UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2013

or

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

Commission file number:  001-03789

SOUTHWESTERN PUBLIC SERVICE COMPANY

(Exact name of registrant as specified in its charter)

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

Tyler at Sixth, Amarillo, Texas  79101

(Address of principal executive offices)

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

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

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.  o Yes ý 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.  o Yes ý 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.  ý Yes   o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  ý Yes  o 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.  ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act

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

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

As of Feb. 24, 2014, 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

Xcel Energy Inc.’s Definitive Proxy Statement for its 2014 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

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

TABLE OF CONTENTS

Index

PART I	3
Item 1 — Business	3
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS	3
COMPANY OVERVIEW	5
ELECTRIC UTILITY OPERATIONS	5
Public Utility Regulation	5
Capacity and Demand	6
Energy Sources and Related Transmission Initiatives	6
Fuel Supply and Costs	7
Fuel Sources	7
Renewable Energy Sources	8
Wholesale Commodity Marketing Operations	8
Summary of Recent Federal Regulatory Developments	9
Electric Operating Statistics	10
Natural Gas Facilities Used for Electric Generation	11
GENERAL	11
ENVIRONMENTAL MATTERS	12
EMPLOYEES	12
Item 1A — Risk Factors	12
Item 1B — Unresolved Staff Comments	21
Item 2 — Properties	21
Item 3 — Legal Proceedings	22
Item 4 — Mine Safety Disclosures	22
PART II	23
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	23
Item 6 — Selected Financial Data	23
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 7A — Quantitative and Qualitative Disclosures About Market Risk	26
Item 8 — Financial Statements and Supplementary Data	27
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	70
Item 9A — Controls and Procedures	70
Item 9B — Other Information	70
PART III	70
Item 10 — Directors, Executive Officers and Corporate Governance	70
Item 11 — Executive Compensation	70
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	70
Item 13 — Certain Relationships and Related Transactions, and Director Independence	70
Item 14 — Principal Accountant Fees and Services	71
PART IV	72
Item 15 — Exhibits, Financial Statement Schedules	72
SIGNATURES	76

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

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PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
NCE	New Century Energies, Inc.
NSP-Minnesota	Northern States Power Company, a Minnesota corporation
NSP-Wisconsin	Northern States Power Company, a Wisconsin corporation
PSCo	Public Service Company of Colorado
SPS	Southwestern Public Service Company
Utility subsidiaries	NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
Xcel Energy	Xcel Energy Inc. and its subsidiaries
Federal and State Regulatory Agencies
CFTC	Commodity Futures Trading Commission
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
DOT	United States Department of Transportation
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
IRS	Internal Revenue Service
NERC	North American Electric Reliability Council
NMAG	New Mexico Attorney General
NMPRC	New Mexico Public Regulation Commission
PNM	Public Service Company of New Mexico
PUCT	Public Utility Commission of Texas
SEC	Securities and Exchange Commission
Electric and Resource Adjustment Clauses
DCRF	Distribution cost recovery factor
DRC	Deferred renewable cost rider
DSM	Demand side management
EE	Energy efficiency
EECRF	Energy efficiency cost recovery factor
FCA	Fuel clause adjustment
FPPCAC	Fuel and purchased power cost adjustment clause
OATT	Open access transmission tariff
PCRF	Power cost recovery factor
TCRF	Transmission cost recovery factor (recovers transmission infrastructure improvement costs and changes in wholesale transmission charges)
Other Terms and Abbreviations
AFUDC	Allowance for funds used during construction
APBO	Accumulated postretirement benefit obligation
ARO	Asset retirement obligation
ASU	FASB Accounting Standards Update
BART	Best available retrofit technology
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CCN	Certificate of convenience and necessity
CO2	Carbon dioxide
CP	Coincident peak
CSAPR	Cross-State Air Pollution Rule
CWIP	Construction work in progress

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ETR	Effective tax rate
FASB	Financial Accounting Standards Board
FTR	Financial transmission right
GAAP	Generally accepted accounting principles
GHG	Greenhouse gas
HTY	Historic test year
JOA	Joint operating agreement
MISO	Midcontinent Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investor Services
Native load	Customer demand of retail and wholesale customers whereby a utility has an obligation to serve under statute or long-term contract.
NOL	Net operating loss
NOx	Nitrogen oxide
NSPS	New source performance standard
NTC	Notifications to construct
O&M	Operating and maintenance
OCI	Other comprehensive income
PCB	Polychlorinated biphenyl
PJM	PJM Interconnection, LLC
PM	Particulate matter
PPA	Purchased power agreement
PRP	Potentially responsible party
PTC	Production tax credit
PV	Photovoltaic
QF	Qualifying facilities
REC	Renewable energy credit
ROE	Return on equity
ROFR	Right of first refusal
RPS	Renewable portfolio standards
RTO	Regional Transmission Organization
SIP	State implementation plan
Sharyland	Sharyland Distribution and Transmission Services, LLC
SO2	Sulfur dioxide
SPP	Southwest Power Pool, Inc.
Standard & Poor’s	Standard & Poor’s Ratings Services
Measurements
KV	Kilovolts
KWh	Kilowatt hours
MMBtu	Million British thermal units
MW	Megawatts
MWh	Megawatt hours

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COMPANY OVERVIEW

SPS was incorporated in 1921 under the laws of New Mexico.  SPS is a utility engaged primarily in the generation, purchase, transmission, distribution, and sale of electricity in portions of Texas and New Mexico.  The wholesale customers served by SPS comprised approximately 33 percent of its total KWh sold in 2013.  SPS provides electric utility service to approximately 383,000 retail customers in Texas and New Mexico.  Approximately 73 percent of SPS’ retail electric operating revenues were derived from operations in Texas during 2013.  Although SPS’ large commercial and industrial electric retail customers are comprised of many diversified industries, a significant portion of SPS’ large commercial and industrial electric sales include the following industries:  oil and gas extraction, as well as petroleum and coal products.  For small commercial and industrial customers, significant electric retail sales include the following industries: oil and gas extraction and crop related agricultural industries.  Generally, SPS’ earnings contribute approximately 5 percent to 15 percent of Xcel Energy’s consolidated net income.

SPS’ corporate strategy focuses on four core objectives: driving operational excellence; providing options and solutions to customers; investing for the future; and enhancing engagement with employees, customers, shareholders, communities and policy makers.  SPS files periodic rate cases and establishes formula rates or automatic rate adjustment mechanisms with state and federal regulators to earn a return on its investments and recover costs of operations.  Environmental leadership is a core priority for SPS and is designed to meet customer and policy maker expectations for clean energy at a competitive price while creating shareholder value.

ELECTRIC UTILITY OPERATIONS

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — The PUCT and NMPRC regulate SPS’ retail electric operations and have jurisdiction over its retail rates and services and the construction of transmission or generation in their respective states.  The municipalities in which SPS operates in Texas have original jurisdiction over SPS’ rates in those communities.  Each municipality can deny SPS’ rate increases.  SPS can then appeal municipal rate decisions to the PUCT, which hears all municipal rate denials in one hearing. The NMPRC also has jurisdiction over the issuance of securities.  SPS is regulated by the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce.  SPS has received authorization from the FERC to make wholesale electric sales at market-based prices.

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

• DCRF — The DCRF rider recovers distribution costs in Texas.

• DRC — The DRC rider recovers deferred costs associated with renewable energy programs in New Mexico.

• EECRF — The EECRF rider recovers costs associated with providing energy efficiency programs in Texas.

• EE rider — The EE rider recovers costs associated with providing energy efficiency programs in New Mexico.

• FPPCAC — The FPPCAC adjusts monthly to recover the difference between the actual fuel and purchased power costs and the amount included in base rates of SPS’ New Mexico retail jurisdiction.

• PCRF — The PCRF rider allows recovery of certain purchased power costs in Texas.

• TCRF — The TCRF rider recovers transmission infrastructure improvement costs and changes in wholesale transmission charges in Texas.

Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor, which is part of SPS’ retail electric tariff.  SO₂ and NOx allowance revenues and costs are also recovered through the fixed fuel and purchased energy recovery factor. The regulations allow retail fuel factors to change up to three times per year.

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

PUCT regulations require periodic examination of SPS’ fuel and purchased energy costs, the efficient use of fuel and purchased energy, fuel acquisition and management policies and purchased energy commitments.  SPS is required to file an application for the PUCT to retrospectively review fuel and purchased energy costs at least every three years.

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NMPRC regulations require SPS to request authority to continue collecting its fuel and purchased power costs through a fuel adjustment clause every four years.  The NMPRC has granted SPS authority to use a fuel adjustment clause through November 2014.

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

Capacity and Demand

Uninterrupted system peak demand for SPS for each of the last three years and the forecast for 2014, assuming normal weather, is listed below.

System Peak Demand (in MW)
2011	2012	2013	2014 Forecast
5,210	5,265	5,056	5,119

The peak demand for the SPS system typically occurs in the summer. The 2013 uninterrupted system peak demand for SPS occurred on Aug. 6, 2013. The 2013 peak demand is down slightly from the previous year, when peak weather conditions were hotter.

Energy Sources and Related Transmission Initiatives

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

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

In November 2013, the NMPRC approved SPS’ request to enter into three PPAs for approximately 700 MW of additional wind power. These contracts were entered into by SPS for economic purposes, not to meet the state mandated renewable energy portfolios.

Purchased Transmission Services — SPS has contractual arrangements with SPP and regional transmission service providers, including PSCo, to deliver power and energy to its native load customers, which are retail and wholesale load obligations with terms of more than one year.

SPP Integrated Market (IM)— SPP has operated a regional energy imbalance market since 2007. SPS has recovered related charges and revenues in its retail and wholesale rates. In 2012 and 2013, the FERC approved proposed revisions to the SPP tariff to allow SPP to operate a day ahead/real time energy and ancillary services market similar to the regional market operated by MISO. The SPP IM is scheduled to start operations on March 1, 2014. SPS has submitted filings to the FERC to modify its wholesale power sales contracts to allow recovery of SPP IM charges and revenues through the SPP wholesale FCA. SPS has also requested FERC approval to make sales to the SPP IM at market-based rates. FERC approval of the tariff and market based rates filings are pending. SPS has also filed changes to its retail tariffs in Texas and New Mexico to allow retail FCA treatment of SPP IM charges and revenues.

Transmission NTCs — As a member of SPP, SPS accepts NTCs for transmission projects. These are typically a portfolio of transmission lines and electric substation projects. SPS has accepted NTCs for several hundred miles of transmission lines and substations at an estimated capital cost of approximately $1.4 billion and will continue to review new NTCs for acceptance as they are issued. These projects generally span several years to plan, site, procure and develop. Typical SPS capital spending for SPP NTC transmission projects is approximately $200 to $300 million per year, but may vary. The NMPRC and the PUCT must approve the siting and routing of all SPP identified transmission line NTC projects that require permitting approval. Projects identified through SPP NTCs may have costs allocated to other SPP members in accordance with the SPP open access transmission tariff. Costs allocated to SPS are permissible for recovery through the NMPRC, the PUCT and the FERC processes.

6

TUCO Inc. (TUCO) to Woodward, Okla. 345 KV transmission line

The TUCO to Woodward District extra high voltage interchange is a 345 KV transmission line. SPS is constructing the line to just inside the Oklahoma state line, and Oklahoma Gas and Electric Company (OGE) is building from there to Woodward, Okla. SPS’ estimated investment in the TUCO to Woodward line and substation is $185 million and is expected to be recovered from SPP members, including SPS, in accordance with the SPP OATT and the ratemaking process. The PUCT approved SPS’ CCN to build the line in 2012. It is anticipated to be complete in mid-2014.

Hitchland substation to Woodward, Okla. 345 KV transmission line

The Hitchland substation to Woodward line is a 345 KV double circuit transmission line and associated substation facilities in the Oklahoma and Texas Panhandle. SPS is building the first 30 miles and OGE is completing the line from there to Woodward, Okla. SPS’ estimated investment for the Hitchland to Woodward line and substation is $63 million and is expected to be recovered from SPP members in accordance with the SPP OATT and the ratemaking process. The line is anticipated to be complete in mid-2014.

Jones CCN— In August 2011, the PUCT approved SPS’ request for a CCN to build a gas-fired combustion turbine generating unit at SPS’ existing Jones Station in Lubbock, Texas (Jones Unit 4). In February 2012, the NMPRC approved the CCN with a projected cost of $118 million, inclusive of AFUDC. Jones Unit 4 achieved commercial operation in May 2013 and added 168 MW of capacity to the SPS service territory.

Resource Plans — SPS is required to develop and implement a renewable portfolio plan in which 10 percent of its energy to serve its New Mexico retail customers is produced by renewable resources in 2011, increasing to 15 percent in 2015. SPS primarily fulfills its renewable portfolio requirements through the purchase of wind energy. SPS was granted a variance from the NMPRC to extend the time to implement a portion of the diversity requirements to 2015.

CSAPR — CSAPR addresses long range transport of PM and ozone by requiring reductions in SO₂ and NOx from utilities located in the eastern half of the United States. In December 2013, the U.S. Supreme Court heard oral arguments on the D.C. Circuit’s 2012 decision to vacate the CSAPR. A decision is anticipated by June 2014. It is not yet known whether the D.C. Circuit’s decision will be upheld, or how the EPA might approach a replacement rule. Therefore, it is not known what requirements may be imposed in the future. CSAPR is discussed further at Note 11 to the financial statements — Environmental Contingencies.

Fuel Supply and Costs

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

	Coal				Natural Gas				Weighted Average Owned Fuel Cost
	Cost		Percent		Cost		Percent
2013	$	2.14	71	%	$	3.97	29	%	$	2.68
2012	1.87		67		2.99		33		2.24
2011	1.89		67		4.37		33		2.71

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

Fuel Sources

Coal— SPS purchases all of the coal requirements for its two coal facilities, Harrington and Tolk electric generating stations, from TUCO. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers. The coal supply contract with TUCO expires in 2016 and 2017 for the Harrington station and Tolk station, respectively.  As of Dec. 31, 2013 and 2012, coal inventories at SPS were approximately 42 and 40 days supply, respectively.  TUCO has coal agreements to supply 93 percent of SPS’ estimated coal requirements in 2014, and a declining percentage of the requirements in subsequent years. SPS’ general coal purchasing objective is to contract for approximately 100 percent of requirements for the following year, 67 percent of requirements in two years, and 33 percent of requirements in three years.

7

Natural gas— SPS uses both firm and interruptible natural gas supply and standby oil in combustion turbines and certain boilers. Natural gas for SPS’ power plants is procured under contracts to provide an adequate supply of fuel; which typically is purchased with terms of one year or less. The transportation and storage contracts expire in various years from 2014 to 2033.  All of the natural gas supply contracts have pricing that is tied to various natural gas indices.

Most transportation contract pricing is based on FERC and Railroad Commission of Texas approved transportation tariff rates. Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery.  SPS’ commitments related to gas supply contracts were approximately $21 million and $57 million and commitments related to gas transportation and storage contracts were approximately $201 million and $229 million at Dec. 31, 2013 and 2012, respectively.

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

Renewable Energy Sources

SPS’ renewable energy portfolio includes wind and solar power from both owned generating facilities and PPAs.As of Dec. 31, 2013, SPS is in compliance with mandated RPS, which require generation from renewable resources of approximately four percent and 10 percent of Texas and New Mexico electric retail sales, respectively.  Renewable energy comprised 12.7 percent and 8.0 percent of SPS’ total owned and purchased energy for 2013 and 2012, respectively.  Wind energy comprised 12.1 percent and 7.4 percent of SPS’ total owned and purchased energy for 2013 and 2012, respectively.  Solar power comprised approximately 0.4 percent and 0.5 percent of SPS’ total owned and purchased energy for 2013 and 2012, respectively.

SPS also offers customer-focused renewable energy initiatives.  Windsource allows customers in New Mexico to purchase a portion or all of their electricity from renewable sources.  The number of Windsource participants dropped from approximately 1,000 in 2012 to 900 in 2013 due to residential attrition, while Windsource MWh sales remained consistent from approximately 4,400 MWh in 2012 to 4,400 MWh in 2013.  Additionally, to encourage the growth of solar energy on the system in New Mexico, customers are offered incentives to install solar panels on their homes and businesses under the Solar*Rewards program.  Over 115 PV systems with approximately 7.6 MW of aggregate capacity and over 80 PV systems with approximately 4.5 MW of aggregate capacity have been installed in New Mexico under this program as of Dec. 31, 2013 and 2012, respectively.

Wind— SPS acquires its wind energy from long-term PPAs with wind farm owners, primarily located in the Texas Panhandle area of Texas and New Mexico. SPS currently has six of these agreements in place, with facilities ranging in size from under two MW to 161 MW for a total capacity greater than 600 MW. In 2013, the NMPRC approved three PPAs for approximately 700 MW of wind power. In addition to receiving purchased wind energy under these agreements, SPS also typically receives wind RECs, which are used to meet state renewable resource requirements. The average cost per MWh of wind energy under the PPA and QF contracts was approximately $26 for each of 2013 and 2012. The cost per MWh of wind energy varies by contract and may be influenced by a number of factors including regulation, state-specific renewable resource requirements and the year of contract execution. Generally, contracts executed in 2013 continued to benefit from improvements in technology, excess capacity among manufacturers, and motivation to commence new construction prior to the expiration of the Federal PTCs in 2013. At the end of each of 2013 and 2012, SPS had over 1,000 MW of wind energy on its system. With these projects, SPS is anticipated to have approximately 1,800 MW of wind power.

Wholesale Commodity Marketing Operations

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

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Summary of Recent Federal Regulatory Developments

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

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) — The FERC issued Order 1000 in July 2011 adopting new requirements for transmission planning, cost allocation and development to be effective prospectively.  In Order 1000, the FERC required utilities, including RTO’s such as SPP, to file compliance tariffs that provide for joint regional transmission planning and cost allocation for all FERC-jurisdictional utilities within a region.  In addition, Order 1000 required that regions coordinate to develop interregional plans for transmission planning and cost allocation.  A key provision of Order 1000 is a requirement that FERC-jurisdictional wholesale transmission tariffs exclude provisions that would grant the incumbent transmission owner a federal ROFR to build certain types of transmission projects in its service area.

The removal of a federal ROFR would eliminate rights that SPS currently has under the SPP tariff to build certain transmission within its footprint. The FERC required that the opportunity to build such projects would extend to competitive transmission developers. Compliance with Order 1000 for SPS will occur through the SPP tariff.  SPP made its initial compliance filing to incorporate new provisions into its tariff regarding regional planning and cost allocation. The FERC’s ruling on the SPP compliance filing was issued in July 2013 as discussed below. Filings to address SPP interregional planning and cost allocation requirements with other regions were made in July 2013.

In July 2013, the FERC issued its initial order on SPP’s Order 1000 regional compliance filing identifying several issues and requiring a further compliance filing by SPP. The FERC rejected SPP’s proposal to retain a ROFR for new transmission projects with operational voltages between 100 KV and 300 KV. Requests for rehearing of the FERC’s July 2013 order were filed and are pending FERC action. The SPP regional compliance filing to the July 2013 order was filed and is pending FERC action. The SPP interregional compliance filing was submitted and is also pending the FERC’s action. SPS believes that Texas statutes protect the ROFR of incumbent utilities operating outside of the Electric Reliability Council of Texas (ERCOT) to construct and own transmission interconnected to their systems, though this view is disputed by some parties. The State of New Mexico does not have legislation protecting ROFR rights for incumbent utilities.

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Electric Operating Statistics

Electric Sales Statistics

	Year Ended Dec. 31
	2013			2012			2011
Electric sales (Millions of KWh)
Residential	3,564			3,542			3,700
Large commercial and industrial	9,893			9,707			9,546
Small commercial and industrial	4,743			4,708			4,778
Public authorities and other	568			575			615
Total retail	18,768			18,532			18,639
Sales for resale	9,200			9,281			11,324
Total energy sold	27,968			27,813			29,963
Number of customers at end of period
Residential	301,169			299,352			296,311
Large commercial and industrial	214			209			201
Small commercial and industrial	75,592			74,706			73,567
Public authorities and other	6,256			6,262			6,177
Total retail	383,231			380,529			376,256
Wholesale	30			31			27
Total customers	383,261			380,560			376,283
Electric revenues (Thousands of Dollars)
Residential	$	330,487		$	309,474		$	321,533
Large commercial and industrial	445,043			379,722			418,388
Small commercial and industrial	351,851			314,526			333,504
Public authorities and other	43,059			40,432			42,973
Total retail	1,170,440			1,044,154			1,116,398
Wholesale	416,793			408,491			511,316
Other electric revenues	119,854			87,410			79,851
Total electric revenues	$	1,707,087		$	1,540,055		$	1,707,565
KWh sales per retail customer	48,973			48,701			49,537
Revenue per retail customer	$	3,054		$	2,744		$	2,967
Residential revenue per KWh		9.27	¢		8.74	¢		8.69	¢
Large commercial and industrial revenue per KWh	4.50			3.91			4.38
Small commercial and industrial revenue per KWh	7.42			6.68			6.98
Total retail revenue per KWh	6.24			5.63			5.99
Wholesale revenue per KWh	4.53			4.40			4.52

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Energy Source Statistics

	Year Ended Dec. 31
	2013			2012			2011
	Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation
Coal	14,184	49	%	14,005	49	%	14,818	48	%
Natural Gas	11,235	38		12,088	43		13,167	43
Wind (a)	3,507	12		2,103	7		2,386	8
Other (b)	167	1		177	1		409	1
Total	29,093	100	%	28,373	100	%	30,780	100	%
Owned generation	18,814	65	%	19,940	70	%	19,310	63	%
Purchased generation	10,279	35		8,433	30		11,470	37
Total	29,093	100	%	28,373	100	%	30,780	100	%

^(a)  This category includes wind energy de-bundled from RECs and also includes Windsource RECs.  SPS uses RECs to meet or exceed state resource requirements and may sell surplus RECs.

^(b)  Includes energy from other sources, including nuclear, hydroelectric, solar, biomass, oil and refuse.  Distributed generation from the Solar*Rewards program is not included, and was approximately 0.011, 0.008, and 0.006 net million KWh for 2013, 2012, and 2011, respectively.

Natural Gas Facilities Used for Electric Generation

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

The Pipeline and Hazardous Materials Safety Administration

Pipeline Safety Act— The Pipeline Safety, Regulatory Certainty, and Job Creation Act, signed into law in January 2012 (Pipeline Safety Act) requires additional 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. The DOT Pipeline and Hazardous Materials Safety Administration (PHMSA) will require operators to re-confirm the maximum allowable operating pressure if records are inadequate. This process could cause temporary or permanent limitations on throughput for affected pipelines. In addition, the Pipeline Safety Act requires PHMSA to issue reports and develop new regulations including: requiring use of automatic or remote-controlled shut-off valves; requiring testing of certain previously untested transmission lines; and expanding integrity management requirements. The Pipeline Safety Act also raises the maximum penalty for violating pipeline safety rules to $2 million per day for related violations. While SPS cannot predict the ultimate impact Pipeline Safety Act will have on its costs, operations or financial results, it is taking actions that are intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective.

GENERAL

Seasonality

The demand for electric power is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer and winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, SPS’ operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. See Item 7 for further discussion.

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Competition

SPS remains a vertically integrated utility subject to traditional cost-of-service regulation. Within this construct, however, SPS is subject to different public policies that promote competition and the development of energy markets. SPS’ industrial and large commercial customers have the ability to own or operate facilities to generate their own electricity. In addition, customers may have the option of substituting other fuels, such as natural gas, steam or chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region. Customers also have the opportunity to supply their own power with on-site solar generation (typically rooftop solar) and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them.

The FERC has continued to promote competitive wholesale markets through open access transmission and other means. As a result, SPS can purchase generation resources from competing wholesale suppliers and use the transmission systems of Xcel Energy Inc.’s utility subsidiaries on a comparable basis to serve their native load. State public utilities commissions, including the NMPRC, have created resource planning programs that promote competition in the acquisition of electricity generation resources used to provide service to retail customers. In addition, FERC Order 1000 seeks to establish competition for construction and operation of new electric transmission facilities. SPS has franchise agreements with certain cities subject to periodic renewal. If a city elected not to renew the franchise agreement, it could seek alternative means for its citizens to access electric power or gas, such as municipalization. Several states, including New Mexico, have policies designed to promote the development of solar and other distributed energy resources through significant incentive policies; with these incentives and federal tax subsidies, distributed generating resources are potential competitors to SPS’ electric service business. These competitive challenges continue to evolve over time. While facing these challenges, SPS believes its rates and services are competitive with currently available alternatives. SPS continues to evaluate policies, products and strategies to enable it to compete in the changing energy marketplace.

ENVIRONMENTAL MATTERS

SPS’ facilities are regulated by federal and state environmental agencies. These agencies have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. SPS has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. SPS’ facilities have been designed and constructed to operate in compliance with applicable environmental standards. SPS strives to comply with all environmental regulations applicable to its operations. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or what effect future laws or regulations may have upon SPS’ operations. See Notes 10 and 11 to the financial statements for further discussion.

There are significant future environmental regulations under consideration to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change. While environmental regulations related to climate change and clean energy continue to evolve, SPS has undertaken a number of initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. Although the impact of these policies on SPS will depend on the specifics of state and federal policies, legislation, and regulation, we believe that, based on prior state commission practice, we would recover the cost of these initiatives through rates.

EMPLOYEES

As of Dec. 31, 2013, SPS had 1,277 full-time employees, of which 832 were covered under collective-bargaining agreements. See Note 7 to the financial statements for further discussion.

Item 1A — Risk Factors

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

There may be further risks and uncertainties that are not presently known or are not currently believed to be material that may adversely affect our performance or financial condition in the future.

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Oversight of Risk and Related Processes

The goal of Xcel Energy’s risk management process, which includes SPS, is to understand, manage and, when possible, mitigate material risk.  Management is responsible for identifying and managing risks, while the Board of Directors oversees and holds management accountable.  SPS is faced with a number of different types of risk.  Many of these risks are cross-cutting risks such that these risks are discussed and managed across business areas and coordinated by Xcel Energy Inc.’s and SPS’ senior management.  Our risk management process has three parts: identification and analysis, management and mitigation and communication and disclosure.

Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Management broadly considers our business, the utility industry, the domestic and global economy and the environment to identify risks. Identification and analysis occurs formally through a key risk assessment process conducted by senior management, the financial disclosure process, the hazard risk management process and internal auditing and compliance with financial and operational controls. Management also identifies and analyzes risk through its business planning process and development of goals and key performance indicators, which include risk identification to determine barriers to implementing our strategy. At the same time, the business planning process identifies areas in which there is a potential for a business area to take inappropriate risk to meet goals and determines how to prevent inappropriate risk-taking.

Management seeks to mitigate the risks inherent in the implementation of Xcel Energy Inc.’s and SPS’ strategy.  The process for risk mitigation includes adherence to our code of conduct and other compliance policies, operation of formal risk management structures and groups, and overall business management.  At a threshold level, we have developed a robust compliance program and promote a culture of compliance, including tone at the top, which mitigates risk.  Building on this culture of compliance, we manage and further mitigate risks through operation of formal risk management structures and groups, including management councils, risk committees and the services of corporate areas such as internal audit, the corporate controller and legal services.  While we have developed a number of formal structures for risk management, many material risks affect the business as a whole and are managed across business areas.

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

The guidelines on corporate governance and Board committee charters define the scope of review and inquiry for the Board and its committees. Each Board committee has responsibility for overseeing aspects of risk and our management and mitigation of the risk. Xcel Energy Inc.’s Board of Directors has overall responsibility for risk oversight and with the committees periodically undertakes the review of the charters to ensure that oversight of key risks are appropriately considered by the various Board committees.  Xcel Energy Inc.’s Board also reviews risks at an enterprise level and annually conducts a full day strategy session where it considers risks and confirms that Xcel Energy’s and SPS’ strategy appropriately addresses risk management and mitigation and reviews the performance and annual goals of each business area.

As described above, the Board reviews senior management’s key risk assessment that analyzes the most likely areas of future risk to Xcel Energy. This review, when combined with the oversight of specific risks by the committees, allows the Board to confirm risk is considered in the development of goals and that risk has been adequately considered and mitigated in the execution of corporate strategy. The presentation of the assessment of key risks also provides the basis for the discussion of risk in our public filings and securities disclosures.

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Risks Associated with Our Business

Environmental Risks

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

We are subject to environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. These laws and regulations require us to obtain and comply with a wide variety of environmental requirements including those for protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archaeological and historical resources), licenses, permits, inspections and other approvals. Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, install pollution control equipment at our facilities, clean up spills and other contamination and correct environmental hazards.  Environmental regulations may also lead to shutdown of existing facilities, either due to the difficulty in assuring compliance or that the costs of compliance no longer makes operation of the units economic. Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us. We may be required to pay all or a portion of the cost to remediate (i.e., cleanup) sites where our past activities, or the activities of certain other parties, caused environmental contamination.  At Dec. 31, 2013, these sites included third party sites, such as landfills, for which we are alleged to be a PRP that sent hazardous materials and wastes.

We are also subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings.  These mandates are designed in part to mitigate the potential environmental impacts of utility operations.  Failure to meet the requirements of these mandates may result in fines or penalties, which could have a material effect on our results of operations.  If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial position or cash flows.

In addition, existing environmental laws or regulations may be revised, and new laws or regulations seeking to protect the environment may be adopted or become applicable to us, including but not limited to, regulation of mercury, NOx, SO₂, CO₂, and other GHGs, particulates, coal ash and cooling water intake systems.  We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.

We are subject to physical and financial risks associated with climate change.

There is a growing consensus that emissions of GHGs are linked to global climate change.  Climate change creates physical and financial risk. Physical risks from climate change include an increase in sea level and changes in weather conditions, such as changes in precipitation and extreme weather events.  We do not serve any coastal communities so the possibility of sea level rises does not directly affect us or our customers.

Our customers’ energy needs vary with weather conditions, primarily temperature and humidity.  For residential customers, heating and cooling represent their largest energy use.  To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes.

Increased energy use due to weather changes may require us to invest in additional generating assets, transmission and other infrastructure to serve increased load.  Decreased energy use due to weather changes may affect our financial condition, through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions.  Weather conditions outside of our service territory could also have an impact on our revenues. We buy and sell electricity depending upon system needs and market opportunities.  Extreme weather conditions creating high energy demand on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers.

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

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

Financial Risks

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

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

Our profitability is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations.  We provide service at rates approved by one or more regulatory commissions.  These rates are generally regulated and based on an analysis of our costs incurred in a test year.  Thus, the rates we are allowed to charge may or may not match our costs at any given time.  While rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital, in a continued low interest rate environment there has been pressure pushing down ROE.  There can also be no assurance that the applicable regulatory commission will judge all of our costs to have been prudent or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs.  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.

Management currently believes these prudently incurred costs are recoverable given the existing regulatory mechanisms in place. However, adverse regulatory rulings or the imposition of additional regulations, including additional environmental or climate change regulation, could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including debt payments.

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

We cannot be assured that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency.  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.  For example, Standard & Poor’s calculates an imputed debt associated with capacity payments from purchased power contracts.  An increase in the overall level of capacity payments would increase the amount of imputed debt, based on Standard & Poor’s methodology.  Therefore, our credit ratings could be adversely affected based on the level of capacity payments associated with purchased power contracts or changes in how imputed debt is determined. Any downgrade could lead to higher borrowing costs. Also, we may enter into certain procurement and derivative contracts that require the posting of collateral or settlement of applicable contracts if credit ratings fall below investment grade.

We are subject to capital market and interest rate risks.

Utility operations require significant capital investment in property, plant and equipment; consequently, we are an active participant in debt and equity markets.  Any disruption in capital markets could have a material impact on our ability to fund our operations.  Capital markets are global in nature and are impacted by numerous issues and events throughout the world economy.  Capital market disruption events, and resulting broad financial market distress, could prevent us from issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates.

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

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We are subject to credit risks.

Credit risk includes the risk that our retail customers will not pay their bills, which may lead to a reduction in liquidity and an eventual increase in bad debt expense.  Retail 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 breach their obligations.  Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements.  In that event, our financial results could be adversely affected and we could incur losses.

One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges.  The credit risk is then socialized through the exchange central clearinghouse function.  While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which create an additional need for liquidity to post margin as exchange positions change value daily. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires broad clearing of financial swap transactions through a central counterparty, which could lead to additional margin requirements that would impact our liquidity: however, we have taken advantage of an exception to mandatory clearing afforded to commercial end-users who are not classified as a major swap participant.  The Board of Directors has authorized Xcel Energy and its subsidiaries to take advantage of this end-user exception. In addition, the CFTC has granted an increase in the de minimis level for swap transactions with defined utility special entities, generally entities owning or operating electric or natural gas facilities, from $25 million to $800 million.  Our current level of financial swap activity with special entities is significantly below this new threshold; therefore, we will not be classified as a swap dealer in our special entity activity.  Swap transactions with non special entities have a much higher level of activity considered to be de minimis, currently $8 billion, and our level of activity is well under this limit; therefore, we will not be classified as a swap dealer under the Dodd-Frank Act.  We are currently reporting all of our swap transactions as part of the Dodd-Frank Act.

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

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

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

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

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

Our self-insured costs of health care benefits for eligible employees and costs for retiree health care plans have increased substantially in recent years. Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our operating results, financial position and liquidity.  We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise.  Legislation related to health care could also significantly change our benefit programs and costs.

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Operational Risks

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

We engage in wholesale sales and/or purchases of electric capacity, energy and energy-related products as well as natural gas. As a result we are subject to market supply and commodity price risk.  Commodity price changes can affect the value of our commodity trading derivatives.  We mark certain derivatives to estimated fair market value on a daily basis (mark-to-market accounting), which may cause earnings volatility.  Actual settlements can vary significantly from these estimates, and significant changes from the assumptions underlying our fair value estimates could cause significant earnings variability.

If we encounter market supply shortages or our suppliers are otherwise unable to meet their contractual obligations, we may be unable to fulfill our contractual obligations customers at previously authorized or anticipated costs.  Any such disruption, if significant, would cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Any significantly higher energy or fuel costs relative to corresponding sales commitments would have a negative impact on our cash flows and could potentially result in economic losses.  Potential market supply shortages may not be fully resolved through alternative supply sources and such interruptions may cause short-term disruptions in our ability to provide electric services to our customers. The impact of these cost and reliability issues depends on our operating conditions such as generation fuels mix, availability of water for cooling, availability of fuel transportation, electric generation capacity, transmission, natural gas pipeline capacity, etc.

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

Our utility operations file long-term resource plans with our regulators.  These plans are based on numerous assumptions over the planning horizon such as: sales growth, customer usage patterns, economic activity, costs, regulatory mechanisms, impact of technology, the installation of distributed energy generation, customer behavioral response and continuation of the existing utility business model.  Given the uncertainty in these planning assumptions, there is a risk that the magnitude and timing of resource additions and demand may not coincide. SPS’ aging infrastructure may pose a risk to system reliability and expose us to premature financial obligations. SPS is engaged in significant and ongoing infrastructure investment programs.

In some of our state jurisdictions, large industrial customers may leave our system and invest in their own on-site distributed generation or seek law changes to give them the authority to purchase directly from other suppliers or organized markets.  The recent low natural gas price environment has caused some customers to consider their options in this area, particularly customers with industrial processes using steam.  Wholesale customers may purchase directly from other suppliers and procure only transmission service from us.  These circumstances provide for greater long-term planning uncertainty related to future load growth.  Similarly, distributed solar generation may become an economic competitive threat to our load growth in the future; however we believe the economics, absent significant subsidies, do not support such a trend in the near term unless a state mandates the purchase of such generation. Some states have considered such legislation.

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

Our natural gas transmission activities include a variety of inherent hazards and operating risks, such as leaks, explosions and mechanical problems, which could cause substantial financial losses.  In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us.  In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses.

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

Additionally, the operating or other costs that may be required in order to comply with potential new regulations, including the Pipeline Safety Act, could be significant. The Pipeline Safety Act requires additional verification of pipeline infrastructure records by intrastate and interstate pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. A significant incident could increase regulatory scrutiny and result in penalties and higher costs of operations.

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

If Xcel Energy Inc. were to become obligated to make payments under various guarantees and bond indemnities or to fund its other contingent liabilities, or if either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s credit rating below investment grade, Xcel Energy Inc. may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy part or potentially all of these exposures.  If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s debt securities below investment grade, it would increase Xcel Energy Inc.’s cost of capital and restrict its access to the capital markets. This could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends.  If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

As of Dec. 31, 2013, Xcel Energy Inc. and its utility subsidiaries had approximately $10.9 billion of long-term debt and $1.0 billion of short-term debt and current maturities.  Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.

Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters.  Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions.  The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees.  As of Dec. 31, 2013, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $19.4 million and $0.3 million of exposure. Xcel Energy also had additional guarantees of $32.1 million at Dec. 31, 2013 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 2013, 2012 and 2011 we paid $69.6 million, $66.6 million and $64.4 million of dividends to Xcel Energy Inc., respectively.  If Xcel Energy Inc.’s cash requirements increase, our board of directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs.  This could adversely affect our liquidity.  The most restrictive dividend limitation for SPS is imposed by its state regulatory commissions.  State regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy Inc., by requiring a minimum equity-to-total capitalization ratio. See Item 5 for further discussion on dividend limitations.

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Public Policy Risks

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

Increased public awareness and concern regarding climate change may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. Numerous states have announced or adopted programs to stabilize and reduce GHGs, and federal legislation has been introduced in both houses of Congress.  The U.S. continues to participate in international negotiations related to the United Nations Framework Convention on Climate Change.  Such legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk as our electric generating facilities may be subject to regulation under climate change laws at either the state or federal level in the future. The EPA is regulating GHGs under the CAA. The EPA has regulated GHG emissions from motor vehicles and adopted new permitting requirements for GHG emissions of new and modified large stationary sources, which are applicable to construction of new power plants or power plant modifications that increase emissions above a certain threshold. The EPA has proposed regulations that would establish NSPS for any new fossil fuel-fired power plants that may be built. If adopted, these regulations could significantly increase the cost of building new generating plants. By 2016, the EPA plans to develop and implement GHG regulations applicable to emissions from existing power plants. Such regulations could impose substantial costs on our system.

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

There are many uncertainties regarding when and in what form climate change legislation or regulations may be enacted.  The impact of legislation and regulations will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are recognized as compliance options, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas and coal prices. While we do not have operations outside of the U.S., any international treaties or accords could have an impact to the extent they lead to future federal or state regulations.  Another important factor is our ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed.  We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us.  If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations

We are also subject to a significant number of proposed and potential rules that will impact our coal-fired and other generation facilities. These include rules associated with emissions of SO₂ and NOx, mercury, regional haze, ozone, ash management and cooling water intake systems.  The costs of investment to comply with these rules could be substantial.  We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us.

Increased risks of regulatory penalties could negatively impact our business.

The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders.  The FERC can now impose penalties of $1 million per violation per day.  In addition, NERC electric reliability standards are now mandatory and subject to potential financial penalties by regional entities, the NERC or the FERC for violations.  If a serious reliability incident did occur, it could have a material effect on our operations or financial results.

The FERC issued NOVs of its market manipulation rules to several market participants during 2013.  The potential penalties in one pending case exceed $400 million.  We attempt to mitigate this risk through formal training on such prohibited practices and a compliance function that reviews our interaction with the markets under FERC and CFTC jurisdictions.  However, there is no guarantee our compliance program will be sufficient to ensure against violations.

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Macroeconomic Risks

Economic conditions could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged economic recession and uncertainty of recovery has lowered the correlation between sales and economic growth. Sales growth has been relatively flat due to lower level of economic activity, increased focus on energy efficiency and distributed generation. Instability in the financial markets also may affect the cost of capital and our ability to raise capital, which are discussed in greater detail in the capital market risk section above.

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

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

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

Our generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products.  Any such disruption could result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition and results of operations.  The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business.  We have already incurred increased costs for security and capital expenditures in response to these risks. In addition, we may experience additional capital and operating costs to implement security for our plants, such as additional physical plant security and additional security personnel.  We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection, and may experience additional capital and operating costs to comply with the NERC critical infrastructure protection standards as they are implemented and clarified.

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

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

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

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

We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure.  In addition, in the ordinary course of business, 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.

20

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

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

Rising energy prices could negatively impact our business.

Higher fuel costs could significantly impact our results of operations if requests for recovery are unsuccessful.  In addition, higher fuel costs could reduce customer demand and/or increase bad debt expense, which could also have a material impact on our results of operations. Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases could have an impact on our cash flows.  We are unable to predict future prices or the ultimate impact of such prices on our results of operations or cash flows.

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

Our electric utility business is seasonal, and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations, or cash flows.

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.

21

Electric Utility Generating Stations:
Station, Location and Unit	Fuel	Installed	Summer 2013 Net Dependable Capability (MW)
Steam:
Harrington-Amarillo, Texas, 3 Units	Coal	1976-1980	1,018
Tolk-Muleshoe, Texas, 2 Units	Coal	1982-1985	1,067
Cunningham-Hobbs, N.M., 2 Units	Natural Gas	1957-1965	254
Jones-Lubbock, Texas, 2 Units	Natural Gas	1971-1974	486
Maddox-Hobbs, N.M., 1 Unit	Natural Gas	1967	112
Nichols-Amarillo, Texas, 3 Units	Natural Gas	1960-1968	457
Plant X-Earth, Texas, 4 Units	Natural Gas	1952-1964	411
Combustion Turbine:
Carlsbad-Carlsbad, N.M., 1 Unit	Natural Gas	1968	10
Cunningham-Hobbs, N.M., 2 Units	Natural Gas	1998	212
Jones-Lubbock, Texas, 2 Units	Natural Gas	2011-2013	339	(a)
Maddox-Hobbs, N.M., 1 Unit	Natural Gas	1963-1976	61
		Total	4,427

^(a)  Construction of Jones Unit 3 was completed in 2011 and Jones Unit 4 was completed in May 2013.

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2013:

Conductor Miles
345 KV	6,806
230 KV	9,310
115 KV	12,380
Less than 115 KV	22,782

SPS had 429 electric utility transmission and distribution substations at Dec. 31, 2013.

Item 3 —Legal Proceedings

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

Additional Information

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

Item 4 — Mine Safety Disclosures

None.

22

PART II

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

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

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

• The most restrictive dividend limitation for SPS is imposed by its state regulatory commissions.  State regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy Inc., by requiring an equity-to-total capitalization ratio (excluding short-term debt) between 45.0 percent and 55.0 percent.  In addition, SPS may not pay a dividend that would cause it to lose its investment grade bond rating.  SPS’ equity-to-total capitalization ratio (excluding short-term debt) was 53.2 percent at Dec. 31, 2013 and $359 million in retained earnings was not restricted.

See Note 4 to the financial statements for further discussion of SPS’ dividend policy.

The dividends declared during 2013 and 2012 were as follows:

(Thousands of Dollars)	2013		2012
First quarter	$	17,113	$	16,777
Second quarter	17,475		16,399
Third quarter	18,218		16,520
Fourth quarter	18,083		16,773

Item 6 —Selected Financial Data

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

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

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

Financial Review

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

Ongoing electric revenues and ongoing electric margins are financial measures not recognized under GAAP. We use these non-GAAP financial measures to evaluate and provide details of earnings results. We believe that these non-GAAP measures are useful to investors to evaluate financial performance. These non-GAAP financial measures should not be considered as alternatives to measures calculated and reported in accordance with GAAP.

23

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” and similar expressions.  Actual results may vary materially.  Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date.  Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of SPS to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where SPS has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by SPS; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric market; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee work force factors; and the other risk factors listed from time to time by SPS in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K and Exhibit 99.01 hereto.

Results of Operations

SPS’ net income was approximately $95.2 million for 2013, compared with net income of approximately $106.4 million for 2012. The decrease is the result of two orders issued in August 2013 by the FERC for a potential SPS customer refund and higher depreciation expense. These decreases were partially offset by electric rate increases in Texas and the gain associated with the sale of certain transmission assets to Sharyland.

Electric Revenues and Margins

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

(Millions of Dollars)	2013			2012
Electric revenues	$	1,707		$	1,540
Electric fuel and purchased power	(1,059		)	(890		)
Electric margin	$	648		$	650

24

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

Electric Revenues

(Millions of Dollars)	2013 vs. 2012
Fuel and purchased power cost recovery	$	166
Retail rate increase (Texas)	30
Transmission revenue	12
Demand revenue	10
Trading	(20		)
2004 FERC complaint case orders (a)	(6		)
Firm wholesale	(3		)
Other, net	4
Total increase in ongoing electric revenues	193
2004 FERC complaint case orders (a)	(26		)
Total increase in GAAP electric revenues	$	167

Electric Margin

(Millions of Dollars)	2013 vs. 2012
Retail rate increase (Texas)	$	30
Demand revenue	10
2004 FERC complaint case orders (a)	(6		)
Trading	(3		)
Transmission revenue	(3		)
Firm wholesale	(3		)
Other, net	(1		)
Total increase in ongoing electric margin	24
2004 FERC complaint case orders (a)	(26		)
Total decrease in GAAP electric margin	$	(2	)

^(a)  As a result of two orders issued by the FERC in August 2013, a pretax charge of approximately $36 million ($32 million in electric revenues, of which $6 million relates to 2013 and $26 million relates to periods prior to 2013, and $4 million in interest charges) was recorded in 2013. See Note 10 to financial statements.

Non-Fuel Operating Expense and Other Items

O&M Expenses— O&M expenses increased $2.0 million, or 0.8 percent for 2013 compared with 2012.  The following summarizes the components of the changes for the year ended Dec. 31:

(Millions of Dollars)	2013 vs. 2012
Employee benefits	$	8
Plant generation costs	4
Distribution expense	2
Transmission costs	2
Gain on sale of transmission assets (See Note 10 to financial statements)	(14		)
Total increase in O&M expenses	$	2

Depreciation and Amortization — Depreciation and amortization expenses increased $8.2 million, or 7.2 percent for 2013 compared with 2012. The increase is primarily attributable to normal system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $3.3 million, or 7.1 percent for 2013 compared with 2012. The increase is primarily due to an increase in property taxes in Texas.

25

AFUDC, Equity and Debt — AFUDC increased $4.8 million for 2013 compared with 2012.  The increase was primarily due to the expansion of transmission facilities and normal system expansion.

Interest Charges — Interest charges increased $8.8 million, or 12.7 percent, for 2013 compared with 2012.  The increase was primarily due to interest associated with the customer refund based on the August 2013 FERC orders and higher long-term debt levels, which was partially offset by lower interest rates.

Income Taxes — Income tax expense decreased $8.5 million for 2013 compared with 2012. The decrease in income tax expense was primarily due to lower pretax earnings in 2013.  The ETR was 36.1 percent for 2013, compared with 36.9 percent for 2012.

Item 7A —Quantitativeand Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

In the normal course of business, SPS is exposed to a variety of market risks.  Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value of a particular instrument or commodity.  All financial and commodity-related instruments, including derivatives, are subject to market risk. See Note 9 to the financial statements for further discussion of market risks associated with derivatives.

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

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

Commodity Price Risk — SPS is exposed to commodity price risk in its electric operations.  Commodity price risk is managed by entering into 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 to the extent such exposure exists.

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.  SPS’ risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

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

At Dec. 31, 2013, a 100-basis-point change in the benchmark rate on SPS’ variable rate debt would impact pretax interest expense by approximately $1.2 million annually.  At Dec. 31, 2012, a 100-basis-point change in the benchmark rate on SPS’ variable rate debt would impact pretax interest expense by approximately $0.1 million annually.  See Note 9 to the financial statements for a discussion of SPS’ interest rate derivatives.

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

26

At Dec. 31, 2013, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $2.2 million, while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of $0.1 million.  At Dec. 31, 2012, a 10 percent increase in commodity prices would have resulted in a decrease in credit exposure of $0.1 million, while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of $0.1 million.

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

Fair Value Measurements

SPS follows accounting and disclosure guidance on fair value measurements that contains a hierarchy for inputs used in measuring fair value and requires disclosure of the observability of the inputs used in these measurements.  See Note 9 to the financial statements for further discussion of the fair value hierarchy and the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.

Commodity Derivatives — SPS continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts.  Given this assessment and the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, 2013.  SPS also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities.  The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair value of commodity derivative liabilities at Dec. 31, 2013.

Commodity derivative assets and liabilities assigned to Level 3 consist of FTRs. Determining the fair value of FTRs requires numerous management forecasts that vary in observability, including various forward commodity prices, retail and wholesale demand, generation and resulting transmission system congestion.  Given the limited observability of management’s forecasts for several of these inputs, these instruments have been assigned a Level 3.  Level 3 commodity derivatives assets and liabilities included $16.4 million and $6.5 million of estimated fair values, respectively, for FTRs held at Dec. 31, 2013.

Item 8 — Financial Statements and Supplementary Data

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

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

27

Management Report on Internal Controls Over Financial Reporting

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

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

SPS management assessed the effectiveness of SPS’ internal control over financial reporting as of Dec. 31, 2013. 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 (1992). Based on our assessment, we believe that, as of Dec. 31, 2013, SPS’ internal control over financial reporting is effective at the reasonable assurance level based on those criteria.

/s/ DAVID T. HUDSON	/s/ TERESA S. MADDEN
David T. Hudson	Teresa S. Madden
President, Chief Executive Officer and Director	Senior Vice President, Chief Financial Officer and Director
Feb. 24, 2014	Feb. 24, 2014

28

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Southwestern Public Service Company

We have audited the accompanying balance sheets and statements of capitalization of Southwestern Public Service Company (the “Company”) as of December 31, 2013 and 2012, and 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, 2013.  Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management.  Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Southwestern Public Service Company as of December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 24, 2014

29

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF INCOME

(amounts in thousands of dollars)

	Year Ended Dec. 31
	2013			2012			2011
Operating revenues	$	1,707,087		$	1,540,055		$	1,707,565
Operating expenses
Electric fuel and purchased power	1,059,330			889,567			1,089,415
Operating and maintenance expenses	253,880			251,853			251,886
Demand side management program expenses	12,420			12,891			15,415
Depreciation and amortization	121,907			113,743			106,974
Taxes (other than income taxes)	49,533			46,246			43,278
Total operating expenses	1,497,070			1,314,300			1,506,968
Operating income	210,017			225,755			200,597
Other income, net	140			46			406
Allowance for funds used during construction — equity	10,186			7,272			5,342
Interest charges and financing costs
Interest charges — includes other financing costs of $3,031, $2,996 and $2,964, respectively	77,866			69,074			65,095
Allowance for funds used during construction — debt	(6,461		)	(4,599		)	(3,784		)
Total interest charges and financing costs	71,405			64,475			61,311
Income before income taxes	148,938			168,598			145,034
Income taxes	53,761			62,229			55,133
Net income	$	95,177		$	106,369		$	89,901

See Notes to Financial Statements

30

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF COMPREHENSIVE INCOME

(amounts in thousands of dollars)

	Year Ended Dec. 31
	2013		2012		2011
Net income	$	95,177	$	106,369	$	89,901
Other comprehensive income
Derivative instruments:
Reclassification of losses to net income, net of tax of $97, $97 and $98, respectively	171		172		171
Other comprehensive income	171		172		171
Comprehensive income	$	95,348	$	106,541	$	90,072

See Notes to Financial Statements

31

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF CASH FLOWS

(amounts in thousands of dollars)

	Year Ended Dec. 31
	2013			2012			2011
Operating activities
Net income	$	95,177		$	106,369		$	89,901
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	124,069			115,917			109,207
Demand side management program amortization	1,673			1,811			1,811
Deferred income taxes	36,475			54,119			55,508
Amortization of investment tax credits	(341		)	(327		)	(275		)
Allowance for equity funds used during construction	(10,186		)	(7,272		)	(5,342		)
Provision for bad debts	3,437			2,915			3,655
Gain on sale of transmission assets	(13,661		)	—			—
Net derivative losses	268			269			268
Changes in operating assets and liabilities:
Accounts receivable	(36,184		)	(3,429		)	(23,518		)
Accrued unbilled revenues	(10,315		)	5,250			6,042
Inventories	(7,443		)	4,238			(5,726		)
Prepayments and other	4,456			(3,901		)	(2,480		)
Accounts payable	20,650			(13,730		)	(1,527		)
Net regulatory assets and liabilities	620			24,243			6,090
Other current liabilities	51,880			1,780			5,717
Pension and other employee benefit obligations	(17,968		)	(13,706		)	(7,576		)
Change in other noncurrent assets	(2,281		)	(1,541		)	1,509
Change in other noncurrent liabilities	(2,689		)	(1,912		)	(4,299		)
Net cash provided by operating activities	237,637			271,093			228,965
Investing activities
Utility capital/construction expenditures	(584,736		)	(384,626		)	(308,223		)
Proceeds from sale of transmission assets	37,118			—			—
Allowance for equity funds used during construction	10,186			7,272			5,342
Investments in utility money pool arrangement	(12,000		)	(217,000		)	(40,300		)
Receipts from utility money pool arrangement	12,000			217,000			40,300
Other, net	—			—			221
Net cash used in investing activities	(537,432		)	(377,354		)	(302,660		)
Financing activities
Proceeds from (repayment of) short-term borrowings, net	75,000			9,000			(49,000		)
Proceeds from issuance of long-term debt	94,626			108,678			193,137
Repayment of long-term debt	—			—			(101,800		)
Borrowings under utility money pool arrangement	767,000			265,000			293,500
Repayments under utility money pool arrangement	(729,000		)	(270,000		)	(288,500		)
Capital contributions from parent	162,277			60,024			89,631
Dividends paid to parent	(69,579		)	(66,609		)	(64,401		)
Net cash provided by financing activities	300,324			106,093			72,567
Net change in cash and cash equivalents	529			(168		)	(1,128		)
Cash and cash equivalents at beginning of year	482			650			1,778
Cash and cash equivalents at end of year	$	1,011		$	482		$	650
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(67,209	)	$	(61,268	)	$	(57,122	)
Cash paid for income taxes, net	(16,721		)	(13,763		)	(2,245		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	23,305		$	38,751		$	23,570

See Notes to Financial Statements

32

SOUTHWESTERN PUBLIC SERVICE CO.

BALANCE SHEETS

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

	Dec. 31
	2013			2012
Assets
Current assets
Cash and cash equivalents	$	1,011		$	482
Accounts receivable, net	70,951			62,067
Accounts receivable from affiliates	15,840			4,791
Accrued unbilled revenues	109,207			98,892
Inventories	37,138			31,337
Regulatory assets	27,595			24,020
Derivative instruments	17,826			7,892
Deferred income taxes	85,362			27,528
Prepayments and other	19,571			11,387
Total current assets	384,501			268,396
Property, plant and equipment, net	3,284,030			2,861,756
Other assets
Regulatory assets	290,415			324,081
Derivative instruments	41,056			48,949
Other	17,068			14,759
Total other assets	348,539			387,789
Total assets	$	4,017,070		$	3,517,941
Liabilities and Equity
Current liabilities
Short-term debt	$	84,000		$	9,000
Borrowings under utility money pool arrangement	38,000			—
Accounts payable	143,879			141,327
Accounts payable to affiliates	15,387			12,363
Regulatory liabilities	83,759			75,891
Taxes accrued	23,584			19,380
Accrued interest	16,883			15,104
Dividends payable	18,082			16,773
Derivative instruments	3,583			3,601
Other	75,355			31,084
Total current liabilities	502,512			324,523
Deferred credits and other liabilities
Deferred income taxes	757,778			662,201
Regulatory liabilities	81,504			91,815
Asset retirement obligations	19,375			17,607
Derivative instruments	34,207			37,790
Pension and employee benefit obligations	55,087			97,273
Other	3,051			6,093
Total deferred credits and other liabilities	951,002			912,779
Commitments and contingencies
Capitalization
Long-term debt	1,199,865			1,103,684
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2013 and 2012, respectively	—			—
Additional paid in capital	1,005,463			843,186
Retained earnings	359,389			335,101
Accumulated other comprehensive loss	(1,161		)	(1,332		)
Total common stockholder’s equity	1,363,691			1,176,955
Total liabilities and equity	$	4,017,070		$	3,517,941

See Notes to Financial Statements

33

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

(amounts in thousands of dollars, except share data)

	Common Stock Issued								Accumulated Other Comprehensive Income (Loss)			Total Common Stockholder’s Equity
	Shares	Par Value		Additional Paid In Capital		Retained Earnings
Balance at Dec. 31, 2010	100	$	—	$	693,531	$	270,257		$	(1,675	)	$	962,113
Net income						89,901						89,901
Other comprehensive income									171			171
Common dividends declared to parent						(64,957		)				(64,957		)
Contribution of capital by parent				89,631								89,631
Balance at Dec. 31, 2011	100	$	—	$	783,162	$	295,201		$	(1,504	)	$	1,076,859
Net income						106,369						106,369
Other comprehensive income									172			172
Common dividends declared to parent						(66,469		)				(66,469		)
Contribution of capital by parent				60,024								60,024
Balance at Dec. 31, 2012	100	$	—	$	843,186	$	335,101		$	(1,332	)	$	1,176,955
Net income						95,177						95,177
Other comprehensive income									171			171
Common dividends declared to parent						(70,889		)				(70,889		)
Contribution of capital by parent				162,277								162,277
Balance at Dec. 31, 2013	100	$	—	$	1,005,463	$	359,389		$	(1,161	)	$	1,363,691

See Notes to Financial Statements

34

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF CAPITALIZATION

(amounts in thousands of dollars, except share data)

	Dec. 31
	2013			2012
Long-Term Debt
First Mortgage Bonds, Series due Aug. 15, 2041, 4.5%	$	400,000		$	300,000
Unsecured Senior E Notes, due Oct. 1, 2016, 5.6%	200,000			200,000
Unsecured Senior G Notes, due Dec. 1, 2018, 8.75%	250,000			250,000
Unsecured Senior C and D Notes, due Oct. 1, 2033, 6%	100,000			100,000
Unsecured Senior F Notes, due Oct. 1, 2036, 6%	250,000			250,000
Unamortized (discount) premium	(135		)	3,684
Total	1,199,865			1,103,684
Less current maturities	—			—
Total long-term debt	$	1,199,865		$	1,103,684
Common Stockholder’s Equity
Common stock — 200 shares authorized of $1.00 par value, 100 shares outstanding at Dec. 31, 2013 and 2012, respectively	$	—		$	—
Additional paid in capital	1,005,463			843,186
Retained earnings	359,389			335,101
Accumulated other comprehensive loss	(1,161		)	(1,332		)
Total common stockholder’s equity	$	1,363,691		$	1,176,955

See Notes to Financial Statements

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NOTES TO FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Business and System of Accounts— SPS is principally engaged in the regulated generation, purchase, transmission, distribution and sale of electricity. SPS’ financial statements and disclosures are presented in accordance with GAAP.  All of SPS’ underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.

Variable Interest Entities— SPS evaluates its arrangements and contracts with other entities, including but not limited to, PPAs and fuel contracts to determine if the other party is a variable interest entity, if SPS has a variable interest and if SPS is the primary beneficiary. SPS follows accounting guidance for variable interest entities which requires consideration of the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether SPS is a variable interest entity’s primary beneficiary.  See Note 11 for further discussion of variable interest entities.

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

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

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

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

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

If restructuring or other changes in the regulatory environment occur, SPS may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from its balance sheet.  Such changes could have a material effect on SPS’ financial condition, results of operations and cash flows.  See Note 12 for further discussion of regulatory assets and liabilities.

Revenue Recognition— Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is recognized.  SPS presents its revenues net of any excise or other fiduciary-type taxes or fees.

SPS participates in SPP.  The revenues and charges from SPP related to serving retail and wholesale electric customers comprising the native load of SPS are recorded on a net basis within cost of sales.  Revenues and charges for short-term wholesale sales of excess energy transacted through SPP are recorded on a gross basis in electric revenues and cost of sales.

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

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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 process efficiency and lighting updates, as well as residential rebates for participation in air conditioner interruption and energy-efficient appliances.

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. For incentive programs designed to allow adjustments of future rates for recovery of lost margins and/or conservation performance incentives, recorded revenues are limited to those amounts expected to be collected within 24 months following the end of the annual period in which they are earned.  SPS recovers approved conservation program costs in base rate revenue or through a rider.

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

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. Recently completed property, plant and equipment that is disallowed for cost recovery is expensed in the current period. For investments in property, plant and equipment that are 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 on abandonment is recognized, if necessary.

SPS records depreciation expense related to its plant using the straight-line method over the plant’s useful life.  Actuarial and semi-actuarial life studies are performed on a periodic basis 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 2.6, 2.7 and 2.7 percent for the years ended Dec. 31, 2013, 2012 and 2011, respectively.

Leases — SPS evaluates a variety of contracts for lease classification at inception, including PPAs and rental arrangements for office space, vehicles, and equipment.  Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. See Note 11 for further discussion of leases.

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

AROs — SPS records future plant removal obligations as a liability at fair value with a corresponding increase to the carrying values of the related long-lived assets in accordance with the applicable accounting guidance.  This liability will be increased over time by applying the effective interest method of accretion to the liability and the capitalized costs will be depreciated over the useful life of the related long-lived assets.  The recording of the obligation for regulated operations has no income statement impact due to the deferral of the amounts through the establishment of a regulatory asset and recovery in rates.

SPS also recovers currently in rates certain future plant removal costs in addition to AROs and related capitalized costs, and a regulatory liability is recognized for such future expenditures.

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

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

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded due to the use of flow through accounting for rate making purposes, the reversal of some temporary differences are accounted for as current income tax expense. Investment tax credits are deferred and their benefits amortized over the book depreciable lives of the related property.  Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 12.

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

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

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

See Note 6 for further discussion of income taxes.

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

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

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

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

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

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

Commodity Trading Operations— All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in electric operating revenues in the statements of income.

Pursuant to the JOA approved by the FERC, some of the commodity trading margins from SPS are apportioned to NSP-Minnesota and PSCo. Commodity trading activities are not associated with energy produced from SPS’ generation assets or energy and capacity purchased to serve native load.  Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms.  See Note 9 for further discussion.

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 net asset values.  For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value.  For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract.  In the absence of a quoted price for an identical contract in an active market, SPS may use quoted prices for similar contracts or internally prepared valuation models to determine fair value.  See Note 9 for further discussion.

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

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

Inventory— All inventory is recorded at average cost.

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

When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost.  The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense.  As a result of certain state regulatory orders, SPS reduces recoverable fuel costs for the cost of certain RECs and records that cost as a regulatory asset when the amount is recoverable in future rates.  Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis.  The cost of these RECs, related transaction costs, and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.

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

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

Estimated remediation costs, excluding inflationary increases, are recorded.  The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation.  The recorded costs are regularly adjusted as estimates are revised and remediation proceeds.  If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for SPS’ expected share of the cost.  Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement.  The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs.  Removal costs recovered in rates are classified as a regulatory liability.

See Note 11 for further discussion of environmental costs.

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

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

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

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

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

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

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2013 up to the date of issuance of these financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.

2. Accounting Pronouncements

Recently Adopted

Balance Sheet Offsetting — In December 2011, the FASB issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements.  In January 2013, the FASB issued Balance Sheet (Topic 210) – Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU No. 2013-01) to clarify the specific instruments that should be considered in these disclosures.  These disclosure requirements do not affect the presentation of amounts in the balance sheets, and were effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods.  SPS implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its financial statements. See Note 9 for the required disclosures.

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Comprehensive Income Disclosures — In February 2013, the FASB issued Comprehensive Income (Topic 220) – Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (ASU No. 2013-02), which requires detailed disclosures regarding changes in components of accumulated OCI and amounts reclassified out of accumulated OCI.  These disclosure requirements do not change how net income or comprehensive income are presented in the financial statements.  These disclosure requirements were effective for annual reporting periods beginning on or after Dec. 15, 2012, and interim periods within those annual reporting periods.  SPS implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its financial statements.  See Note 13 for the required disclosures.

3. Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2013			Dec. 31, 2012
Accounts receivable, net
Accounts receivable	$	76,426		$	66,789
Less allowance for bad debts	(5,475		)	(4,722		)
	$	70,951		$	62,067

(Thousands of Dollars)	Dec. 31, 2013		Dec. 31, 2012
Inventories
Materials and supplies	$	21,600	$	18,129
Fuel	15,538		13,208
	$	37,138	$	31,337

(Thousands of Dollars)	Dec. 31, 2013			Dec. 31, 2012
Property, plant and equipment, net
Electric plant	$	4,714,398		$	4,379,208
Construction work in progress	388,323			237,136
Total property, plant and equipment	5,102,721			4,616,344
Less accumulated depreciation	(1,818,691		)	(1,754,588		)
	$	3,284,030		$	2,861,756

4. Borrowings and Other Financing Instruments

Short-Term Borrowings

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended Dec. 31, 2013
Borrowing limit	$	100
Amount outstanding at period end	38
Average amount outstanding	65
Maximum amount outstanding	100
Weighted average interest rate, computed on a daily basis	0.18		%
Weighted average interest rate at period end	0.25

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(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2013			Twelve Months Ended Dec. 31, 2012			Twelve Months Ended Dec. 31, 2011
Borrowing limit	$	100		$	100		$	100
Amount outstanding at period end	38			—			5
Average amount outstanding	46			10			12
Maximum amount outstanding	100			63			71
Weighted average interest rate, computed on a daily basis	0.15		%	0.33		%	0.35		%
Weighted average interest rate at end of period	0.25			N/A			0.35

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:

(Amounts in Millions, Except Interest Rates)	Three Months Ended Dec. 31, 2013
Borrowing limit	$	300
Amount outstanding at period end	84
Average amount outstanding	60
Maximum amount outstanding	121
Weighted average interest rate, computed on a daily basis	0.30		%
Weighted average interest rate at period end	0.27

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2013			Twelve Months Ended Dec. 31, 2012			Twelve Months Ended Dec. 31, 2011
Borrowing limit	$	300		$	300		$	300
Amount outstanding at period end	84			9			—
Average amount outstanding	32			18			54
Maximum amount outstanding	140			106			161
Weighted average interest rate, computed on a daily basis	0.30		%	0.39		%	0.37		%
Weighted average interest rate at end of period	0.27			0.36			N/A

Letters of Credit — SPS may use letters of credit, generally with terms of one-year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2013, there were $25.5 million of letters of credit outstanding under the credit facility. At Dec. 31, 2012, there were no letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

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

SPS has a five-year credit agreement with a syndicate of banks. The total size of the credit facility is $300 million and the credit facility terminates in July 2017.

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

Other features of SPS’ credit facility include:

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

• The credit facility has a financial covenant requiring that SPS’ debt-to-total capitalization ratio be less than or equal to 65 percent. SPS was in compliance as its debt-to-total capitalization ratio was 49 percent at Dec. 31, 2013. If SPS does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender.

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

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• The interest rates under the line of credit are based on Eurodollar borrowing margins ranging from 87.5 to 175 basis points per year based on the applicable long-term credit ratings.

• The commitment fees, also based on applicable long-term credit ratings, are calculated on the unused portion of the lines of credit at a range of 7.5 to 27.5 basis points per year.

At Dec. 31, 2013, SPS had the following committed credit facility available (in millions):

Credit Facility (a)		Drawn (b)		Available
$	300.0	$	109.5	$	190.5

^(a) Credit facility expires in July 2017.

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

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. SPS had no direct advances on the credit facility outstanding at Dec. 31, 2013 and 2012.

Long-Term Borrowings and Other Financing Instruments

Generally, all real and personal property of SPS is subject to the lien of its first mortgage indenture. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses associated with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines.

In August 2013, SPS issued $100 million of 4.50 percent first mortgage bonds due Aug. 15, 2041. Including the $300 million of this series previously issued, total principal outstanding for this series is $400 million. In June 2012, SPS issued an additional $100 million of its 4.50 percent first mortgage bonds due Aug. 15, 2041.

During the next five years, SPS has long-term debt maturities of $200 million and $250 million due in 2016 and 2018, respectively.

Deferred Financing Costs— Other assets included deferred financing costs of approximately $10.3 million and $9.7 million, net of amortization, at Dec. 31, 2013 and 2012, respectively.  SPS is amortizing these financing costs over the remaining maturity periods of the related debt.

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

The most restrictive dividend limitation for SPS is imposed by its state regulatory commissions. SPS’ state regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy Inc. by requiring an equity-to-total capitalization ratio (excluding short-term debt) between 45.0 percent and 55.0 percent. In addition, SPS may not pay a dividend that would cause it to lose its investment grade bond rating.  SPS’ equity-to-total capitalization ratio (excluding short-term debt) was 53.2 percent at Dec. 31, 2013 and $359 million in retained earnings was not restricted.

5. Preferred Stock

SPS has authorized the issuance of preferred stock.

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

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6. Income Taxes

Federal Audit — SPS is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return.  The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expired in September 2012.  The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in June 2015.  In the third quarter of 2012, the IRS commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of Dec. 31, 2013, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $10 million of income tax expense for the 2009 through 2011 claims and the anticipated claim for 2013.  SPS is not expected to accrue any income tax expense related to this adjustment.  Xcel Energy is continuing to work through the audit process, but the outcome and timing of a resolution are uncertain.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns.  As of Dec. 31, 2013, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2008. There are currently no state income tax audits in progress.

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

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

(Millions of Dollars)	Dec. 31, 2013		Dec. 31, 2012
Unrecognized tax benefit — Permanent tax positions	$	1.2	$	0.2
Unrecognized tax benefit — Temporary tax positions	2.9		3.7
Total unrecognized tax benefit	$	4.1	$	3.9

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

(Millions of Dollars)	2013			2012			2011
Balance at Jan. 1	$	3.9		$	4.8		$	4.3
Additions based on tax positions related to the current year	1.6			1.1			1.5
Reductions based on tax positions related to the current year	—			(1.6		)	(0.2		)
Additions for tax positions of prior years	3.1			0.8			2.5
Reductions for tax positions of prior years	(0.3		)	(1.2		)	(0.3		)
Settlements with taxing authorities	(4.2		)	—			(3.0		)
Balance at Dec. 31	$	4.1		$	3.9		$	4.8

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

(Millions of Dollars)	Dec. 31, 2013			Dec. 31, 2012
NOL and tax credit carryforwards	$	(2.4	)	$	(2.0	)

It is reasonably possible that SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume.  As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $2 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.  The payables for interest related to unrecognized tax benefits at Dec. 31, 2013, 2012 and 2011 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2013, 2012 or 2011.

Tangible Property Regulations — In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with the acquisition, production and improvement of tangible property. As SPS had adopted certain utility-specific guidance previously issued by the IRS, the issuance is not expected to have a material impact on its financial statements.

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

(Millions of Dollars)	2013	2012
Federal NOL carryforward	168.7	158.0
Federal tax credit carryforwards	1.7	1.3
State NOL carryforwards	23.6	21.0

The federal carryforward periods expire between 2021 and 2033.  The state carryforward periods expire between 2014 and 2031.

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.  The following reconciles such differences for the years ending Dec. 31:

	2013		2012		2011
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	2.0		2.2		2.9
Change in unrecognized tax benefits	0.7		—		—
Regulatory differences — utility plant items	(1.1	)	(0.4	)	(0.1	)
Tax credits recognized	(0.4	)	(0.2	)	(0.3	)
Other, net	(0.1	)	0.3		0.5
Effective income tax rate	36.1	%	36.9	%	38.0	%

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

(Thousands of Dollars)	2013			2012			2011
Current federal tax expense (benefit)	$	14,947		$	6,549		$	(1,993	)
Current state tax expense	2,943			2,712			3,287
Current change in unrecognized tax benefit	(263		)	(824		)	(1,394		)
Deferred federal tax expense	33,489			50,189			50,903
Deferred state tax expense	1,754			3,069			3,240
Deferred change in unrecognized tax expense	1,232			861			1,365
Deferred investment tax credits	(341		)	(327		)	(275		)
Total income tax expense	$	53,761		$	62,229		$	55,133

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

(Thousands of Dollars)	2013			2012			2011
Deferred tax expense excluding items below	$	38,333		$	55,749		$	56,181
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(1,761		)	(1,533		)	(575		)
Tax expense allocated to other comprehensive income	(97		)	(97		)	(98		)
Deferred tax expense	$	36,475		$	54,119		$	55,508

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The components of the net deferred tax liability (current and noncurrent) at Dec. 31 were as follows:

(Thousands of Dollars)	2013		2012
Deferred tax liabilities:
Differences between book and tax bases of property	$	705,416	$	654,259
Employee benefits	52,081		51,394
Other	30,066		24,034
Total deferred tax liabilities	$	787,563	$	729,687
Deferred tax assets:
NOL carryforward	$	61,330	$	59,562
Rate refund	17,192		2,911
Unbilled revenue - fuel costs	13,316		10,555
Regulatory liabilities	9,724		6,176
Deferred fuel costs	6,877		11,952
Other	6,708		4,448
Total deferred tax assets	$	115,147	$	95,604
Net deferred tax liability	$	672,416	$	634,083

7. Benefit Plans and Other Postretirement Benefits

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

Xcel Energy, which includes SPS, offers various benefit plans to its employees. Approximately 65 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2013, SPS had 832 bargaining employees covered under a collective-bargaining agreement, which expires in October 2014.

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

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

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

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

Specific valuation methods include the following:

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

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

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Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds, private equity investments and real estate investments are measured using net asset values, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value. The investments in commingled funds may be redeemed for net asset value with proper notice. Proper notice varies by fund and can range from daily with one or two days notice to annually with 90 days notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate investments may be redeemed with proper notice, which is typically quarterly with 45-90 days notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity. Based on the plan’s evaluation of its ability to redeem private equity and real estate investments, fair value measurements for private equity and real estate investments have been assigned a Level 3.

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

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

Pension Benefits

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

In addition to the qualified pension plans, Xcel Energy maintains a supplemental executive retirement plan (SERP) and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides unfunded, nonqualified benefits for compensation that is in excess of the limits applicable to the qualified pension plans. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2013 and 2012 were $36.5 million and $39.4 million, respectively, of which $2.8 million and $3.3 million were attributable to SPS. In 2013 and 2012, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $6.6 million and $15.6 million, respectively, of which $0.3 million and $0.3 million were attributable to SPS. Benefits for these unfunded plans are paid out of Xcel Energy’s consolidated operating cash flows.

Xcel Energy Inc. and SPS base the investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the historical returns achieved by the asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. The pension cost determination assumes a forecasted mix of investment types over the long-term. Investment returns were below the assumed levels of 6.49 percent in 2013 and above the assumed levels of 6.68 percent and 6.80 percent in 2012 and 2011, respectively. Xcel Energy Inc. and SPS continually review the pension assumptions. In 2014, SPS’ expected investment-return assumption is 6.90 percent.

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

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The following table presents the target pension asset allocations for SPS:

	2013		2012
Domestic and international equity securities	29	%	21	%
Long-duration fixed income and interest rate swap securities	36		50
Short-to-intermediate term fixed income securities	14		8
Alternative investments	19		19
Cash	2		2
Total	100	%	100	%

The ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios, and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. The aggregate projected asset allocation presented in the table above for the master pension trust results from the plan-specific strategies.

Pension Plan Assets

The following tables present, for each of the fair value hierarchy levels, SPS’ pension plan assets that are measured at fair value as of Dec. 31, 2013 and 2012:

	Dec. 31, 2013
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	17,354	$	—	$	—	$	17,354
Derivatives	—		4,200		—		4,200
Government securities	—		26,649		—		26,649
Corporate bonds	—		79,635		—		79,635
Asset-backed securities	—		889		—		889
Mortgage-backed securities	—		1,939		—		1,939
Common stock	12,813		—		—		12,813
Private equity investments	—		—		18,222		18,222
Commingled funds	—		223,322		—		223,322
Real estate	—		—		5,755		5,755
Securities lending collateral obligation and other	—		2,615		—		2,615
Total	$	30,167	$	339,249	$	23,977	$	393,393

	Dec. 31, 2012
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	26,765	$	—		$	—	$	26,765
Derivatives	—		1,388			—		1,388
Government securities	—		33,676			—		33,676
Corporate bonds	—		95,726			—		95,726
Asset-backed securities	—		—			1,755		1,755
Mortgage-backed securities	—		—			4,331		4,331
Common stock	7,762		—			—		7,762
Private equity investments	—		—			17,049		17,049
Commingled funds	—		183,957			—		183,957
Real estate	—		—			6,969		6,969
Securities lending collateral obligation and other	—		(3,240		)	—		(3,240		)
Total	$	34,527	$	311,507		$	30,104	$	376,138

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The following tables present the changes in SPS’ Level 3 pension plan assets for the years ended Dec. 31, 2013, 2012 and 2011:

(Thousands of Dollars)	Jan. 1, 2013		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3 (a)			Dec. 31, 2013
Asset-backed securities	$	1,755	$	—		$	—		$	—		$	(1,755	)	$	—
Mortgage-backed securities	4,331		—			—			—			(4,331		)	—
Private equity investments	17,049		2,630			(1,055		)	(402		)	—			18,222
Real estate	6,969		(322		)	1,475			1,128			(3,495		)	5,755
Total	$	30,104	$	2,308		$	420		$	726		$	(9,581	)	$	23,977

^(a) Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

(Thousands of Dollars)	Jan. 1, 2012		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3		Dec. 31, 2012
Asset-backed securities	$	4,018	$	531	$	(741	)	$	(2,053	)	$	—	$	1,755
Mortgage-backed securities	7,907		245		(265		)	(3,556		)	—		4,331
Private equity investments	16,159		1,886		(2,296		)	1,300			—		17,049
Real estate	3,586		2		551			2,830			—		6,969
Total	$	31,670	$	2,664	$	(2,751	)	$	(1,479	)	$	—	$	30,104

(Thousands of Dollars)	Jan. 1, 2011		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3		Dec. 31, 2011
Asset-backed securities	$	3,450	$	328		$	(355	)	$	595		$	—	$	4,018
Mortgage-backed securities	11,060		170			(865		)	(2,458		)	—		7,907
Private equity investments	11,464		401			1,300			2,994			—		16,159
Real estate	10,132		(61		)	3,131			(9,616		)	—		3,586
Total	$	36,106	$	838		$	3,211		$	(8,485	)	$	—	$	31,670

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

(Thousands of Dollars)	2013			2012
Accumulated Benefit Obligation at Dec. 31	$	402,509		$	416,808
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	454,184		$	403,367
Service cost	9,615			8,520
Interest cost	17,908			19,697
Plan amendments	—			98
Actuarial (gain) loss	(27,185		)	45,881
Transfer from other plan	3,625			—
Benefit payments	(23,840		)	(23,379		)
Obligation at Dec. 31	$	434,307		$	454,184

(Thousands of Dollars)	2013			2012
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	376,138		$	350,054
Actual return on plan assets	15,455			36,403
Employer contributions	22,015			13,060
Transfer from other plan	3,625			—
Benefit payments	(23,840		)	(23,379		)
Fair value of plan assets at Dec. 31	$	393,393		$	376,138

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(Thousands of Dollars)	2013			2012
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(40,914	)	$	(78,046	)

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

(Thousands of Dollars)	2013		2012
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	208,594	$	244,412
Prior service cost	93		963
Total	$	208,687	$	245,375

(Thousands of Dollars)	2013		2012
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	$	15,843	$	14,877
Noncurrent regulatory assets	192,844		230,498
Total	$	208,687	$	245,375

Measurement date Dec. 31, 2013 Dec. 31, 2012

	2013		2012
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.75	%	4.00	%
Expected average long-term increase in compensation level	3.75		3.75
Mortality table	RP 2000		RP 2000

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. These regulations did not require cash funding for 2008 through 2010 for Xcel Energy’s pension plans. Required contributions were made in 2011, 2012 and 2013 to meet minimum funding requirements.

The following are the pension funding contributions, both voluntary and required, made by Xcel Energy for 2011 through January 2014:

• In January 2014, contributions of $130.0 million were made across three of Xcel Energy’s pension plans, of which $4.4 million was attributable to SPS;

• In 2013, contributions of $192.4 million were made across four of Xcel Energy’s pension plans, of which $22.0 million was attributable to SPS;

• In 2012, contributions of $198.1 million were made across four of Xcel Energy’s pension plans, of which $13.1 million was attributable to SPS;

• In 2011, contributions of $137.3 million were made across three of Xcel Energy’s pension plans, of which $5.2 million was attributable to SPS;

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

Plan Amendments —Xcel Energy, which includes SPS, amended the plan in 2012 to allow a one time transfer of a portion of qualifying obligations from the nonqualified pension plan into the qualified pension plans. Xcel Energy and SPS also modified the benefit formula for nonbargaining and bargaining new hires beginning in 2012 to a reduced benefit level.

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

(Thousands of Dollars)	2013			2012			2011
Service cost	$	9,615		$	8,520		$	7,690
Interest cost	17,908			19,697			20,036
Expected return on plan assets	(23,970		)	(24,928		)	(26,316		)
Amortization of prior service cost	870			1,438			1,505
Amortization of net loss	17,148			12,897			9,046
Net periodic pension cost	$	21,571		$	17,624		$	11,961
Costs not recognized due to effects of regulation	(1,269		)	(4,300		)	(2,300		)
Net benefit cost recognized for financial reporting	$	20,302		$	13,324		$	9,661

	2013		2012		2011
Significant Assumptions Used to Measure Costs:
Discount rate	4.00	%	5.00	%	5.50	%
Expected average long-term increase in compensation level	3.75		4.00		4.00
Expected average long-term rate of return on assets	6.49		6.68		6.80

In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy Inc., costs are allocated to SPS based on Xcel Energy Services Inc. employees’ labor costs. Amounts allocated to SPS were $4.9 million, $4.1 million and $2.9 million in 2013, 2012 and 2011, respectively. Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2014 pension cost calculations is6.90 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy, including SPS, uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year. As these differences between actual investment returns and the expected investment returns are incorporated into the market-related value, the differences are recognized over the expected average remaining years of service for active employees.

Defined Contribution Plans

Xcel Energy, which includes SPS, maintains 401(k) and other defined contribution plans that cover substantially all employees. The expense to these plans for SPS was approximately $2.4 million in 2013, $2.3 million in 2012 and $2.0 million in 2011.

Postretirement Health Care Benefits

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

In 1993, Xcel Energy Inc. and SPS adopted accounting guidance regarding other non-pension postretirement benefits and elected to amortize the unrecognized APBO on a straight-line basis over 20 years.

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

Plan Assets — Certain state agencies that regulate Xcel Energy Inc.’s utility subsidiaries also have issued guidelines related to the funding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for Texas and New Mexico jurisdictional amounts collected in rates. Also, a portion of the assets contributed on behalf of nonbargaining retirees has been funded into a sub-account of the Xcel Energy pension plans. These assets are invested in a manner consistent with the investment strategy for the pension plan.

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Xcel Energy Inc. and SPS base investment-return assumptions for the postretirement health care fund assets on expected long-term performance for each of the investment types included in the asset portfolio. The assets are invested in a portfolio according to Xcel Energy Inc.’s and SPS’ return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected allocation of assets to selected asset classes, given the long-term risk, return, correlation and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by postretirement health care assets in any year.

The following tables present, for each of the fair value hierarchy levels, SPS’ postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2013 and 2012:

	Dec. 31, 2013
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	1,941	$	—		$	—	$	1,941
Derivatives	—		(38		)	—		(38		)
Government securities	—		5,549			—		5,549
Insurance contracts	—		5,016			—		5,016
Corporate bonds	—		4,926			—		4,926
Asset-backed securities	—		319			—		319
Mortgage-backed securities	—		2,303			—		2,303
Commingled funds	—		28,331			—		28,331
Other	—		(1,609		)	—		(1,609		)
Total	$	1,941	$	44,797		$	—	$	46,738

	Dec. 31, 2012
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	8,774	$	—		$	—	$	8,774
Government securities	—		7,061			—		7,061
Insurance contracts	—		4,807			—		4,807
Corporate bonds	—		4,211			—		4,211
Asset-backed securities	—		—			73		73
Mortgage-backed securities	—		—			3,841		3,841
Commingled funds	—		21,958			—		21,958
Other	—		(4,503		)	—		(4,503		)
Total	$	8,774	$	33,534		$	3,914	$	46,222

The following tables present the changes in SPS’ Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2013, 2012 and 2011:

(Thousands of Dollars)	Jan. 1, 2013		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)		Purchases, Issuances and Settlements, Net		Transfers Out of Level 3 (a)			Dec. 31, 2013
Asset-backed securities	$	73	$	—	$	—	$	—	$	(73	)	$	—
Mortgage-backed securities	3,841		—		—		—		(3,841		)	—
Total	$	3,914	$	—	$	—	$	—	$	(3,914	)	$	—

^(a) Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

(Thousands of Dollars)	Jan. 1, 2012		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)		Purchases, Issuances and Settlements, Net			Transfers Out of Level 3		Dec. 31, 2012
Asset-backed securities	$	730	$	(32	)	$	179	$	(804	)	$	—	$	73
Mortgage-backed securities	2,535		(70		)	377		999			—		3,841
Total	$	3,265	$	(102	)	$	556	$	195		$	—	$	3,914

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(Thousands of Dollars)	Jan. 1, 2011		Net Realized Gains (Losses)			Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net		Transfers Out of Level 3		Dec. 31, 2011
Asset-backed securities	$	245	$	(2	)	$	(101	)	$	588	$	—	$	730
Mortgage-backed securities	1,820		(157		)	194			678		—		2,535
Total	$	2,065	$	(159	)	$	93		$	1,266	$	—	$	3,265

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

(Thousands of Dollars)	2013			2012
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	59,260		$	55,165
Service cost	1,368			1,259
Interest cost	2,352			2,831
Medicare subsidy reimbursements	63			404
Plan amendments	—			(4,334		)
Plan participants’ contributions	698			2,004
Actuarial (gain) loss	(5,215		)	7,120
Benefit payments	(3,544		)	(5,189		)
Obligation at Dec. 31	$	54,982		$	59,260

(Thousands of Dollars)	2013			2012
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	46,222		$	39,679
Actual return on plan assets	3,228			5,375
Plan participants’ contributions	698			2,004
Employer contributions	134			4,353
Benefit payments	(3,544		)	(5,189		)
Fair value of plan assets at Dec. 31	$	46,738		$	46,222

(Thousands of Dollars)	2013			2012
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(8,244	)	$	(13,038	)

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

(Thousands of Dollars)	2013			2012
Amounts Not Yet Recognized as Components of Net Periodic Benefit Credit:
Net gain	$	(5,344	)	$	(90	)
Prior service credit	(3,833		)	(4,317		)
Transition obligations	—			—
Total	$	(9,177	)	$	(4,407	)

(Thousands of Dollars)	2013			2012
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory liabilities	$	(319	)	$	(954	)
Noncurrent regulatory liabilities	(8,858		)	(3,453		)
Total	$	(9,177	)	$	(4,407	)

Measurement date Dec. 31, 2013 Dec. 31, 2012

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	2013		2012
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.82	%	4.10	%
Mortality table	RP 2000		RP 2000
Health care costs trend rate — initial	7.00	%	7.50	%

Effective Jan. 1, 2014, the initial medical trend rate was decreased from 7.5 percent to 7.0 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is five years. Xcel Energy Inc. and SPS base the medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by the retiree medical plan.

A one-percent change in the assumed health care cost trend rate would have the following effects on SPS:

	One-Percentage Point
(Thousands of Dollars)	Increase		Decrease
APBO	$	5,684	$	(4,763	)
Service and interest components	368		(290		)

Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy, which includes SPS, contributed $17.6 million, $47.1 million and $49.0 million during 2013, 2012 and 2011, respectively, of which $0.1 million, $4.4 million and $3.6 million were attributable to SPS. Xcel Energy expects to contribute approximately $13.3 million during 2014, of which amounts attributable to SPS will be zero.

Plan Amendments — The 2012 decrease of the projected Xcel Energy and SPS postretirement health and welfare benefit obligation for plan amendments is due to the expected transition of certain participant groups to an external plan administrator.

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

(Thousands of Dollars)	2013			2012			2011
Service cost	$	1,368		$	1,259		$	1,092
Interest cost	2,352			2,831			2,722
Expected return on plan assets	(3,183		)	(2,701		)	(3,006		)
Amortization of transition obligation	—			1,545			1,669
Amortization of prior service credit	(484		)	(148		)	(51		)
Amortization of net (gain) loss	(6		)	1,256			855
Net periodic postretirement benefit cost	$	47		$	4,042		$	3,281

	2013		2012		2011
Significant Assumptions Used to Measure Costs:
Discount rate	4.10	%	5.00	%	5.50	%
Expected average long-term rate of return on assets	7.11		6.75		7.50

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

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Projected Benefit Payments — The following table lists SPS’ projected benefit payments for the pension and postretirement benefit plans:

(Thousands of Dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
2014	$	26,265	$	3,285	$	33	$	3,252
2015	27,361		3,450		36		3,414
2016	27,565		3,547		50		3,497
2017	28,738		3,691		52		3,639
2018	29,703		3,582		55		3,527
2019-2023	153,507		17,912		186		17,726

8. Other Income, Net

Other income, net for the years ended Dec. 31 consisted of the following:

(Thousands of Dollars)	2013			2012			2011
Interest income	$	663		$	379		$	506
Other nonoperating income	9			36			11
Insurance policy expense	(532		)	(369		)	(111		)
Other income, net	$	140		$	46		$	406

9. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

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

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

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

Specific valuation methods include the following:

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

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

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

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

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

Derivative Instruments Fair Value Measurements

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

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

At Dec. 31, 2013, accumulated other comprehensive losses related to interest rate derivatives included $0.2 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

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

Commodity Derivatives — SPS enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric utility operations, as well as for trading purposes.  This could include the purchase or sale of energy or energy-related products.  At Dec. 31, 2012, SPS held no commodity derivatives.

The following table details the gross notional amounts of commodity FTRs at Dec. 31, 2013:

(Amounts in Thousands)(a)(b)	Dec. 31, 2013
MWh of electricity	5,989

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

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Consideration of Credit Risk and Concentrations — SPS continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of SPS’ own credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets.

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

SPS’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities.  At Dec. 31, 2013, two of SPS’ 10 most significant counterparties for these activities, comprising $13.5 million or 18 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings.  Seven of the 10 most significant counterparties, comprising $37.4 million or 51 percent of this credit exposure, were not rated by these agencies, but based on SPS’ internal analysis, had credit quality consistent with investment grade. Another of these significant counterparties, comprising $3.3 million or 5 percent of this credit exposure, had credit quality less than investment grade, based on SPS’ internal analysis.  All 10 of these significant counterparties are municipal or cooperative electric entities, or other utilities.

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

(Thousands of Dollars)	2013			2012			2011
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(1,332	)	$	(1,504	)	$	(1,675	)
After-tax net realized losses on derivative transactions reclassified into earnings	171			172			171
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(1,161	)	$	(1,332	)	$	(1,504	)

Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were $0.3 million for each of the years ended Dec. 31, 2013, 2012 and 2011.

During the year ended Dec. 31, 2013, pre-tax net gains of $9.9 million of FTRs 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.

SPS had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2013, 2012 and 2011. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

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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:

	Dec. 31, 2013
	Fair Value
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting (b)			Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	16,420	$	16,420	$	(6,487	)	$	9,933
Total current derivative assets	$	—	$	—	$	16,420	$	16,420	$	(6,487	)	9,933
PPAs (a)												7,893
Current derivative instruments												$	17,826
Noncurrent derivative assets
PPAs (a)												$	41,056
Noncurrent derivative instruments												$	41,056
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	6,487	$	6,487	$	(6,487	)	$	—
Total current derivative liabilities	$	—	$	—	$	6,487	$	6,487	$	(6,487	)	—
PPAs (a)												3,583
Current derivative instruments												$	3,583
Noncurrent derivative liabilities
PPAs (a)												$	34,207
Noncurrent derivative instruments												$	34,207

^(a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, SPS qualified these contracts under the normal purchase exception.  Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b) SPS nets derivative instruments and related collateral in its consolidated 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, 2013.  At Dec. 31, 2013, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

At Dec. 31, 2012, derivative instruments presented on SPS’ balance sheets consist of amounts related to long-term purchased power agreements.

The following table presents the changes in Level 3 commodity derivatives for the year ended Dec. 31, 2013:

(Thousands of Dollars)	2013
Balance at Jan. 1	$	—
Purchases	9,933
Balance at Dec. 31	$	9,933

SPS recognizes transfers between levels as of the beginning of each period.  There were no transfers of amounts between levels for derivative instruments for the year ended Dec. 31, 2013.

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Fair Value of Long-Term Debt

As of Dec. 31, 2013 and 2012, other financial instruments for which the carrying amount did not equal fair value were as follows:

	2013				2012
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,199,865	$	1,307,035	$	1,103,684	$	1,327,538

The fair value of SPS’ long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities.  The fair value estimates are based on information available to management as of Dec. 31, 2013 and 2012, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

10. Rate Matters

Pending and Recently Concluded Regulatory Proceedings — PUCT

Texas 2014 Electric Rate Case — On Jan. 7, 2014, SPS filed a retail electric rate case in Texas with each of its Texas municipalities and the PUCT for a net increase in annual revenue of approximately $52.7 million, or 5.8 percent. The net increase reflects a base rate increase, revenue credits transferred from base rates to rate riders or the fuel clause, and resetting the TCRF to zero when the final base rates become effective, as shown in the following table:

(Millions of Dollars)	SPS Request
Base rate increase	$	81.5
Resetting TCRF	(12.9		)
Credit to customers for gain on sale to Lubbock moved to a rider	(4.9		)
Net increase in base revenue	63.7
Fuel clause offsets	(11.0		)
Retail customer net bill impact	$	52.7

The rate filing is based on a HTY ending June 2013, a requested ROE of 10.40 percent, an electric rate base of approximately $1.27 billion and an equity ratio of 53.89 percent. The requested rate increase reflects an increase in depreciation expense of approximately $16 million.

The PUCT has suspended SPS' proposed rates through Oct. 31, 2014. If the PUCT has not issued a final order by July 11, 2014, then SPS' current rates will not change, but the final rates will be made effective retroactive to July 12, 2014.

Next steps in the procedural schedule are as follows:

• Intervenor testimony — May 22, 2014;

• PUCT Staff testimony — May 29, 2014;

• Cross-rebuttal testimony — June 12, 2014;

• Rebuttal testimony — June 16, 2014;

• Evidentiary hearing — June 25, 2014; and

• A PUCT decision and implementation of final rates are anticipated in the third quarter of 2014.

Texas 2012 Electric Rate Case — In November 2012, SPS filed an electric rate case in Texas with the PUCT for an increase in annual revenue of approximately $90.2 million.  The rate filing is based on a historic 12 month test year ended June 30, 2012 (adjusted for known and measurable changes), a requested ROE of 10.65 percent, an electric rate base of $1.15 billion and an equity ratio of 52 percent. In June 2013, the PUCT approved a settlement agreement in which SPS’ base rate increased by $37 million, effective May 1, 2013 and by an additional $13.8 million on Sept. 1, 2013.

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Electric, Purchased Gas and Resource Adjustment Clauses

TCRF Rider — In November 2013, SPS filed with the PUCT to implement the TCRF for Texas retail customers. The requested increase in revenues is $13 million. The PUCT issued an order allowing the TCRF to go into effect on an interim basis effective Jan. 1, 2014.

Next steps in the procedural schedule are as follows:

• Intervenor testimony — April 17, 2014;

• Rebuttal testimony — May 6, 2014; and

• Evidentiary hearings — May 15 - May 16, 2014.

Pending Regulatory Proceedings — NMPRC

New Mexico 2014 Electric Rate Case — In December 2012, SPS filed an electric rate case in New Mexico with the NMPRC for an increase in annual revenue of approximately $45.9 million effective in 2014.  The rate filing is based on a 2014 forecast test year (FTY), a requested ROE of 10.65 percent, an electric rate base of $479.8 million and an equity ratio of 53.89 percent. In June 2013, SPS revised its requested rate increase to $43.3 million.

In August 2013, the NMPRC Staff (Staff), the NMAG, the Federal Executive Agencies, the Coalition of Clean Affordable Energy, Occidental Permian, Ltd. and New Mexico Gas Company filed testimony.

The following table summarizes certain parties’ recommendations from SPS’ revised request:

(Millions of Dollars)	Staff Testimony August 2013			NMAG Testimony August 2013
SPS revised request	$	43.3		$	43.3
Rate rider for renewable energy costs (a)	(14.5		)	(8.5		)
Present revenues (sales growth and weather)	(4.4		)	(6.4		)
ROE (9.8 percent and 8.63 percent, respectively)	(3.2		)	(8.1		)
Capital structure	(1.5		)	(1.1		)
Employee benefits	(2.8		)	(1.8		)
Reduced recovery for payroll expense	(0.1		)	(0.1		)
Gain on sale of transmission assets	—			(1.7		)
Fuel clause revenue	6.0			—
Other, net	(5.0		)	(6.6		)
Recommended rate increase	$	17.8		$	9.0
Means of recovery:
Base revenue	$	8.8		$	(6.0	)
Rider revenue	7.3			13.3
Fuel cost adjustment revenue	1.7			1.7
	$	17.8		$	9.0

^(a)  Adjustments represent recommended deferrals, extended amortizations and moving costs from rider to fuel in base rates.

In September 2013, SPS filed rebuttal testimony, revising its requested rate increase to $32.5 million, based on updated information and an ROE of 10.25 percent. This reflects a base and fuel increase of $20.9 million, an increase of rider revenue of $12.1 million and a decrease to other of $0.5 million.

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In January 2014, the hearing examiner released her recommended decision. SPS estimates the recommendation reduces the requested rate increase by approximately $6.2 million, resulting in a base revenue increase of $14.7 million. The recommendation proposes an ROE of 9.73 percent, an equity ratio of 53.89 percent, an FTY with certain adjustments and excludes certain employee benefits and other costs. In February 2014, the hearing examiner released a supplemental recommended decision proposing the approval of the requested $12.1 million renewable energy rider revenue recovery. Parties have filed exceptions to the hearing examiner’s recommendations. An NMPRC decision and final rates are expected to be effective in the second quarter of 2014.

Pending and Recently Concluded Regulatory Proceedings — FERC

2004 FERC Complaint Case Orders—In August 2013, the FERC issued an order on rehearing related to a 2004 Complaint case brought by Golden Spread Electric Cooperative, Inc. (Golden Spread), a wholesale cooperative customer, and PNM and an Order on Initial Decision in a subsequent 2006 rate case filed by SPS.

The original Complaint included two key components: 1) PNM’s claim regarding inappropriate allocation of fuel costs and 2) a base rate complaint, including the appropriate demand-related cost allocator. The FERC previously determined that the allocation of fuel costs and the demand-related cost allocator utilized by SPS was appropriate.

In the August 2013 Orders, the FERC clarified its previous ruling on the allocation of fuel costs and reaffirmed that the refunds in question should only apply to firm requirements customers and not PNM’s contractual load. The FERC also reversed its prior demand-related cost allocator decision. The FERC stated that it had erred in its initial analysis and concluded that the SPS system was a 3CP rather than a 12CP system.

The pre-tax impact to 2013 earnings from these orders is approximately $36 million. Pending the timing and resolution of this matter, the annual impact to revenues through 2014 could be up to $6 million and decreasing to $4 million on June 1, 2015.

In September 2013, SPS filed a request for rehearing of the FERC ruling on the CP allocation and refund decisions. SPS asserted that the FERC applied an improper burden of proof and that precedent did not support retroactive refunds. PNM also requested rehearing of the FERC decision not to reverse its prior ruling.

In October 2013, the FERC issued orders further considering the requests for rehearing. These matters are currently pending the FERC’s action. If unsuccessful in its rehearing request, SPS will have the opportunity to file rate cases with the FERC and its retail jurisdictions seeking to change all customers to a 3CP allocation method.

Wholesale Rate Complaint — In April 2012, Golden Spread filed a rate complaint alleging that the base ROE included in the SPS production formula rate of 10.25 percent, and the SPS transmission base formula rate ROE of 10.77 percent, are unjust and unreasonable. Golden Spread alleged that the appropriate base ROE is 9.15 percent, or an annual difference of approximately $3.3 million. An additional 50 basis point incentive is added to the base ROE for the transmission formula rate for SPS’ participation in the SPP RTO. Golden Spread is not contesting this transmission incentive.  The FERC has taken no action on this complaint. If granted, the complaint could reduce SPS revenues approximately $3.1 million per year prospectively from the effective date established by the FERC.

Sale of Texas Transmission Assets — In March 2013, SPS reached an agreement to sell certain segments of SPS’ transmission lines and two related substations to Sharyland. In 2013, SPS received all necessary regulatory approvals for the transaction. On Dec. 30, 2013, SPS received $37.1 million and recognized a pre-tax gain of $13.6 million. The gain is reflected in the statement of income as a reduction to O&M expenses. Regulatory liabilities were recorded for jurisdictional gain sharing of $7.2 million.

11. Commitments and Contingencies

Commitments

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

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Southeast New Mexico Transmission Development — SPS is developing a transmission expansion plan for southeastern New Mexico. The SPP, with input from SPS, is conducting a High Priority Incremental Load Study to review oil and natural gas load additions in several areas, including southeastern New Mexico. A final report is expected by SPP in April 2014. SPS has started right-of-way work on four projects for which NTCs are anticipated from SPP in early 2014.

Transmission NTC— SPS has accepted NTCs for several hundred miles of transmission line and related substation projects based on needs identified through SPP’s various planning processes, including those associated with economics, reliability, generator interconnection or the load addition processes. A major project committed to is the TUCO to Woodward District Extra High Voltage Interchange, a 345 KV transmission line. This line connects the TUCO substation near Lubbock, Texas with the OGE substation in Woodward, Okla. The PUCT approved SPS’ CCN to build the line in 2012. It is anticipated to be complete in 2014.

Fuel Contracts— SPS has entered into various long-term commitments for the purchase and delivery of a significant portion of its current coal and natural gas requirements.  These contracts expire in various years between 2014 and 2033.  SPS is required to pay additional amounts depending on actual quantities shipped under these agreements.  

The estimated minimum purchases for SPS under these contracts as of Dec. 31, 2013, are as follows:

(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2014	$	273.8	$	20.6	$	23.7
2015	241.5		—		22.1
2016	143.8		—		22.1
2017	36.7		—		21.3
2018	—		—		15.9
Thereafter	—		—		96.1
Total	$	695.8	$	20.6	$	201.2

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

PPAs— SPS has entered into PPAs with other utilities and energy suppliers with expiration dates through 2024 for purchased power to meet system load and energy requirements and meet operating reserve obligations. In general, these contracts provide for energy payments, based on actual energy delivered and capacity payments. Capacity payments are typically contingent on the independent power producing entity meeting certain contract obligations, including plant availability requirements.  Certain contractual payments are adjusted based on market indices. The effects of price adjustments on our financial results are mitigated through purchased energy cost recovery mechanisms.

Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts, were payments for capacity of $38.4 million, $36.2 million and $39.7 million in 2013, 2012 and 2011, respectively. At Dec. 31, 2013, the estimated future payments for capacity that SPS is obligated to purchase pursuant to these executory contracts, subject to availability, are as follows:

(Millions of Dollars)
2014	$	52.3
2015	56.5
2016	57.0
2017	58.2
2018	57.2
Thereafter	72.2
Total (a)	$	353.4

^(a)  Excludes contingent energy payments for renewable energy PPAs.

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

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Leases— SPS leases a variety of equipment and facilities used in the normal course of business. These leases, primarily for office space, generating facilities, trucks, aircraft, cars and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations were approximately $64.2 million, $59.9 million and $58.8 million for 2013, 2012 and 2011, respectively. These expenses included capacity payments for PPAs accounted for as operating leases of $59.0 million, $56.0 million and $54.4 million in 2013, 2012 and 2011, respectively, recorded to electric fuel and purchased power expenses.

Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases in accordance with the applicable accounting guidance.  Future commitments under operating leases are:

	Operating		PPA		Total Operating
(Millions of Dollars)	Leases		Operating Leases (a) (b)		Leases
2014	$	3.1	$	58.3	$	61.4
2015	3.2		49.9		53.1
2016	3.2		49.9		53.1
2017	2.3		49.9		52.2
2018	1.9		49.9		51.8
Thereafter	12.7		734.1		746.8

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

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

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

PPAs — Under certain PPAs, SPS purchases power from independent power producing entities for which SPS is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which SPS procures the natural gas required to produce the energy that it purchases. These specific PPAs create a variable interest in the associated independent power producing entity.

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

SPS has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities. SPS has concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. SPS had approximately 827 MW of capacity under long-term PPAs as of Dec. 31, 2013 and 2012, with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2033.

Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk electric generating stations from TUCO under contracts for those facilities that expire in 2016 and 2017, respectively. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing, and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.

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

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Indemnification Agreements

In connection with the sale of certain Texas electric transmission assets to Sharyland, SPS agreed to indemnify the purchaser for losses arising out of any breach of the representations, warranties and covenants under the related asset purchase agreement and for losses arising out of certain other matters, including pre-closing liabilities. SPS’ indemnification obligation is capped at $37.1 million, in the aggregate. The indemnification provisions for most representations and warranties expire in December 2014. The remaining representations and warranties, which relate to due organization and transaction authorization, survive indefinitely. SPS has recorded a $0.4 million liability related to this indemnity.

Environmental Contingencies

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

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

Environmental Requirements

Water and waste

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

Federal Clean Water Act Effluent Limitations Guidelines (ELG) — In June 2013, the EPA published a proposed ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. Refuse derived fuel, biomass and other alternatively fueled power plants are not addressed by the proposed revisions. The proposed rule identifies four potential regulatory options and invites comments on those regulatory approaches. The options differ in the number of waste streams covered, size of the units controlled and stringency of controls. It is not yet known when the EPA will issue a finalized rule. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017 but no later than July 2022. The impact of this rule on SPS is uncertain at this time.

Proposed Coal Ash Regulation — SPS’ operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of hazardous waste. In 2010, the EPA published a proposed rule on whether to regulate coal combustion byproducts (coal ash) as hazardous or nonhazardous waste. Coal ash is currently exempt from hazardous waste regulation. SPS’ costs for the management and disposal of coal ash would significantly increase and the beneficial reuse of coal ash would be negatively impacted if the EPA ultimately issues a rule under which coal ash is regulated as hazardous waste. The EPA has entered into a consent decree to act on final regulations by December 2014. The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.

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Air

EPA GHG Regulation — In 2009, the EPA issued its “endangerment” finding that GHG emissions pose a threat to public health and welfare. This finding required the EPA to adopt GHG emission standards for mobile sources. In 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold. These rules were upheld on appeal to the D.C. Circuit. The U.S. Supreme Court has granted review on one issue related to these rules, specifically whether the EPA’s regulation of GHG emissions from mobile sources triggered, by operation of law, new source review permitting requirements for stationary sources, which was the EPA’s basis for adopting the 2011 permitting rules. The Court is scheduled to hear arguments in February 2014. A ruling is anticipated by June 2014. SPS is unable to determine the cost of compliance with these new EPA requirements as it is not clear whether these requirements will apply to future changes at SPS’ power plants.

GHG Emission Standard for Existing Sources and NSPS Proposal — In June 2013, President Obama issued a memorandum directing the EPA to develop GHG emission standards for existing power plants. The memorandum anticipates the EPA will issue a proposed GHG emission standard for existing power plants in June 2014. It is not possible to evaluate the impact of existing source standards until the upcoming proposal and final requirements are known.

In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which seeks to establish CO₂ emission rates for coal-fired power plants that reflect emission reductions using partial carbon capture and storage technology (CCS). The EPA’s proposed CO₂ emission limits for gas-fired power plants reflect emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.

CSAPR — In 2011, the EPA issued the CSAPR to address long range transport of PM and ozone by requiring reductions in SO₂ and NOx from utilities in the eastern half of the United States, including Texas. The CSAPR would have set more stringent requirements than the proposed Clean Air Transport Rule and would have required plants in Texas to reduce their SO₂ and annual NOx emissions. The rule also would have created an emissions trading program.

In August 2012, the D.C. Circuit vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated that the EPA must continue administering the CAIR pending adoption of a valid replacement. In December 2013, the U.S. Supreme Court heard oral arguments on the D.C. Circuit’s 2012 decision to vacate the CSAPR. A decision is anticipated by June 2014. It is not yet known whether the D.C. Circuit’s decision will be upheld, or how the EPA might approach a replacement rule. Therefore, it is not known what requirements may be imposed in the future.

As the EPA continues administering the CAIR while the CSAPR or a replacement rule is pending, SPS expects to comply with the CAIR as described below.

CAIR — In 2005, the EPA issued the CAIR to further regulate SO₂ and NOx emissions. Under the CAIR’s cap and trade structure, companies can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems. In the SPS region, installation of low-NOx combustion control technology was completed in 2012 on Tolk Unit 1. SPS plans to install the same combustion control technology on Tolk Unit 2 in the second quarter of 2014. These installations will reduce or eliminate SPS’ need to purchase NOx emission allowances. SPS had sufficient SO₂ allowances to comply with the CAIR in 2013 and has sufficient allowances for 2014. At Dec. 31, 2013, the estimated annual CAIR NOx allowance cost for SPS did not have a material impact on the results of operations, financial position or cash flows.

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. SPS expects to comply with the EGU MATS rule through a combination of mercury and other emission control projects. SPS believes EGU MATS costs will be recoverable through regulatory mechanisms and does not expect a material impact on results of operations, financial position or cash flows.

Regional Haze Rules — In 2005, the EPA amended the BART requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. In its first regional haze SIP, Texas identified the SPS facilities that will have to reduce SO₂, NOx and PM emissions under BART and then set emissions limits for those facilities.

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Harrington Units 1 and 2 are potentially subject to BART. Texas has developed a SIP that finds the CAIR equal to BART for EGUs. As a result, no additional controls beyond CAIR compliance would be required. In May 2012, the EPA deferred its review of the SIP in its final rule allowing states to find that CSAPR compliance meets BART requirements for EGUs. It is not yet known how the U.S. Supreme Court’s review of the CSAPR may impact the EPA’s approval of the SIP.

Revisions to National Ambient Air Quality Standards (NAAQS) for PM — In December 2012, the EPA lowered the primary health-based NAAQS for annual average fine PM and retained the current daily standard for fine PM. In areas where SPS operates power plants, current monitored air concentrations are below the level of the final annual primary standard. The EPA is expected to designate non-compliant locations by December 2014. States would then study the sources of the nonattainment and make emission reduction plans to attain the standards. It is not possible to evaluate the impact of this regulation further until the final designations have been made.

Asset Retirement Obligations

Recorded AROs— AROs have been recorded for property related to the following: electric steam production, electric distribution and transmission, and general property.  The electric production obligations include asbestos, ash containment facilities, storage tanks and control panels.  The asbestos recognition associated with the steam production includes certain plants. This asbestos abatement removal obligation originated in 1973 with the CAA applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal.  The AROs also have been recorded for SPS steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills and the AROs origination dates on the ARO recognition for ash-containment facilities at steam plants were the in-service dates of the various facilities.

An ARO was recognized for the removal of electric transmission and distribution equipment at SPS, which consists of many small potential obligations associated with PCBs, mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps. The electric general AROs include small obligations related to storage tanks, radiation sources and office buildings. These assets have numerous in-service dates for which it is difficult to assign the obligation to a particular year. Therefore, the obligation was measured using an average service life.

A reconciliation of SPS’ AROs is shown in the tables below for the years ended Dec. 31, 2013 and 2012:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2013		Liabilities Settled			Accretion		Revisions to Prior Estimates			Ending Balance Dec. 31, 2013
Electric plant
Steam production asbestos	$	10,979	$	(118	)	$	747	$	—		$	11,608
Steam production ash containment	764		—			48		(3		)	809
Electric distribution	5,303		—			171		630			6,104
Other	561		—			42		251			854
Total liability	$	17,607	$	(118	)	$	1,008	$	878		$	19,375

(Thousands of Dollars)	Beginning Balance Jan. 1, 2012		Liabilities Settled		Accretion		Revisions to Prior Estimates			Ending Balance Dec. 31, 2012
Electric plant
Steam production asbestos	$	20,803	$	—	$	1,422	$	(11,246	)	$	10,979
Steam production ash containment	719		—		45		—			764
Electric distribution	5,202		—		188		(87		)	5,303
Other	542		—		20		(1		)	561
Total liability	$	27,266	$	—	$	1,675	$	(11,334	)	$	17,607

In 2013, SPS revised ash containment facilities, miscellaneous electric production, electric transmission and distribution and electric general AROs due to revised estimated cash flows. Additionally, in 2013, an ARO was settled for the asbestos abatement at the Riverview generating facility. In 2012, SPS revised asbestos and electric transmission and distribution AROs due to revised estimated cash flows.

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Removal Costs— SPS records a regulatory liability for the plant removal costs of steam and other generation, transmission and distribution facilities.  Generally, the accrual of future non-ARO removal obligations is not required.  However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates.  These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities.  Given the long time periods over which the amounts were accrued and the changing of rates over time, SPS has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates.  Accordingly, the recorded amounts of estimated future removal costs are considered regulatory liabilities. Removal costs as of Dec. 31, 2013 and 2012, were $53 million and $67 million, respectively.

Legal Contingencies

SPS is involved in various litigation matters that are being defended and handled in the ordinary course of business.  The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events.  Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation.  Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.  In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.  For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on SPS’ financial statements.  Unless otherwise required by GAAP, legal fees are expensed as incurred.

Employment, Tort and Commercial Litigation

Exelon Wind (formerly John Deere Wind) Complaint—Several lawsuits in Texas state and federal courts and regulatory proceedings have arisen out of a dispute concerning SPS’ payments for energy and capacity produced from the Exelon Wind subsidiaries’ projects. There are two main areas of dispute.  First, Exelon Wind claims that it established legally enforceable obligations (LEOs) for each of its 12 wind facilities in 2005 through 2008 that require SPS to buy power based on SPS’ forecasted avoided cost as determined in 2005 through 2008.  Although SPS has refused to accept Exelon Wind’s LEOs, SPS accepts that it must take energy from Exelon Wind under SPS’ PUCT-approved QF Tariff.  Second, Exelon Wind has raised various challenges to SPS’ PUCT-approved QF Tariff, which became effective in August 2010. The state and federal lawsuits and regulatory proceedings are in various stages of litigation, including a pending appeal by SPS in the Fifth Circuit Court of Appeals. SPS believes the likelihood of loss in these lawsuits and proceedings is remote based primarily on existing case law and while it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome, SPS believes such loss would not be material based upon its belief that it would be permitted to recover such costs, if needed, through its various fuel clause mechanisms. No accrual has been recorded for this matter.

Other Contingencies

See Note 10 for further discussion.

12. Regulatory Assets and Liabilities

SPS’ financial statements are prepared in accordance with the applicable accounting guidance, as discussed in Note 1.  Under this guidance, regulatory assets and liabilities are created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric rates.  If changes in the utility industry or the business of SPS no longer allow for the application of regulatory accounting guidance under GAAP, SPS would be required to recognize the write-off of regulatory assets and liabilities in net income or OCI.

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The components of regulatory assets shown on the balance sheets of SPS at Dec. 31, 2013 and 2012 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2013				Dec. 31, 2012
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations (a)	7	Various	$	17,382	$	200,158	$	15,038	$	238,398
Recoverable deferred taxes on AFUDC recorded in plant	1	Plant lives	—		31,362		—		27,591
Net AROs (b)	11	Plant lives	—		21,382		—		21,714
Conservation programs (c)	1	One to six years	1,951		7,753		1,735		9,095
Renewable resources and environmental initiatives	11	One to four years	3,428		17,671		4,094		15,101
Losses on reacquired debt	4	Term of related debt	1,225		3,697		1,225		4,922
Deferred income tax adjustment	1, 6	Typically plant lives	—		3,375		—		4,859
Recoverable electric energy costs	1	Less than one year	491		—		873		—
Other		Various	3,118		5,017		1,055		2,401
Total regulatory assets			$	27,595	$	290,415	$	24,020	$	324,081

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

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

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

The components of regulatory liabilities shown on the balance sheets of SPS at Dec. Dec. 31, 2013 and 2012 are:

(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2013				Dec. 31, 2012
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Plant removal costs	11	Plant lives	$	—	$	53,006	$	—	$	66,575
Deferred electric energy costs	1	Less than one year	55,395		—		61,874		—
Contract valuation adjustments (a)	1, 9	Term of related contract	14,243		6,849		4,292		11,159
Gain from asset sales	10	Various	11,172		4,201		4,903		8,272
Conservation programs (b)	1	Less than one year	1,465		—		1,875		—
Other		Various	1,484		17,448		2,947		5,809
Total regulatory liabilities			$	83,759	$	81,504	$	75,891	$	91,815

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

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

At Dec. 31, 2013 and 2012, approximately $30 million and $25 million of SPS’ regulatory assets represented past expenditures not currently earning a return, respectively.  This amount primarily includes certain expenditures associated with renewable resources and environmental initiatives.

13. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the year ended Dec. 31, 2013 were as follows:

(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at Jan. 1	$	(1,332	)
Losses reclassified from net accumulated other comprehensive loss	171
Net current period OCI	171
Accumulated other comprehensive loss at Dec. 31	$	(1,161	)

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Reclassifications from accumulated other comprehensive loss for the year ended Dec. 31, 2013 were as follows:

(Thousands of Dollars)	Amounts Reclassified from Accumulated Other Comprehensive Loss
Losses on cash flow hedges:
Interest rate derivatives	$	268		(a)
Total, pre-tax	268
Tax benefit	(97		)
Total amounts reclassified, net of tax	$	171

^(a)  Included in interest charges.

14. Related Party Transactions

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

Xcel Energy Inc., NSP-Minnesota, PSCo and SPS have established a utility money pool arrangement with the utility subsidiaries. See Note 4 for further discussion of this borrowing arrangement.

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

(Thousands of Dollars)	2013		2012		2011
Operating revenues:
Electric	$	1,331	$	6,539	$	7,187
Operating expenses:
Purchased power	8,136		9,271		10,896
Other operating expenses — paid to Xcel Energy Services Inc.	127,669		117,277		118,370
Interest expense	178		76		83
Interest income	—		10		1

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

	2013				2012
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	3,462	$	—	$	3,820	$	—
NSP-Wisconsin	—		26		4		—
PSCo	—		1,056		—		69
Other subsidiaries of Xcel Energy Inc.	12,378		14,305		967		12,294
	$	15,840	$	15,387	$	4,791	$	12,363

15. Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2013		June 30, 2013		Sept. 30, 2013		Dec. 31, 2013
Operating revenues	$	374,257	$	461,831	$	481,407	$	389,592
Operating income	33,059		58,469		74,653		43,836
Net income	12,584		28,206		35,037		19,350

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	Quarter Ended
(Thousands of Dollars)	March 31, 2012		June 30, 2012		Sept. 30, 2012		Dec. 31, 2012
Operating revenues	$	340,488	$	380,201	$	471,889	$	347,477
Operating income	31,845		61,891		107,509		24,510
Net income	11,360		30,294		58,247		6,468

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

None.

Item 9A — Controls and Procedures

Disclosure Controls and Procedures

SPS maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of Dec. 31, 2013, based on an evaluation carried out under the supervision and with the participation of SPS’ management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that SPS’ disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No change in SPS’ internal control over financial reporting has occurred during SPS’ most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, SPS’ internal control over financial reporting. SPS maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. SPS has evaluated and documented its controls in process activities, general computer activities, and on an entity-wide level. During the year and in preparation for issuing its report for the year ended Dec. 31, 2013, 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

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Item 14 — Principal Accountant Fees and Services

Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2014 Annual Meeting of Shareholders, which is incorporated by reference.

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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, 2013.
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Statements of Income — For the three years ended Dec. 31, 2013, 2012 and 2011.
	Statements of Comprehensive Income — For the three years ended Dec. 31, 2013, 2012 and 2011.
	Statements of Cash Flows — For the three years ended Dec. 31, 2013, 2012 and 2011.
	Balance Sheets — As of Dec. 31, 2013 and 2012.
	Statements of Common Stockholder’s Equity — For the three years ended Dec. 31, 2013, 2012 and 2011.
	Statements of Capitalization — As of Dec. 31, 2013 and 2012.
2.	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2013, 2012 and 2011.
3.	Exhibits

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

3.01*	Amended and Restated Articles of Incorporation dated Sept. 30, 1997 (Exhibit 3(a)(2) to Form 10-K (file no. 001-03789) dated March 3, 1998).
3.02*	By-Laws of SPS as Amended and Restated on Sept. 26, 2013. (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 001-03789)).
4.01*	Indenture dated Feb. 1, 1999 between SPS and The Chase Manhattan Bank (Exhibit 99.2 to Form 8-K (file no. 001-03789) dated Feb. 25, 1999).
4.02*	First Supplemental Indenture dated March 1, 1999 between SPS and The Chase Manhattan Bank (Exhibit 99.3 to Form 8-K (file no. 001-03789) dated Feb. 25, 1999).
4.03*	Second Supplemental Indenture dated Oct. 1, 2001 between SPS and The Chase Manhattan Bank (Exhibit 4.01 to Form 8-K (file no. 001-03789) dated Oct. 23, 2001).
4.04*	Third Supplemental Indenture dated Oct. 1, 2003 to the indenture dated Feb. 1, 1999 between SPS and JPMorgan Chase Bank, as successor Trustee, creating $100 million principal amount of Series C and Series D Notes, 6 percent due 2033 (Exhibit 4.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated Nov. 13, 2003).
4.05*	Fourth Supplemental Indenture dated Oct. 1, 2006 between SPS and The Bank of New York, as successor Trustee (Exhibit 4.01 to Form 8-K (file no. 001-03789) dated Oct. 3, 2006).
4.06*	Red River Authority for Texas Indenture of Trust dated July 1, 1991 (Form 10-K, Aug. 31, 1991 -Exhibit 4(b)).
4.07*	Supplemental Trust Indenture dated as of Nov. 1, 2008 between SPS and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $250 million principal amount of Series G Senior Notes, 8.75 percent due 2018  (Exhibit 4.01 of Form 8-K of SPS, dated Nov. 14, 2008 (file no. 001-03789)).
4.08*	Indenture dated as of Aug. 1, 2011 between SPS and U.S, Bank National Association, as Trustee  (Exhibit 4.01 to Form 8-K dated Aug. 10, 2011 (file no. 001-03789)).
4.09*	Supplemental Indenture dated as of Aug. 3, 2011 between SPS and U.S. Bank National Association, as Trustee, creating $200 million principal amount of 4.50 percent First Mortgage Bonds, Series No. 1 due 2041  (Exhibit 4.02 to Form 8-K dated Aug. 10, 2011 (file no. 001-03789)).
10.01*+	Xcel Energy Non-Qualified Pension Plan (2009 Restatement) (Exhibit 10.02 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.02*+	Xcel Energy Senior Executive Severance Policy (2009 Amendment and Restatement) (Exhibit 10.05 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.03*+	Xcel Energy Non-employee Directors’ Deferred Compensation Plan as amended and restated on Jan. 1, 2009 (Exhibit 10.08 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.04*+	Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Form U5B (file no. 001-03034) dated Nov. 16, 2000).

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10.05*+	Xcel Energy Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 (Exhibit 10.17 to Form 10-K of Xcel Energy  (file no. 001-03034) for the year ended Dec. 31, 2008).
10.06*	Coal Supply Agreement (Harrington Station) between SPS and TUCO, dated May 1, 1979 (Form 8-K (file no. 001-03789), May 14, 1979 — Exhibit 3).
10.07*	Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO, dated July 1, 1978 (Form 8-K, (file no. 001-03789) May 14, 1979 — Exhibit 5(A)).
10.08*	Guaranty of Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO (Form 8-K, (file no. 3789) May 14, 1979 — Exhibit 5(B)).
10.09*	Coal Supply Agreement (Tolk Station) between SPS and TUCO dated April 30, 1979, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, (file no. 3789) Feb. 28, 1982 — Exhibit 10(b)).
10.10*	Master Coal Service Agreement between Wheelabrator Coal Services Co. and TUCO dated Dec. 30, 1981, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, (file no. 3789) Feb. 28, 1982 — Exhibit 10(c)).
10.11*	Power Purchase Agreement dated May 23, 1997 between Borger Energy Associates, L.P, and SPS.
10.12*+	Amendment dated Aug. 26, 2009 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy  (Exhibit 10.06 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.13*+	Xcel Energy Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.08 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.14*+	Xcel Energy Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix A to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).
10.15*+	Xcel Energy 2010 Executive Annual Discretionary Award Plan (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2009).
10.16*+	Xcel Energy 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix B to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).
10.17*+	Xcel Energy 2010 Executive Annual Discretionary Award Plan (as amended and restated effective Dec. 15, 2010) (Exhibit 10.23 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.18*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Bonus Stock Agreement (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.19*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Performance Share Agreement (Exhibit 10.25 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.20a*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.26 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.20b*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Time-Based Restricted Stock Unit Agreement (Exhibit 10.14b to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2012).
10.21*+	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy as amended and restated effective Feb. 23, 2011 (Appendix A to the Xcel Energy Definitive Proxy Statement (file no. 001-03034) filed Apr. 5, 2011).
10.22*+	Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (as amended and restated effective Nov. 29, 2011) (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011).
10.23*+	Second Amendment dated Oct. 26, 2011 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.18 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011).
10.24*	Amended and Restated Credit Agreement, dated as of July 27, 2012 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, as Documentation Agent (Incorporated by reference to Exhibit 99.04 to Xcel Energy Inc.’s Form 8-K, dated July 27, 2012 (file no. 001-03034)).
10.25*+	First Amendment dated Feb. 20, 2013 to the Xcel Energy Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended March 31, 2013).
10.26*+	Fourth Amendment dated Feb. 20, 2013 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.02 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended March 31, 2013).

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10.27*+	First Amendment dated May 21, 2013 to the Xcel Energy Inc. Long Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.21 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013).
10.28*+	Second Amendment dated May 21, 2013 to the Xcel Energy Inc. Non-Qualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.22 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013).
12.01	Statement of Computation of Ratio of Earnings to Fixed Charges.
23.01	Consent of Independent Registered Public Accounting Firm.
31.01	Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101	The following materials from SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2013 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Statements of Income, (ii) the Statements of Comprehensive Income, (iii) the Statements of Cash Flows, (iv) the Balance Sheets, (v) the Statements of Stockholder’s Equity, (vi) the Statements of Capitalization, (vii) Notes to Financial Statements, (viii) document and entity information, and (ix) Schedule II.

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SCHEDULE II

SOUTHWESTERN PUBLIC SERVICE CO.

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DEC. 31, 2013, 2012 AND 2011

(amounts in thousands)

			Additions
	Balance at Jan. 1		Charged to Costs and Expenses		Charged to Other Accounts(a)		Deductions from Reserves (b)		Balance at Dec. 31
Allowance for bad debts:
2013	$	4,722	$	3,437	$	1,076	$	3,760	$	5,475
2012	5,380		2,915		1,202		4,775		4,722
2011	5,095		3,655		1,139		4,509		5,380

^(a)  Recovery of amounts previously written off.

^(b)  Principally bad debts written off.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned thereunto duly authorized.

	SOUTHWESTERN PUBLIC SERVICE COMPANY
Feb. 24, 2014	/s/ TERESA S. MADDEN
	Teresa S. Madden
	Senior 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/ DAVID T. HUDSON	/s/ BENJAMIN G.S. FOWKE III
David T. Hudson	Benjamin G.S. Fowke III
President, Chief Executive Officer and Director	Chairman and Director
(Principal Executive Officer)
/s/ TERESA S. MADDEN	/s/ JEFFREY S. SAVAGE
Teresa S. Madden	Jeffrey S. Savage
Senior Vice President, Chief Financial Officer and Director	Vice President and Controller
(Principal Financial Officer)	(Principal Accounting Officer)
/s/ DAVID M. SPARBY
David M. Sparby
Director

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

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

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