		$ (700)	$ (800)	$ (700)

[1] 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.

XML

Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges	$ 0.0	$ 0.0	$ 0.0
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Interest Rate Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net	(0.1)	(0.1)	(0.2)
Other Derivative Instruments | Electric Commodity
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	7.0	0.5	3.0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	$ (4.4)	$ (0.8)	$ (2.1)

XML

Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Derivative Asset, Collateral, Obligation to Return Cash, Offset		$ 0.0	$ 0.0
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		17.8	15.9
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		15.8	19.0
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		3.6	3.6
Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		16.4	19.9
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		14.7	12.7
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	[1]	(0.2)	(2.0)
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		14.7	12.7
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	[1]	(0.2)	(2.0)
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0.0	0.0
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	[1]	(0.2)	(2.0)
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0.0	0.0
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	[1]	(0.2)	(2.0)
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0.0	0.0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0.0	0.0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0.0	0.0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0.0	0.0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0.0	0.0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0.0	0.0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0.0	0.0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0.0	0.0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		14.9	14.7
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		14.9	14.7
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0.2	2.0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0.2	2.0
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	[2]	3.1	3.2
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		15.8	19.0
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		3.6	3.6
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	[2]	16.4	19.9
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		14.9	14.7
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		14.9	14.7
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0.2	2.0
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		$ 0.2	$ 2.0

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

[2] 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.

XML

Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) (Details) - Commodity Contract - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of period	$ 12,700,000	$ 2,000,000	$ 5,100,000
Purchases	32,300,000	41,200,000	7,600,000
Settlements	(41,600,000)	(55,800,000)	(41,900,000)
Gains (losses) recognized as regulatory assets	11,300,000	25,300,000	31,200,000
Balance at end of period	14,700,000	12,700,000	2,000,000
Transfers into Level 3	0	0	0
Transfers out of Level 3	$ 0	$ 0	$ 0

XML

Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 2,126.1	$ 1,829.9
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 2,139.8	$ 2,002.0

XML

Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018 USD ($) Plan	Dec. 31, 2017 USD ($) Plan	Dec. 31, 2016 USD ($) Plan
Pension Plan [Member]
Pension Benefits [Abstract]
Total benefit obligation		$ 477.8	$ 515.9	$ 483.6
Net benefit cost recognized for financial reporting		$ 14.8	$ 14.9	$ 17.4
Minimum number of years historical achieved weighted average annual returns used to determine investment return assumptions (in years)		20 years
Expected average long-term rate of return on assets (as a percent)		6.78%	6.78%	6.78%
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)		100.00%	100.00%
Pension Plan [Member] | Domestic and international equity securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)		35.00%	34.00%
Pension Plan [Member] | Long-Duration Fixed Income and Long-duration fixed income and interest rate swap securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)		32.00%	31.00%
Pension Plan [Member] | Short-to-intermediate fixed income securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)		16.00%	19.00%
Pension Plan [Member] | Alternative investments
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)		15.00%	14.00%
Pension Plan [Member] | Cash
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)		2.00%	2.00%
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation		$ 2.0
Net benefit cost recognized for financial reporting		4.0	$ 5.0
Parent Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected contribution to postretirement health care plans during 2019		11.0
Target Pension Asset Allocations [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year		$ 11.0	$ 20.0	$ 18.0
Parent Company [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan number of pension plans to which contributions were made | Plan		4	4	4
Parent Company [Member] | Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation		$ 33.0	$ 37.0
Scenario, Forecast [Member] | Pension Plan [Member]
Pension Benefits [Abstract]
Expected average long-term rate of return on assets for next fiscal year (as a percent)	6.78%

XML

Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) - Pension Plan [Member] - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 392.2	$ 433.2	$ 380.4
Plan asset investments measured at net asset value	128.5	142.8
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	164.8	184.5
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	98.9	105.9
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Debt Securities [Member]
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	98.1	105.3
Plan asset investments measured at net asset value	0.0	0.0
Debt Securities [Member] | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Debt Securities [Member] | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	98.1	105.3
Debt Securities [Member] | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Domestic and international equity securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	14.4	15.2
Plan asset investments measured at net asset value	0.0	0.0
Domestic and international equity securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	14.4	15.2
Domestic and international equity securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Domestic and international equity securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Cash
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	21.6	26.9
Plan asset investments measured at net asset value	0.0	0.0
Cash | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	21.6	26.9
Cash | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Cash | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	261.1	288.4
Plan asset investments measured at net asset value	132.5	142.7
Commingled funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	128.6	145.7
Commingled funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Commingled funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	(3.0)	(2.6)
Plan asset investments measured at net asset value	(4.0)	0.1
Other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.2	(3.3)
Other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.8	0.6
Other | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 0.0	$ 0.0

XML

Benefit Plans and Other Postretirement Benefits, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details)	1 Months Ended	12 Months Ended
	Jan. 31, 2019 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($) Plan	Dec. 31, 2017 USD ($) Plan	Dec. 31, 2016 USD ($) Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Payment for Settlement			$ 6,900,000	$ 0
Operating and maintenance expenses			282,700,000	285,400,000	$ 265,500,000
Significant Assumptions Used to Measure Costs [Abstract]
Liability, Defined Benefit Plan, Noncurrent			(92,400,000)	(90,300,000)
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Payment for Settlement			3,300,000
Accumulated Benefit Obligation at Dec. 31			445,800,000	478,800,000
Operating and maintenance expenses			0
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	$ 477,800,000	$ 477,800,000	515,900,000	483,600,000
Service cost			9,700,000	9,800,000	9,800,000
Interest cost			18,400,000	19,700,000	21,200,000
Plan amendments			0	(1,000,000)
Actuarial loss			(34,800,000)	31,200,000
Benefit payments			(31,400,000)	(27,400,000)
Obligation at Dec. 31			477,800,000	515,900,000	483,600,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	392,200,000	392,200,000	433,200,000	380,400,000
Actual return on plan assets			(17,600,000)	56,700,000
Employer contributions			8,000,000	23,500,000
Benefit payments			(31,400,000)	(27,400,000)
Fair value of plan assets at Dec. 31			392,200,000	433,200,000	380,400,000
Funded Status of Plans at Dec. 31 [Abstract]
Funded status			(85,600,000)	(82,700,000)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery Rates [Abstract]
Net loss			230,900,000	237,000,000
Prior service credit			(1,200,000)	(1,300,000)
Total			229,700,000	235,700,000
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
Current regulatory assets			12,900,000	13,900,000
Noncurrent regulatory assets			216,800,000	221,800,000
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Current Regulatory Liabilities			0	0
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Noncurrent Regulatory Liabilities			0	0
Total			$ 229,700,000	$ 235,700,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)			4.31%	3.63%
Expected average long-term increase in compensation level (as a percent)			3.75%	3.75%
Mortality table			RP-2014	RP-2014
Cash Flows [Abstract]
Payment for Pension Benefits			$ 8,000,000	$ 24,000,000	18,000,000
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost			9,700,000	9,800,000	9,800,000
Interest cost			18,400,000	19,700,000	21,200,000
Expected return on plan assets			(28,300,000)	(27,900,000)	(27,600,000)
Amortization of prior service cost			(100,000)	0	0
Amortization of net loss			14,100,000	13,000,000	12,000,000
Net periodic pension cost			17,000,000	14,600,000	15,400,000
Net benefit cost recognized for financial reporting			$ 14,800,000	$ 14,900,000	$ 17,400,000
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)			3.63%	4.13%	4.66%
Expected average long-term increase in compensation level (as a percent)			3.75%	3.75%	4.00%
Expected average long-term rate of return on assets (as a percent)			6.78%	6.78%	6.78%
Plan participant's contributions			$ 0	$ 0
Plan participant's contributions			0	0
Liability, Defined Benefit Plan, Noncurrent			(85,600,000)	(82,700,000)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position			(85,600,000)	(82,700,000)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement			3,200,000	0	$ 0
Defined Benefit Plan, Costs Not Recognized Due To Regulation			$ (2,200,000)	$ 300,000	$ 2,000,000
Pension Plan [Member] | Subsequent Event
Cash Flows [Abstract]
Payment for Pension Benefits	$ 17,000,000
Parent Company [Member] | Pension Plan [Member]
Cash Flows [Abstract]
Number of pension plans to which contributions were made | Plan			4	4	4
Payment for Pension Benefits		$ 150,000,000	$ 150,000,000	$ 162,000,000	$ 125,000,000

XML

Benefit Plans and Other Postretirement Benefits, Defined Contribution Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Contribution Plans [Abstract]
Contributions to 401(k) and other defined contribution plans	$ 3.0	$ 3.0	$ 3.0

XML

Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) - Other Postretirement Benefits Plan [Member]	Dec. 31, 2018	Dec. 31, 2017
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	100.00%	100.00%
Domestic and international equity securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	18.00%	24.00%
Long-Duration Fixed Income and Long-duration fixed income and interest rate swap securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	0.00%	0.00%
Short-to-intermediate fixed income securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	70.00%	60.00%
Alternative investments
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	8.00%	9.00%
Cash
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	4.00%	7.00%

XML

Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Other Postretirement Benefits Plan [Member]
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 40.0	$ 44.1	$ 42.3
Plan assets at net asset value	3.8	0.0
Other Postretirement Benefits Plan [Member] | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	14.6	20.2
Other Postretirement Benefits Plan [Member] | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	21.6	23.9
Other Postretirement Benefits Plan [Member] | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Other Postretirement Benefits Plan [Member] | Debt Securities [Member]
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	17.2	19.0
Plan assets at net asset value	0.0	0.0
Other Postretirement Benefits Plan [Member] | Debt Securities [Member] | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Other Postretirement Benefits Plan [Member] | Debt Securities [Member] | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	17.2	19.0
Other Postretirement Benefits Plan [Member] | Debt Securities [Member] | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Other Postretirement Benefits Plan [Member] | Cash
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1.8	2.8
Plan assets at net asset value	0.0	0.0
Other Postretirement Benefits Plan [Member] | Cash | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1.8	2.8
Other Postretirement Benefits Plan [Member] | Cash | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Other Postretirement Benefits Plan [Member] | Cash | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Other Postretirement Benefits Plan [Member] | Insurance contracts
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	4.3	4.7
Plan assets at net asset value	0.0	0.0
Other Postretirement Benefits Plan [Member] | Insurance contracts | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Other Postretirement Benefits Plan [Member] | Insurance contracts | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	4.3	4.7
Other Postretirement Benefits Plan [Member] | Insurance contracts | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Other Postretirement Benefits Plan [Member] | Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.1	0.2
Plan assets at net asset value	0.0	0.0
Other Postretirement Benefits Plan [Member] | Other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Other Postretirement Benefits Plan [Member] | Other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.1	0.2
Other Postretirement Benefits Plan [Member] | Other | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Other Postretirement Benefits Plan [Member] | Commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	16.6	14.1
Plan assets at net asset value	3.8	0.0
Other Postretirement Benefits Plan [Member] | Commingled funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	12.8	14.1
Other Postretirement Benefits Plan [Member] | Commingled funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Other Postretirement Benefits Plan [Member] | Commingled funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Other Postretirement Benefits Plan [Member] | Domestic and international equity securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	3.3
Plan assets at net asset value	0.0	0.0
Other Postretirement Benefits Plan [Member] | Domestic and international equity securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	3.3
Other Postretirement Benefits Plan [Member] | Domestic and international equity securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Other Postretirement Benefits Plan [Member] | Domestic and international equity securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.0	0.0
Parent Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Payment for Other Postretirement Benefits	$ 11.0	$ 20.0	$ 18.0

XML

Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Significant Assumptions Used to Measure Costs [Abstract]
Liability, Defined Benefit Plan, Noncurrent		$ (92.4)	$ (90.3)
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan amendments		0.0	0.0
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	$ 41.8	47.0	41.9
Service cost		1.1	0.9	$ 0.8
Interest cost		1.6	1.7	1.8
Plan participant's contributions		0.6	0.6
Actuarial loss		(5.1)	4.7
Benefit payments		(3.4)	(2.8)
Obligation at Dec. 31		41.8	47.0	41.9
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	40.0	44.1	42.3
Actual return on plan assets		(1.3)	3.8
Plan participant's contributions		0.6	0.6
Employer contributions		0.0	0.2
Benefit payments		(3.4)	(2.8)
Fair value of plan assets at Dec. 31		40.0	44.1	42.3
Funded Status of Plans at Dec. 31 [Abstract]
Funded status		(1.8)	(2.9)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery Rates [Abstract]
Net loss		(9.6)	(8.6)
Prior service credit		(1.8)	(2.2)
Total		(11.4)	(10.8)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost (Credit) Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Current Regulatory Assets		0.0	0.0
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Noncurrent Regulatory Assets		0.0	0.0
Current regulatory liabilities		(0.9)	(0.8)
Noncurrent regulatory liabilities		(10.5)	(10.0)
Total		$ (11.4)	$ (10.8)
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)		4.32%	3.62%
Mortality table		RP-2014	RP-2014
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65		6.50%	7.00%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65		5.30%	5.50%
Ultimate health care trend assumption rate (as a percent)		4.50%	4.50%
Period until ultimate trend rate is reached (in years)		4	5
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 1.1	$ 0.9	0.8
Interest cost		1.6	1.7	1.8
Expected return on plan assets		(2.5)	(2.4)	(2.4)
Amortization of prior service cost		(0.4)	(0.4)	(0.4)
Amortization of net loss		(0.4)	(0.6)	(0.6)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement		0.0	0.0	0.0
Net periodic pension cost		$ (0.6)	$ (0.8)	$ (0.8)
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)		3.62%	4.13%	4.65%
Expected average long-term increase in compensation level (as a percent)		0.00%	0.00%	0.00%
Expected average long-term rate of return on assets (as a percent)		5.80%	5.80%	5.80%
Liability, Defined Benefit Plan, Noncurrent		$ (1.8)	$ (2.9)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position		(1.8)	(2.9)
Defined Benefit Plan, Costs Not Recognized Due To Regulation		0.0	0.0	$ 0.0
Net benefit cost recognized for financial reporting		(0.6)	(0.8)	(0.8)
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Payment for Pension Benefits		8.0	24.0	18.0
Plan amendments		0.0	(1.0)
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	477.8	515.9	483.6
Service cost		9.7	9.8	9.8
Interest cost		18.4	19.7	21.2
Plan participant's contributions		0.0	0.0
Actuarial loss		(34.8)	31.2
Benefit payments		(31.4)	(27.4)
Obligation at Dec. 31		477.8	515.9	483.6
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	392.2	433.2	380.4
Actual return on plan assets		(17.6)	56.7
Plan participant's contributions		0.0	0.0
Employer contributions		8.0	23.5
Benefit payments		(31.4)	(27.4)
Fair value of plan assets at Dec. 31		392.2	433.2	380.4
Funded Status of Plans at Dec. 31 [Abstract]
Funded status		(85.6)	(82.7)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery Rates [Abstract]
Net loss		230.9	237.0
Prior service credit		(1.2)	(1.3)
Total		229.7	235.7
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost (Credit) Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Current Regulatory Assets		12.9	13.9
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Noncurrent Regulatory Assets		216.8	221.8
Current regulatory liabilities		0.0	0.0
Noncurrent regulatory liabilities		0.0	0.0
Total		$ 229.7	$ 235.7
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)		4.31%	3.63%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase		3.75%	3.75%
Mortality table		RP-2014	RP-2014
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 9.7	$ 9.8	9.8
Interest cost		18.4	19.7	21.2
Expected return on plan assets		(28.3)	(27.9)	(27.6)
Amortization of prior service cost		(0.1)	0.0	0.0
Amortization of net loss		14.1	13.0	12.0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement		(3.2)	0.0	0.0
Net periodic pension cost		$ 17.0	$ 14.6	$ 15.4
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)		3.63%	4.13%	4.66%
Expected average long-term increase in compensation level (as a percent)		3.75%	3.75%	4.00%
Expected average long-term rate of return on assets (as a percent)		6.78%	6.78%	6.78%
Liability, Defined Benefit Plan, Noncurrent		$ (85.6)	$ (82.7)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position		(85.6)	(82.7)
Defined Benefit Plan, Costs Not Recognized Due To Regulation		2.2	(0.3)	$ (2.0)
Net benefit cost recognized for financial reporting		14.8	14.9	17.4
Parent Company [Member]
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year		11.0	20.0	18.0
Expected contribution to postretirement health care plans during 2019		11.0
Parent Company [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Payment for Pension Benefits	$ 150.0	$ 150.0	$ 162.0	$ 125.0

XML

Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details) $ in Millions	Dec. 31, 2018 USD ($)
Pension Plan [Member]
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2019	$ 29.7
2020	30.0
2021	29.3
2022	30.8
2023	30.8
2024-2028	156.2
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2019	3.2
2020	3.1
2021	3.2
2022	3.2
2023	3.2
2024-2028	14.4
Expected Medicare Part D Subsidies [Abstract]
2019	0.0
2020	0.0
2021	0.0
2022	0.0
2023	0.0
2024-2028	0.2
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
2019	3.2
2020	3.1
2021	3.2
2022	3.2
2023	3.2
2024-2028	$ 14.2

XML

Commitments and Contingencies, Fuel Contracts (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018 USD ($)
Coal
Fuel Contracts [Abstract]
2019	$ 127,300
2020	83,900
2021	41,000
2022	41,200
2023	0
Thereafter	0
Total	293,400
Natural Gas Supply [Member]
Fuel Contracts [Abstract]
2019	20,300
2020	0
2021	0
2022	0
2023	0
Thereafter	0
Total	20,300
Natural Gas Storage and Transportation [Member]
Fuel Contracts [Abstract]
2019	30,300
2020	30,300
2021	25,200
2022	19,300
2023	14,100
Thereafter	33,600
Total	$ 152,800
Minimum
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date	2019
Maximum
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date	2033

XML

Commitments and Contingencies, Purchased Power Agreements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Long-term Contract for Purchase of Electric Power [Line Items]
Operating Lease Purchase Power Agreement Expiration Date	2033
Capacity
Purchased Power Agreements (PPAs) [Abstract]
Payments for capacity	$ 57.6	$ 58.4	$ 56.8
Estimated Future Payments Under PPAs [Abstract]
2019	20.3
2020	12.0
2021	12.2
2022	12.4
2023	12.6
Thereafter	5.7
Total	$ 75.2

XML

Commitments and Contingencies, Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Leased Assets [Line Items]
Operating Lease Purchase Power Agreement Expiration Date	2033
Operating Leases, Future Minimum Payments Due [Abstract]
2018	$ 51.9
2019	51.4
2020	51.3
2021	51.3
2022	51.3
Thereafter	507.1
Office Space and Other Equipment
Operating Leases [Abstract]
Total expenses under operating lease obligations	59.0	$ 57.8	$ 56.6
Operating Leases, Future Minimum Payments Due [Abstract]
2018	5.2
2019	5.2
2020	5.1
2021	5.1
2022	5.1
Thereafter	56.3
Purchased Power Agreements
Operating Leases [Abstract]
Payments for capacity	51.1	$ 51.4	$ 50.6
Operating Leases, Future Minimum Payments Due [Abstract]
2018	46.7
2019	46.2
2020	46.2
2021	46.2
2022	46.2
Thereafter	$ 450.8

XML

Commitments and Contingencies, Variable Interest Entities (Details) - MW	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Independent Power Producing Entities
Purchased Power Agreements [Abstract]
Generating capacity (in MW)	1,197	897
VIE Purchase Power Agreement Expiration	2041
Tolk Station Power Plant
Fuel Contracts [Abstract]
Coal Supply Agreement Expiration	2022

XML

Commitments and Contingencies Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) - Other MGP, Landfill, or Disposal Sites $ in Millions	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Site Contingency [Line Items]
Number of identified MGP sites under current investigation and/or remediation	1
Accrual for Environmental Loss Contingencies	$ 0.1	$ 0.1

XML

Commitments and Contingencies, Environmental Contingencies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($)
Harrington Units 1 and 2 | Implementation of the National Ambient Air Quality Standard for Sulfur Dioxide
Environmental Requirements [Abstract]
Number of Years Unclassifiable Areas Will Be Monitored	3 years
Tolk Units 1 and 2 | Capital Commitments | Regional Haze Rules
Environmental Requirements [Abstract]
Liability for Estimated Cost to Comply with Regulation	$ 600

XML

Commitments and Contingencies, Asset Retirement Obligations (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Liabilities Settled	$ 0	$ 0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	28,500,000	28,700,000
Liabilities Incurred	0	0
Accretion	1,600,000	1,500,000
Cash flow revisions	2,300,000	(1,700,000)
Ending balance	32,400,000	28,500,000
Electric Plant Steam Production Asbestos
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Liabilities Settled	0	0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	20,300,000	20,700,000
Liabilities Incurred	0	0
Accretion	1,200,000	1,300,000
Cash flow revisions	500,000	(1,700,000)
Ending balance	22,000,000	20,300,000
Electric Plant Electric Distribution
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Liabilities Settled	0	0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	7,000,000	6,800,000
Liabilities Incurred	0	0
Accretion	300,000	200,000
Cash flow revisions	1,800,000	0
Ending balance	9,100,000	7,000,000
Electric Plant Other
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Liabilities Settled	0	0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	1,200,000	1,200,000
Liabilities Incurred	0	0
Accretion	100,000	0
Cash flow revisions	0	0
Ending balance	$ 1,300,000	$ 1,200,000

XML

Commitments and Contingencies, Removal Costs (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 188	$ 197

XML

Commitments and Contingencies, Legal Contingencies (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Aug. 31, 2018	Dec. 31, 2018	Dec. 31, 2016
Loss Contingencies [Line Items]
Public Utilities, Amount proposed changes would increase wholesale transmission revenues		$ 9.4
Legal Contingencies [Abstract]
Public Utilities, Amount of proposed changes would be recoverable		$ 4.4
Southwest Power Pool (SPP) [Member] | SPP Open Access Transmission Tariff Upgrade Costs [Member]
Loss Contingencies [Line Items]
Public Utilities, Annual Transmission Revenue Requirement Increase	$ 9.5
Legal Contingencies [Abstract]
Public Utilities, Annual Transmission Revenue Requirement Increase (SPS)	6.0
Public Utilities, Annual Transmission Revenue Requirement (Other Utilities)	$ 3.5
SPS [Member] | Southwest Power Pool (SPP) [Member] | SPP Open Access Transmission Tariff Upgrade Costs [Member]
Loss Contingencies [Line Items]
Public Utilities, Billed Charges For Transmission Service Upgrades			$ 13.0

XML

Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	$ 2,130,300
(Gains) losses reclassified from net accumulated other comprehensive loss	0	$ (100)
Net current period other comprehensive income (loss)	100	100
Adoption of ASU No. 2018-02		0
Accumulated other comprehensive loss at end of period	2,536,600	2,130,300
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss) Arising During Period, Tax	0	0	$ (100)
Income Tax Expense (Benefit)	38,900	68,400	82,100
AOCI Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(1,500)	(1,300)
Adoption of ASU No. 2018-02		(300)
Accumulated other comprehensive loss at end of period	(1,400)	(1,500)	(1,300)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(700)	(600)
(Gains) losses reclassified from net accumulated other comprehensive loss	0	(100)
Net current period other comprehensive income (loss)	0	100
Adoption of ASU No. 2018-02		(200)
Accumulated other comprehensive loss at end of period	(700)	(700)	(600)
Reclassification from AOCI, Current Period, Tax	0	0
Gains and Losses on Cash Flow Hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(800)	(700)
(Gains) losses reclassified from net accumulated other comprehensive loss	0	0
Net current period other comprehensive income (loss)	100	0
Adoption of ASU No. 2018-02		(100)
Accumulated other comprehensive loss at end of period	(700)	(800)	$ (700)
Interest Rate Swap
AOCI Attributable to Parent, Net of Tax [Roll Forward]
(Gains) losses reclassified from net accumulated other comprehensive loss	(100)	0
Interest Rate Swap | Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
(Gains) losses reclassified from net accumulated other comprehensive loss	0	0
Interest Rate Swap | Gains and Losses on Cash Flow Hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
(Gains) losses reclassified from net accumulated other comprehensive loss	(100)	0
Reclassification out of Accumulated Other Comprehensive Income [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Income Tax Expense (Benefit)	0	0
Reclassification from AOCI, Current Period, Tax	0	0
Reclassification out of Accumulated Other Comprehensive Income [Member] | Gains and Losses on Cash Flow Hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Income Tax Expense (Benefit)	$ 0	$ 100

XML

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating expenses [Abstract]
Purchased power	$ 0.0	$ 1.4	$ 8.8
Other operating expenses - paid to Xcel Energy Services Inc.	195.1	196.6	188.2
Interest expense	0.6	0.0	$ 0.2
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	10.5	1.3
Accounts payable	19.9	22.6
NSP-Minnesota
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	4.7	1.0
Accounts payable	0.0	0.0
PSCo
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0.0	0.0
Accounts payable	0.7	0.3
Other Subsidiaries of Xcel Energy Inc.
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	5.8	0.3
Accounts payable	$ 19.2	$ 22.3

XML

Summarized Quarterly Financial Data (Unaudited) (Details) - USD ($) $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 464,600		$ 540,100		$ 481,300		$ 447,200		$ 426,500		$ 551,600		$ 479,800		$ 460,100		$ 1,933,200	$ 1,918,000	$ 1,851,000
Operating income	56,000	[1]	111,000	[1]	87,600	[1]	57,100	[1]	43,400	[1]	123,100	[1]	75,200	[1]	59,200	[1]	311,700	300,900	311,300
Net income	$ 40,200		$ 81,500		$ 58,500		$ 33,100		$ 31,000		$ 67,800		$ 35,300		$ 25,100		$ 213,300	$ 159,200	$ 152,200

[1] (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.

XML

Schedule II, Valuation and Qualifying Accounts (Details) - Allowance for Bad Debts - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1	$ 6.4	$ 6.4	$ 5.9
Charged to costs and expenses	4.9	5.1	6.1
Charged to other accounts	1.0	1.2	0.9
Deductions from reserves	(6.7)	(6.3)	(6.5)
Balance at Dec. 31	$ 5.6	$ 6.4	$ 6.4