SOUTHWESTERN PUBLIC SERVICE CO - FORM 10-K

SOUTHWESTERN PUBLIC SERVICE CO - FORM 10-K - February 23, 2015

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Attached files

SOUTHWESTERN PUBLIC SERVICE CO Reports

file	filename
EX-99.01 - EXHIBIT 99.01 - SOUTHWESTERN PUBLIC SERVICE CO	spsex990110k2014.htm
EX-31.01 - EXHIBIT 31.01 - SOUTHWESTERN PUBLIC SERVICE CO	spsex310110k2014.htm
EX-12.01 - EXHIBIT 12.01 - SOUTHWESTERN PUBLIC SERVICE CO	spsex120110k2014.htm
EX-31.02 - EXHIBIT 31.02 - SOUTHWESTERN PUBLIC SERVICE CO	spsex310210k2014.htm
EX-32.01 - EXHIBIT 32.01 - SOUTHWESTERN PUBLIC SERVICE CO	spsex320110k2014.htm
EXCEL - IDEA: XBRL DOCUMENT - SOUTHWESTERN PUBLIC SERVICE CO	Financial_Report.xls
EX-23.01 - EXHIBIT 23.01 - SOUTHWESTERN PUBLIC SERVICE CO	spsex230110k2014.htm

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, 2014



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. 23, 2015, 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 2015 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	8
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	22
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	22
Item 6 — Selected Financial Data	22
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 7A — Quantitative and Qualitative Disclosures About Market Risk	25
Item 8 — Financial Statements and Supplementary Data	26
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	70
Item 9A — Controls and Procedures	70
Item 9B — Other Information	71

PART III	71
Item 10 — Directors, Executive Officers and Corporate Governance	71
Item 11 — Executive Compensation	71
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	71
Item 13 — Certain Relationships and Related Transactions, and Director Independence	71
Item 14 — Principal Accountant Fees and Services	71

PART IV	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.

Table of Contents

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
C&I	Commercial and Industrial
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

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CWIP	Construction work in progress
ETR	Effective tax rate
ERCOT	Electric Reliability Council of Texas
FASB	Financial Accounting Standards Board
FTR	Financial transmission right
GAAP	Generally accepted accounting principles
GHG	Greenhouse gas
HTY	Historic test year
MISO	Midcontinent Independent 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
NOV	Notice of violation
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

Table of Contents

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 31 percent of its total KWh sold in 2014. SPS provides electric utility service to approximately 386,000 retail customers in Texas and New Mexico. Approximately 72 percent of SPS’ retail electric operating revenues were derived from operations in Texas during 2014. 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 five percent to 15 percent of Xcel Energy’s consolidated net income.

SPS’ corporate strategy focuses on four core objectives: improving utility performance; driving operational excellence; providing options and solutions to customers; and investing for the future.

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 previously recovered 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.


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


•	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 previously granted SPS authority to use a fuel adjustment clause through November 2014, and allows its continued use while a new application is pending. In November 2014, SPS filed an application with the NMPRC to continue use of the fuel adjustment clause for an additional four years. Hearings are scheduled for May 2015.

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 2015, assuming normal weather, is listed below.



System Peak Demand (in MW)
2012	2013	2014	2015 Forecast
5,265	5,056	4,871	4,982

The peak demand for the SPS system typically occurs in the summer. The 2014 uninterrupted system peak demand for SPS occurred on Aug. 7, 2014. The 2014 peak demand decreased due to cooler summer weather.

Energy Sources and Related Transmission Initiatives

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

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) — In February 2014, the FERC granted SPS approval to make sales to the SPP IM at market-based rates. Further, In February and March, respectively, SPS was granted interim approval for revised QF tariff pricing in Texas and New Mexico to be consistent with the new market and to coincide with the start of the IM. The SPP IM began operations in March 2014 and operates in the day ahead and real time energy and ancillary services market. In April 2014, the FERC approved SPS’ filings to modify its wholesale power sales contracts to allow recovery of SPP IM charges and revenues through the SPP wholesale FCA.

Transmission NTCs — As a member of SPP, SPS accepts NTCs for electric transmission line and substation projects to be built within the SPP footprint. SPS has accepted NTCs for projects with an estimated capital cost of approximately $1.9 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. The NMPRC and the PUCT must approve the siting and routing of any 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 OATT. Costs allocated to SPS are permissible for recovery through the NMPRC, the PUCT and the FERC processes.

High Priority Incremental Load Study Report

In April 2014, the SPP Board of Directors approved the High Priority Incremental Load Study Report, a reliability assessment that evaluated the anticipated transmission needs of certain parts of the SPP resulting from expected load growth in the area. As a result of this study, SPS has received NTCs and conditional NTCs for 44 new transmission projects to be placed into service by 2020. SPS is developing plans for these projects in preparation of submitting CCNs to the PUCT and the NMPRC. These projects are intended to provide regional reliability benefits as well as the ability to serve the increase in load in southeastern New Mexico.

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TUCO substation to Woodward, Okla. 345 KV transmission line

The TUCO to Woodward District extra high voltage interchange is a 345 KV transmission line. SPS constructed the line to just inside the Oklahoma state line, and Oklahoma Gas and Electric Company (OGE) built from there to Woodward, Okla. SPS’ investment in the TUCO to Woodward line and substation is approximately $206 million and is expected to be recovered from SPP members, including SPS, in accordance with the SPP tariff. The line was placed into service in September 2014.

Hitchland substation to Woodward, Okla. 345 KV transmission line

The Hitchland substation to Woodward, Okla. line is a 345 KV double circuit transmission line and associated substation facilities in the Oklahoma and Texas Panhandle. SPS built the first 30 miles to Beaver County, Okla. and OGE completed the line from there to Woodward, Okla. SPS’ investment for the Hitchland to Woodward line and substation is approximately $58 million and is expected to be recovered from SPP members in accordance with the SPP tariff. The line was placed into service in May 2014.

Potash Junction substation to Roadrunner substation 345 KV transmission line

In April 2014, SPS filed a CCN with the NMPRC for a new 345 KV transmission line from the Potash Junction substation to the Roadrunner substation, both near Carlsbad, N.M. The proposed line would run 40 miles and cost an estimated $54 million. The NMPRC approved the CCN in December 2014. The line is anticipated to be placed into service in the fourth quarter of 2015.

Resource Plans — SPS is required to develop and implement a renewable portfolio plan in which 15 percent of its energy to serve its New Mexico retail customers is produced by renewable resources in 2015. SPS primarily fulfills its renewable portfolio requirements through PPAs.

Fuel Supply and Costs

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



	Coal				Natural Gas				Weighted Average Owned Fuel Cost
SPS Generating Plants	Cost		Percent		Cost		Percent		Weighted Average Owned Fuel Cost
2014	$	2.07	71	%	$	4.76	29	%	$	2.85
2013	2.14		71		3.97		29		2.68
2012	1.87		67		2.99		33		2.24

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 for Harrington and Tolk. SPS normally maintains approximately 43 days of coal inventory. As of Dec. 31, 2014 and 2013, coal inventories at SPS were approximately 17 and 42 days supply, respectively. At Dec. 31, 2014, coal inventories were below optimal levels due to railcar congestion. TUCO has coal agreements to supply 87 percent of SPS’ estimated coal requirements in 2015, 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 first year, 67 percent of requirements in year two, and 33 percent of requirements in year three.

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 2015 to 2033. All of the natural gas supply contracts have variable pricing that is tied to various natural gas indices.

Most transportation contract pricing is based on FERC and Railroad Commission of Texas approved transportation tariff rates. Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. SPS’ commitments related to gas supply contracts were approximately $3 million and $21 million and commitments related to gas transportation and storage contracts were approximately $222 million and $201 million at Dec. 31, 2014 and 2013, respectively.

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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, 2014, 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 14.7 percent and 12.7 percent of SPS’ energy for 2014 and 2013, respectively.


•	Wind energy comprised 14.0 percent and 12.1 percent of SPS’ energy for 2014 and 2013, respectively.


•	Solar power comprised approximately 0.4 percent of SPS’ energy for both 2014 and 2013.

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 remained consistent at approximately 900 in 2013 and 2014. Windsource sales were approximately 4,400 MWh in 2013 and 3,900 MWh in 2014.

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 315 PV systems with approximately 20.8 MW of aggregate capacity and over 115 PV systems with approximately 7.6 MW of aggregate capacity have been installed in New Mexico under this program as of Dec. 31, 2014 and 2013, respectively.

Wind — SPS acquires its wind energy from independent power producers (IPP) and qualified facilities (QF) contracts with wind farm owners, primarily located in the Texas Panhandle area of Texas and New Mexico. SPS currently has 37 of these agreements in place, with facilities ranging in size from under two MW to 250 MW for a total capacity greater than 1,800 MW. SPS had approximately 1,500 MW and 1,000 MW of wind energy on its system at the end of 2014 and 2013, respectively. 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 IPP contracts and QF contracts was approximately $26 for both 2014 and 2013. 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 2014 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 2014, with certain projects qualifying into future years.

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.

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, New ROE Policy — In June 2014, the FERC adopted a new two-step ROE methodology for electric utilities. In October 2014, the FERC upheld the determination of the long-term growth rate to be used in its new ROE methodology. Several parties sought rehearing of the June 2014 order and therefore the new FERC policy may be subject to additional changes.

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FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) — In 2011, the FERC issued a final ruling, Order 1000, adopting new requirements for transmission planning, cost allocation and development to be effective prospectively. Order 1000 requires:


•	The development of tariffs that provide for joint regional transmission planning and cost allocation for all FERC-jurisdictional utilities within a region;


•	The coordination between regions for the development of interregional plans for transmission planning and cost allocation;


•	Each public utility transmission provider to amend its Open Access Transmission Tariff to describe procedures that provide for the consideration of transmission needs driven by public policy requirements in the local and regional transmission planning processes; and


•	The removal of ROFR provisions from FERC-jurisdictional wholesale transmission contracts and tariffs that presently grant the incumbent transmission owner a federal ROFR to build certain types of transmission projects in its service area.

SPP has submitted multiple compliance filings with the FERC to implement the Order 1000 requirements. Some of the new compliance provisions that were filed have already been approved but others remain under review by the FERC.

In August 2014, the D.C. Circuit denied all appeals and upheld Order 1000 in its entirety and indicated that challenges to the removal of federal ROFR provisions from individual contracts or tariffs could be considered in individual compliance filings. The FERC’s decisions to remove federal ROFR provisions in certain SPP agreements were appealed to federal courts of appeal in 2014, and those appeals are pending. The removal of a federal ROFR would eliminate rights that SPS currently has under the SPP tariffs to build certain transmission projects within its footprint.

In 2014, SPP filed compliance plans that would allow the RTO to recognize state law ROFRs in any selection process for Order 1000 transmission projects. In 2015, the FERC issued orders on rehearing on the compliance filing that would continue to allow SPP the authority to recognize state ROFRs. SPS believes it has a state ROFR in Texas.

Order 1000 could create opportunities for third parties to build and own certain regional transmission projects that had previously been reserved for the SPP transmission owners, potentially reducing SPS’s financial return on new investments in electric transmission facilities. The ultimate impact of Order 1000 on future SPS transmission investment is not known at this time.

NERC Critical Infrastructure Protection (CIP) Requirements — The FERC has approved version 5 of NERC’s CIP standards. Requirements must be applied to high and medium impact assets by April 1, 2016 and to low impact assets by April 1, 2017. SPS is currently in the process of evaluating the new requirements and identifying initiatives needed to meet the compliance deadlines.

NERC Physical Security Requirements — In November 2014, the FERC approved NERC’s proposed CIP standard related to physical security for bulk electric system facilities. The new standard will become enforceable in October 2015 with staggered milestone deliverable dates through 2016. SPS is currently in the process of developing and performing the initial risk assessment in accordance with the requirements of the standard, which will provide a basis to estimate the cost of protections necessary to meet the standard. The additional cost for compliance is anticipated to be recoverable through rates.

SPP and MISO Complaints Regarding RTO Joint Operating Agreement (JOA) — SPP and MISO have a longstanding dispute regarding the interpretation of their JOA, which is intended to coordinate RTO operations along the MISO/SPP system boundary. SPP and MISO disagree over MISO’s authority to transmit power over SPP transmission facilities between the traditional MISO region in the Midwest and the Entergy system. Several cases have been filed with the FERC by MISO and SPP. In June 2014, the FERC accepted a proposed tariff change by MISO to recover transmission charges imposed by SPP retroactive to January 2014, and set the issues for settlement judge and hearing procedures. If SPP is successful in charging MISO for use of the SPP system, the NSP System would experience higher costs from MISO, which could be material, but SPS would collect revenues from SPP. The outcome of the JOA disputes, and the potential impact on SPS, are uncertain at this time.

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Electric Operating Statistics

Electric Sales Statistics



	Year Ended Dec. 31
	2014			2013			2012
Electric sales (Millions of KWh)
Residential	3,549			3,564			3,542
Large commercial and industrial	10,262			9,893			9,707
Small commercial and industrial	4,741			4,743			4,708
Public authorities and other	556			568			575
Total retail	19,108			18,768			18,532
Sales for resale	8,563			9,200			9,281
Total energy sold	27,671			27,968			27,813

Number of customers at end of period
Residential	302,922			301,169			299,352
Large commercial and industrial	214			214			209
Small commercial and industrial	76,553			75,592			74,706
Public authorities and other	6,323			6,256			6,262
Total retail	386,012			383,231			380,529
Wholesale	7			30			31
Total customers	386,019			383,261			380,560

Electric revenues (Thousands of Dollars)
Residential	$	363,841		$	330,487		$	309,474
Large commercial and industrial	516,648			445,043			379,722
Small commercial and industrial	379,558			351,851			314,526
Public authorities and other	46,916			43,059			40,432
Total retail	1,306,963			1,170,440			1,044,154
Wholesale	493,127			416,793			408,491
Other electric revenues	137,280			119,854			87,410
Total electric revenues	$	1,937,370		$	1,707,087		$	1,540,055

KWh sales per retail customer	49,501			48,973			48,701
Revenue per retail customer	$	3,386		$	3,054		$	2,744
Residential revenue per KWh		10.25	¢		9.27	¢		8.74	¢
Large commercial and industrial revenue per KWh	5.03			4.50			3.91
Small commercial and industrial revenue per KWh	8.01			7.42			6.68
Total retail revenue per KWh	6.84			6.24			5.63
Wholesale revenue per KWh	5.76			4.53			4.40

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Energy Source Statistics



	Year Ended Dec. 31
	2014			2013			2012
	Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation
Coal	12,770	48	%	14,184	49	%	14,005	49	%
Natural Gas	10,068	37		11,235	38		12,088	43
Wind ^(a)	3,762	14		3,507	12		2,103	7
Other ^(b)	180	1		167	1		177	1
Total	26,780	100	%	29,093	100	%	28,373	100	%

Owned generation	16,956	63	%	18,814	65	%	19,940	70	%
Purchased generation	9,824	37		10,279	35		8,433	30
Total	26,780	100	%	29,093	100	%	28,373	100	%


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


^(b)	Distributed generation from the Solar*Rewards program is not included, and was approximately 10, 11, and eight net million KWh for 2014, 2013, and 2012, 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 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 is a vertically integrated utility, subject to traditional cost-of-service regulation. However, SPS is subject to different public policies that promote competition and the development of energy markets. SPS’ industrial and large commercial customers have the ability to own or operate facilities to generate their own electricity. In addition, customers may have the option of substituting other fuels, such as natural gas, steam or chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region. Customers also have the opportunity to supply their own power with 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 certain new electric transmission facilities. SPS has franchise agreements with certain cities subject to periodic renewal. If a city elected not to renew the franchise agreement, it could seek alternative means for its citizens to access electric power or gas, such as municipalization. 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. While facing these challenges, SPS believes its rates and services are competitive with currently available alternatives.

ENVIRONMENTAL MATTERS

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

There are significant future environmental regulations under consideration to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change. SPS has undertaken a number of initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. If these future environmental regulations do not provide credit for the investments we have already made to reduce GHG emissions, or if they require additional initiatives or emission reductions, then their requirements would potentially impose additional substantial costs. We believe, based on prior state commission practice, we would recover the cost of these initiatives through rates.

EMPLOYEES

As of Dec. 31, 2014, SPS had 1,281 full-time employees and one part-time employee, of which 840 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.

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Oversight of Risk and Related Processes

A key accountability of the Board of Directors is to identify, manage and mitigate material risk. Our Board employs an effective process for doing so, combining management and Board risk oversight. The guidelines on corporate governance and Board committee charters define the scope of review and inquiry for the Board and its committees regarding risk management. As provided below, management and each committee has responsibility for overseeing aspects of risk management and mitigation of the risk.

Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability, broadly considering our business, the utility industry, the domestic and global economy and the environment. 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.

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. The process for risk mitigation includes adherence to our code of conduct and other compliance policies, operation of formal risk management structures and groups, and overall business management to mitigate the risks inherent in the implementation strategy. Building on this culture of compliance, we manage and further mitigate risks through operation of formal risk management structures and groups, including management councils, risk committees and the services of internal corporate areas such as internal audit, the corporate controller and legal services.

Management communicates regularly with the Board 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 Board has assigned several important aspects of its governance and oversight to four standing committees to ensure issues and risks are well understood and effectively managed. While the Board as a whole reviews management’s key risk assessment and analyzes areas of potential future risk to Xcel Energy, the committees provide focused oversight of specific risks assigned to them. This provides robust and comprehensive risk management that is critical to successful execution of corporate strategy.

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, 2014, these sites included third party sites, such as landfills, for which we are alleged to be a PRP that sent hazardous materials and wastes.

We are also subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. Failure to meet the requirements of these mandates may result in fines or penalties, which 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.

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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, CO₂and other GHGs, particulates 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 changes in weather conditions, changes in precipitation and extreme weather events.

Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in additional generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may 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 may raise electricity prices, which would increase the cost of energy we provide to our customers.

Severe weather impacts our service territories, primarily when thunderstorms, 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.

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, regulation of CO₂emissions under section 111(d) of the CAA, or additional environmental regulation could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.

Financial Risks

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

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

The profitability of our operations is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment 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 such 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.

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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. 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. As a result, we frequently need to access the debt and equity capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital markets are global in nature and are impacted by numerous issues and events throughout the world economy. Capital market disruption events, and resulting broad financial market distress could prevent us from issuing 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.

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’s rules permit us to deal in utility operations-related swaps with utility special entities and not be required to register as a swap dealer provided that our aggregate gross notional amount of swap dealing activity (including utility operations-related swaps) does not exceed the general de minimis threshold and provided that we have not exceeded the special entity de minimis threshold (excluding utility operations-related swaps) of $25 million for the preceding 12 months. Our current level of financial swap activity with special entities is significantly below this special entity de minimis 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.

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

Operational Risks

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

We engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. As a result we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis (mark-to-market accounting). Actual settlements can vary significantly from estimated fair values recorded to the financial statements, 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 to our 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 including rail shipments of coal, electric generation capacity, transmission, natural gas pipeline capacity, etc.

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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, economic activity, costs, regulatory mechanisms, impact of technology, the installation of distributed 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 addition, 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. 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 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. We have programs in place to comply with the Pipeline Safety Act and for systematic infrastructure monitoring and renewal over time. A significant incident could increase regulatory scrutiny and result in penalties and higher costs of operations.

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, 2014, Xcel Energy Inc. and its utility subsidiaries had approximately $11.5 billion of long-term debt and $1.3 billion of short-term debt and current maturities. Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.

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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, 2014, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $13.9 million and $0.2 million of exposure. Xcel Energy also had additional guarantees of $31.4 million at Dec. 31, 2014 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 2014, 2013 and 2012 we paid $83.5 million, $69.6 million and $66.6 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs. This could adversely affect our liquidity. The most restrictive dividend limitation for SPS is imposed by its state regulatory commissions. State regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy Inc., by requiring a minimum equity-to-total capitalization ratio. See Item 5 for further discussion on dividend limitations.

Public Policy Risks

We may be subject to legislative and regulatory responses to climate change 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. Legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk as our electric generating facilities may be subject to additional regulation 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 has proposed regulations to reduce GHG emissions from existing power plants that are expected to become final in 2015, with state plans to achieve the EPA’s goals due by 2017. Such regulations could impose substantial costs on our system. The EPA has also proposed regulations that would establish NSPS for any new fossil fuel-fired power plants that may be built which may be adopted in 2015. If adopted, these regulations could significantly increase the cost of building new generating plants.

The United States continues to participate in international negotiations related to the United Nations Framework Convention on Climate Change (UNFCCC). In 2014, the United States and China jointly announced GHG emissions goals. Further, the 20^th Conference of the Parties (COP) to the UNFCCC concluded with the objective of developing an agreement among countries on emission reductions at the 2015 COP. This could result in additional GHG regulation or reduction goals in the United States.

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

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There are many uncertainties regarding when and in what form climate change legislation or regulations will be imposed. The impact of legislation and regulations will depend on a number of factors, including what GHG emission reduction goals are set, what flexibility is allowed to meet the goals, how and whether early action to reduce GHG emissions is credited, whether GHG sources in other sectors of the economy are regulated, the degree to which GHG offsets are recognized as compliance options, how any emission allowances would be allocated to specific sources and the indirect impact of carbon regulation on natural gas and coal prices. In addition, 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 in a timely manner. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations

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

Increased risks of regulatory penalties could negatively impact our business.

The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. The FERC can now impose penalties of up to $1 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. Some states have the authority to impose substantial penalties in the event of non-compliance.

We attempt to mitigate the risk of regulatory penalties 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.

Macroeconomic Risks

Economic conditions impact our business.

Our operations are affected by local, national and worldwide economic conditions both positively and negatively. Growth in our customer base is correlated with economic conditions. While the number of customers is growing, sales growth is relatively modest due to an increased focus on energy efficiency including federal standards for appliance and lighting efficiency and distributed generation, primarily solar PV. Instability in the financial markets also may affect the cost of capital and our ability to raise capital, which are discussed in the capital market risk section above.

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

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

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

Our generation plants, fuel storage facilities, transmission and distribution facilities and information 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, sudden and significant increase or decrease in wind generation, or any disruption of work force such as may be caused by flu or other epidemic) within our operating systems or on a neighboring system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material impact on our financial condition and results.

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

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

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

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

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

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Rising energy prices could negatively impact our business.

While we have fuel clause recovery mechanisms, higher fuel costs could significantly impact our results of operations if costs are not recovered. 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. Low fuel costs could have a positive impact on sales although, low oil prices could negatively impact oil and gas production activities. We are unable to predict future prices or the ultimate impact of such prices on our results of operations or cash flows.

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

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

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.



Electric Utility Generating Stations:
Station, Location and Unit	Fuel	Installed	Summer 2014 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	338
Maddox-Hobbs, N.M., 1 Unit	Natural Gas	1963-1976	61
		Total	4,426

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2014:



Conductor Miles
345 KV	8,110
230 KV	9,312
115 KV	12,378
Less than 115 KV	23,294

SPS had 433 electric utility transmission and distribution substations at Dec. 31, 2014.

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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.

PART II

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

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


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

•

The most restrictive dividend limitation for SPS is imposed by its state regulatory commissions. SPS’ state regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy Inc. by requiring an equity-to-total capitalization ratio (excluding short-term debt) between 45.0 percent and 55.0 percent. In addition, SPS may not pay a dividend that would cause it to lose its investment grade bond rating. SPS’ equity-to-total capitalization ratio (excluding short-term debt) was 53.6 percent at Dec. 31, 2014 and $396 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 2014 and 2013 were as follows:



(Thousands of Dollars)	2014		2013
First quarter	$	18,181	$	17,113
Second quarter	24,368		17,475
Third quarter	22,866		18,218
Fourth quarter	27,828		18,083

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 Discussion and Analysis of Financial Condition and Results of Operations

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

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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.

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 slowdown in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where SPS has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by SPS; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric market; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; 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 $129.9 million for 2014, compared with net income of approximately $95.2 million for 2013. Electric rate increases in Texas and New Mexico and weather-normalized sales growth offset higher O&M and depreciation expenses.

Electric Revenues and Margins

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. 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)	2014			2013
Electric revenues	$	1,937		$	1,707
Electric fuel and purchased power	(1,192		)	(1,059		)
Electric margin	$	745		$	648

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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)	2014 vs. 2013
Retail rate increases (Texas and New Mexico)	$	58
Trading	55
Fuel and purchased power cost recovery	50
Transmission revenue	23
Non-fuel riders	15
Demand revenue	6
Sales mix	3
Estimated impact of weather	(4		)
Other, net	(2		)
Total increase in ongoing electric revenues	204
FERC complaint case orders ^(a)	26
Total increase in GAAP electric revenues	$	230

Electric Margin



(Millions of Dollars)	2014 vs. 2013
Retail rate increases (Texas and New Mexico)	$	58
Non-fuel riders	15
Transmission revenue	14
Demand revenue	6
Sales mix	3
Purchased capacity costs	(12		)
Renewable energy credits	(10		)
Estimated impact of weather	(4		)
Other, net	1
Total increase in ongoing electric margin	71
FERC complaint case orders ^(a)	26
Total increase in GAAP electric margin	$	97


^(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 $23.3 million, or 9.2 percent for 2014 compared with 2013. The following summarizes the components of the changes for the year ended Dec. 31:



(Millions of Dollars)	2014 vs. 2013
2013 gain on sale of transmission assets	$	14
Plant generation costs	3
Transmission costs	2
Employee benefits	2
Other, net	2
Total increase in O&M expenses	$	23


•	Gain on sale of transmission assets relates to the 2013 gain associated with the sale of certain transmission assets to Sharyland. See Note 10 to financial statements.

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Depreciation and Amortization — Depreciation and amortization expenses increased $13.7 million, or 11.3 percent for 2014 compared with 2013. The increase is primarily attributable to higher amortization as a result of regulatory outcomes.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $4.3 million, or 8.8 percent for 2014 compared with 2013. The increase is primarily due to higher property taxes.

AFUDC, Equity and Debt — AFUDC increased $2.6 million for 2014 compared with 2013. The increase was primarily due to the expansion of transmission facilities.

Interest Charges — Interest charges increased $2.4 million, or 3.0 percent, for 2014 compared with 2013. The increase was primarily due to higher long-term debt levels, partially offset by lower interest rates, and interest associated with the customer refund based on the August 2013 FERC orders.

Income Taxes — Income tax expense increased $21.4 million for 2014 compared with 2013. The increase in income tax expense is primarily due to higher pretax earnings in 2014. The ETR was 36.7 percent for 2014, compared with 36.1 percent for 2013.

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

SPS is exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. See Note 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 short- and long-term physical purchase and sales contracts for electric capacity, energy and energy-related products. Commodity price risk is also managed through the use of financial derivative instruments. SPS’ risk management policy allows it to manage commodity price risk 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, 2014 and 2013, a 100 basis point change in the benchmark rate on SPS’ variable rate debt would impact annual pretax interest expense by approximately $0.5 million and $1.2 million, respectively. See Note 9 to the financial statements for a discussion of SPS’ interest rate derivatives.

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

At Dec. 31, 2014, 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. 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.

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, 2014. 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, 2014.

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 $25.8 million and $9.9 million of estimated fair values, respectively, for FTRs held at Dec. 31, 2014.

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.

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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, 2014. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2014, SPS’ internal control over financial reporting is effective at the reasonable assurance level based on those criteria.



/s/ BEN FOWKE		/s/ TERESA S. MADDEN
Ben Fowke		Teresa S. Madden
Chairman and Chief Executive Officer		Executive Vice President, Chief Financial Officer
Feb. 23, 2015		Feb. 23, 2015

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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, 2014 and 2013, 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, 2014. 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, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, 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 23, 2015

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SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF INCOME

(amounts in thousands of dollars)



	Year Ended Dec. 31
	2014			2013			2012

Operating revenues	$	1,937,370		$	1,707,087		$	1,540,055

Operating expenses
Electric fuel and purchased power	1,192,176			1,059,330			889,567
Operating and maintenance expenses	277,217			253,880			251,853
Demand side management program expenses	12,350			12,420			12,891
Depreciation and amortization	135,632			121,907			113,743
Taxes (other than income taxes)	53,871			49,533			46,246
Total operating expenses	1,671,246			1,497,070			1,314,300

Operating income	266,124			210,017			225,755

Other (expense) income, net	(59		)	140			46
Allowance for funds used during construction — equity	12,118			10,186			7,272

Interest charges and financing costs
Interest charges — includes other financing costs of $3,038, $3,031 and $2,996, respectively	80,218			77,866			69,074
Allowance for funds used during construction — debt	(7,089		)	(6,461		)	(4,599		)
Total interest charges and financing costs	73,129			71,405			64,475

Income before income taxes	205,054			148,938			168,598
Income taxes	75,202			53,761			62,229
Net income	$	129,852		$	95,177		$	106,369

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF COMPREHENSIVE INCOME

(amounts in thousands of dollars)



	Year Ended Dec. 31
	2014		2013		2012
Net income	$	129,852	$	95,177	$	106,369
Other comprehensive income
Derivative instruments:
Reclassification of losses to net income, net of tax of $96, $97 and $97, respectively	172		171		172
Other comprehensive income	172		171		172
Comprehensive income	$	130,024	$	95,348	$	106,541

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF CASH FLOWS

(amounts in thousands of dollars)



	Year Ended Dec. 31
	2014			2013			2012
Operating activities
Net income	$	129,852		$	95,177		$	106,369
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	137,947			124,069			115,917
Demand side management program amortization	1,673			1,673			1,811
Deferred income taxes	123,517			36,475			54,119
Amortization of investment tax credits	(341		)	(341		)	(327		)
Allowance for equity funds used during construction	(12,118		)	(10,186		)	(7,272		)
Provision for bad debts	4,137			3,437			2,915
Gain on sale of transmission assets	—			(13,661		)	—
Net derivative losses	268			268			269
Changes in operating assets and liabilities:
Accounts receivable	9,045			(36,184		)	(3,429		)
Accrued unbilled revenues	(20,080		)	(10,315		)	5,250
Inventories	(6,093		)	(7,443		)	4,238
Prepayments and other	(11,905		)	4,456			(3,901		)
Accounts payable	11,428			20,650			(13,730		)
Net regulatory assets and liabilities	(973		)	620			24,243
Other current liabilities	12,665			51,880			1,780
Pension and other employee benefit obligations	(2,246		)	(17,968		)	(13,706		)
Change in other noncurrent assets	2,836			(2,281		)	(1,541		)
Change in other noncurrent liabilities	7,166			(2,689		)	(1,912		)
Net cash provided by operating activities	386,778			237,637			271,093

Investing activities
Utility capital/construction expenditures	(554,936		)	(584,736		)	(384,626		)
Allowance for equity funds used during construction	12,118			10,186			7,272
Proceeds from sale of transmission assets	—			37,118			—
Investments in utility money pool arrangement	(105,000		)	(12,000		)	(217,000		)
Receipts from utility money pool arrangement	105,000			12,000			217,000
Other, net	—			—			—
Net cash used in investing activities	(542,818		)	(537,432		)	(377,354		)

Financing activities
(Repayment of) proceeds from short-term borrowings, net	(47,000		)	75,000			9,000
Proceeds from issuance of long-term debt	148,123			94,626			108,678
Borrowings under utility money pool arrangement	458,000			767,000			265,000
Repayments under utility money pool arrangement	(480,000		)	(729,000		)	(270,000		)
Capital contributions from parent	160,000			162,277			60,024
Dividends paid to parent	(83,498		)	(69,579		)	(66,609		)
Net cash provided by financing activities	155,625			300,324			106,093

Net change in cash and cash equivalents	(415		)	529			(168		)
Cash and cash equivalents at beginning of year	1,011			482			650
Cash and cash equivalents at end of year	$	596		$	1,011		$	482

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(70,748	)	$	(67,209	)	$	(61,268	)
Cash received (paid) for income taxes, net	42,679			(16,721		)	(13,763		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	33,164		$	23,305		$	38,751

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE CO.

BALANCE SHEETS

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



	Dec. 31
	2014			2013
Assets
Current assets
Cash and cash equivalents	$	596		$	1,011
Accounts receivable, net	71,626			70,951
Accounts receivable from affiliates	1,983			15,840
Accrued unbilled revenues	129,287			109,207
Inventories	43,231			37,138
Regulatory assets	52,006			27,595
Derivative instruments	23,776			17,826
Deferred income taxes	51,854			85,362
Prepayments and other	31,476			19,571
Total current assets	405,835			384,501

Property, plant and equipment, net	3,743,141			3,284,030

Other assets
Regulatory assets	323,305			290,415
Derivative instruments	33,164			41,056
Other	15,859			17,068
Total other assets	372,328			348,539
Total assets	$	4,521,304		$	4,017,070

Liabilities and Equity
Current liabilities
Short-term debt	$	37,000		$	84,000
Borrowings under utility money pool arrangement	16,000			38,000
Accounts payable	160,762			143,879
Accounts payable to affiliates	19,790			15,387
Regulatory liabilities	87,723			83,759
Taxes accrued	27,208			23,584
Accrued interest	17,057			16,883
Dividends payable	27,828			18,082
Derivative instruments	3,565			3,583
Other	80,211			75,355
Total current liabilities	477,144			502,512

Deferred credits and other liabilities
Deferred income taxes	849,145			757,778
Regulatory liabilities	115,188			81,504
Asset retirement obligations	26,031			19,375
Derivative instruments	30,643			34,207
Pension and employee benefit obligations	103,670			55,087
Other	9,320			3,051
Total deferred credits and other liabilities	1,133,997			951,002

Commitments and contingencies
Capitalization
Long-term debt	1,349,691			1,199,865
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2014 and 2013, respectively	—			—
Additional paid in capital	1,165,463			1,005,463
Retained earnings	395,998			359,389
Accumulated other comprehensive loss	(989		)	(1,161		)
Total common stockholder’s equity	1,560,472			1,363,691
Total liabilities and equity	$	4,521,304		$	4,017,070

See Notes to Financial Statements

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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			Accumulated Other Comprehensive Income (Loss)			Total Common Stockholder’s Equity
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
Net income						129,852						129,852
Other comprehensive income									172			172
Common dividends declared to parent						(93,243		)				(93,243		)
Contribution of capital by parent				160,000								160,000
Balance at Dec. 31, 2014	100	$	—	$	1,165,463	$	395,998		$	(989	)	$	1,560,472

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF CAPITALIZATION

(amounts in thousands of dollars, except share data)



	Dec. 31
	2014			2013
Long-Term Debt
First Mortgage Bonds, Series due:
June 15, 2024, 3.3%	$	150,000		$	—
Aug. 15, 2041, 4.5%	400,000			400,000
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	(309		)	(135		)
Total	1,349,691			1,199,865
Less current maturities	—			—
Total long-term debt	$	1,349,691		$	1,199,865

Common Stockholder’s Equity
Common stock — 200 shares authorized of $1.00 par value, 100 shares outstanding at Dec. 31, 2014 and 2013, respectively	$	—		$	—
Additional paid in capital	1,165,463			1,005,463
Retained earnings	395,998			359,389
Accumulated other comprehensive loss	(989		)	(1,161		)
Total common stockholder’s equity	$	1,560,472		$	1,363,691

See Notes to Financial Statements

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NOTES TO FINANCIAL STATEMENTS


1.	Summary of Significant Accounting Policies

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

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

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

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


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


•	Certain credits, which would otherwise be reflected as income, 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 motor, air conditioner and lighting upgrades, as well as residential rebates for participation in air conditioner interruption and home weatherization.

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

Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. Property, plant and equipment also includes costs associated with property held for future use. The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate. Property, plant and equipment 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. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.

SPS records depreciation expense related to its plant using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was 2.5, 2.6 and 2.7 percent for the years ended Dec. 31, 2014, 2013 and 2012, respectively.

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

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

AROs — SPS accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. SPS also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 11 for further discussion of AROs.

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

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

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

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

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

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

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

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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.

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 before the related costs are incurred are classified as a regulatory liability.

See Note 11 for further discussion of environmental costs.

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

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

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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, 2014 up to the date of issuance of these financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.


2.	Accounting Pronouncements

Recently Issued

Revenue Recognition — In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09), which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. This guidance, which includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers, will be effective for interim and annual reporting periods beginning after Dec. 15, 2016. SPS is currently evaluating the impact of adopting ASU 2014-09 on its financial statements.


3.	Selected Balance Sheet Data



(Thousands of Dollars)	Dec. 31, 2014			Dec. 31, 2013
Accounts receivable, net
Accounts receivable	$	77,465		$	76,426
Less allowance for bad debts	(5,839		)	(5,475		)
	$	71,626		$	70,951



(Thousands of Dollars)	Dec. 31, 2014		Dec. 31, 2013
Inventories
Materials and supplies	$	24,738	$	21,600
Fuel	18,493		15,538
	$	43,231	$	37,138



(Thousands of Dollars)	Dec. 31, 2014			Dec. 31, 2013
Property, plant and equipment, net
Electric plant	$	5,376,606		$	4,714,398
Construction work in progress	238,519			388,323
Total property, plant and equipment	5,615,125			5,102,721
Less accumulated depreciation	(1,871,984		)	(1,818,691		)
	$	3,743,141		$	3,284,030

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4.	Borrowings and Other Financing Instruments

Short-Term Borrowings

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



(Amounts in Millions, Except Interest Rates)	Three Months Ended Dec. 31, 2014
Borrowing limit	$	100
Amount outstanding at period end	16
Average amount outstanding	—
Maximum amount outstanding	16
Weighted average interest rate, computed on a daily basis	0.35		%
Weighted average interest rate at period end	0.45



(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2014			Twelve Months Ended Dec. 31, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	100		$	100		$	100
Amount outstanding at period end	16			38			—
Average amount outstanding	9			46			10
Maximum amount outstanding	100			100			63
Weighted average interest rate, computed on a daily basis	0.22		%	0.29		%	0.33		%
Weighted average interest rate at end of period	0.45			0.25			N/A

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



(Amounts in Millions, Except Interest Rates)	Three Months Ended Dec. 31, 2014
Borrowing limit	$	400
Amount outstanding at period end	37
Average amount outstanding	22
Maximum amount outstanding	54
Weighted average interest rate, computed on a daily basis	0.31		%
Weighted average interest rate at period end	0.47



(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2014			Twelve Months Ended Dec. 31, 2013			Twelve Months Ended Dec. 31, 2012
Borrowing limit	$	400		$	300		$	300
Amount outstanding at period end	37			84			9
Average amount outstanding	83			32			18
Maximum amount outstanding	241			140			106
Weighted average interest rate, computed on a daily basis	0.26		%	0.30		%	0.39		%
Weighted average interest rate at end of period	0.47			0.27			0.36

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, 2014, there were $30.0 million of letters of credit outstanding under the credit facility. At Dec. 31, 2013, there were $25.5 million 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.

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

Amended Credit Agreement — In October 2014, SPS entered into an amended five-year credit agreement with a syndicate of banks. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with an increased borrowing limit and an extension of maturity from July 2017 to October 2019. The borrowing limit for SPS has been increased to $400 million from $300 million.

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 47 percent and 49 percent at Dec. 31, 2014 and 2013, respectively. If SPS does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender.


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


•	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, 2014, SPS had the following committed credit facility available (in millions):



Credit Facility ^(a)		Drawn ^(b)		Available
$	400.0	$	67.0	$	333.0


^(a)	These credit facilities have been amended to extend the maturity to October 2019.


^(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, 2014 and 2013.

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 June 2014, SPS issued $150 million of 3.30 percent first mortgage bonds due June 15, 2024. 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 connection with SPS’ issuance of $150 million of 3.30 percent first mortgage bonds due June 15, 2024, SPS concurrently took certain actions to secure its previously issued Series G Senior Notes due Dec. 1, 2018 equally and ratably with SPS’ first mortgage bonds as required pursuant to the terms of the Series G notes.

To provide the required collateralization, SPS issued $250 million of collateral 8.75 percent first mortgage bonds due Dec. 1, 2018 to the trustee under its senior unsecured indenture which secured the previously issued Series G Senior Notes, 8.75 percent due Dec. 1, 2018, equally and ratably with SPS’ first mortgage bonds.

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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 $10.9 million and $10.3 million, net of amortization, at Dec. 31, 2014 and 2013, 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.


5.	Preferred Stock

SPS has authorized the issuance of preferred stock.



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


6.	Income Taxes

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


•	The R&E credit was extended for 2014;


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


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

The accounting related to the TIPA was recorded beginning in the fourth quarter of 2014 because a change in tax law is accounted for in the period of enactment.

American Taxpayer Relief Act of 2012 — In 2013, the American Taxpayer Relief Act (ATRA) was signed into law. The ATRA provided for the following:


•	The top tax rate for dividends increased from 15 percent to 20 percent. The 20 percent dividend rate is now consistent with the tax rates for capital gains;


•	The R&E credit was extended for 2012 and 2013;


•	PTCs were extended for projects that began construction before the end of 2013 with certain projects qualifying into future years; and


•	50 percent bonus depreciation was extended one year through 2013. Additionally, some longer production period property placed in service in 2014 is also eligible for 50 percent bonus depreciation.

The accounting related to the ATRA, including the provisions related to 2012, was recorded beginning in the first quarter of 2013 because a change in tax law is accounted for in the period of enactment.

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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 March 2016. 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, 2014, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $12 million of income tax expense for the 2009 through 2011 claims, the recently filed 2013 claim, and the anticipated claim for 2014. SPS is not expected to accrue any income tax expense related to this adjustment. At Dec. 31, 2014, the IRS has begun the Appeals process; however, 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, 2014, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. 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, 2014		Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions	$	1.5	$	1.2
Unrecognized tax benefit — Temporary tax positions	11.7		2.9
Total unrecognized tax benefit	$	13.2	$	4.1

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



(Millions of Dollars)	2014			2013			2012
Balance at Jan. 1	$	4.1		$	3.9		$	4.8
Additions based on tax positions related to the current year	8.6			1.6			1.1
Reductions based on tax positions related to the current year	—			—			(1.6		)
Additions for tax positions of prior years	2.3			3.1			0.8
Reductions for tax positions of prior years	(0.3		)	(0.3		)	(1.2		)
Settlements with taxing authorities	(0.2		)	(4.2		)	—
Lapse of applicable statutes of limitations	(1.3		)	—			—
Balance at Dec. 31	$	13.2		$	4.1		$	3.9

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, 2014			Dec. 31, 2013
NOL and tax credit carryforwards	$	(4.8	)	$	(2.4	)

It is reasonably possible that SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals process progresses and state audits resume. As the IRS Appeals process moves closer to completion and state audits resume, 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, 2014, 2013 and 2012 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2014, 2013 or 2012.

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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)	2014		2013
Federal NOL carryforward	$	192.4	$	168.7
Federal tax credit carryforwards	2.1		1.7
State NOL carryforwards	58.5		23.6

The federal carryforward periods expire between 2021 and 2034. The state carryforward periods expire between 2016 and 2034.

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:



	2014		2013		2012
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	3.4		2.0		2.2
Change in unrecognized tax benefits	0.2		0.7		—
Regulatory differences — utility plant items	(1.6	)	(1.1	)	(0.4	)
Tax credits recognized	(0.4	)	(0.4	)	(0.2	)
Other, net	0.1		(0.1	)	0.3
Effective income tax rate	36.7	%	36.1	%	36.9	%

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



(Thousands of Dollars)	2014			2013			2012
Current federal tax expense (benefit)	$	(57,201	)	$	14,947		$	6,549
Current state tax expense	2,512			2,943			2,712
Current change in unrecognized tax benefit	6,715			(263		)	(824		)
Deferred federal tax expense	121,882			33,489			50,189
Deferred state tax expense	8,025			1,754			3,069
Deferred change in unrecognized tax (benefits) expense	(6,390		)	1,232			861
Deferred investment tax credits	(341		)	(341		)	(327		)
Total income tax expense	$	75,202		$	53,761		$	62,229

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



(Thousands of Dollars)	2014			2013			2012
Deferred tax expense excluding items below	$	124,875		$	38,333		$	55,749
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(1,262		)	(1,761		)	(1,533		)
Tax expense allocated to other comprehensive income	(96		)	(97		)	(97		)
Deferred tax expense	$	123,517		$	36,475		$	54,119

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



(Thousands of Dollars)	2014		2013
Deferred tax liabilities:
Differences between book and tax bases of property	$	842,847	$	705,416
Employee benefits	50,696		52,081
Other	28,591		30,066
Total deferred tax liabilities	$	922,134	$	787,563
Deferred tax assets:
NOL carryforward	$	71,956	$	61,330
Rate refund	18,405		17,192
Unbilled revenue - fuel costs	10,866		13,316
Regulatory liabilities	10,794		9,724
Deferred fuel costs	6,006		6,877
Other	6,816		6,708
Total deferred tax assets	$	124,843	$	115,147
Net deferred tax liability	$	797,291	$	672,416


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 66 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2014, SPS had 840 bargaining employees covered under a collective-bargaining agreement, which expired in October 2014. While collective bargaining is ongoing, the terms and conditions of the expired agreement are automatically extended until the parties reach an agreement or a decision is rendered by an arbitrator.

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

In addition to the qualified pension plans, Xcel Energy maintains a supplemental executive retirement plan (SERP) and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides unfunded, nonqualified benefits for compensation that is in excess of the limits applicable to the qualified pension plans. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2014 and 2013 were $46.5 million and $36.5 million, respectively, of which $3.1 million and $2.8 million were attributable to SPS. In 2014 and 2013, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $4.7 million and $6.6 million, respectively, of which $0.2 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. Xcel Energy Inc. and SPS continually review the pension assumptions. The pension cost determination assumes a forecasted mix of investment types over the long-term.


•	Investment returns in 2014 were above the assumed levels of 6.90 percent;


•	Investment returns in 2013 were below the assumed level of 6.49 percent;


•	Investment returns in 2012 were above the assumed level of 6.68 percent; and


•	In 2015, SPS’ expected investment-return assumption is 7.22 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 at Dec. 31 for the upcoming year:



	2014		2013
Domestic and international equity securities	39	%	29	%
Long-duration fixed income and interest rate swap securities	23		36
Short-to-intermediate term fixed income securities	14		14
Alternative investments	22		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, 2014 and 2013:



	Dec. 31, 2014
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	17,181	$	—		$	—	$	17,181
Derivatives	—		748			—		748
Government securities	—		68,058			—		68,058
Corporate bonds	—		46,531			—		46,531
Asset-backed securities	—		494			—		494
Mortgage-backed securities	—		1,451			—		1,451
Common stock	13,439		—			—		13,439
Private equity investments	—		—			18,331		18,331
Commingled funds	—		233,232			—		233,232
Real estate	—		—			6,689		6,689
Securities lending collateral obligation and other	—		(3,885		)	—		(3,885		)
Total	$	30,620	$	346,629		$	25,020	$	402,269



	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

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The following tables present the changes in SPS’ Level 3 pension plan assets for the years ended Dec. 31, 2014, 2013 and 2012:



(Thousands of Dollars)	Jan. 1, 2014		Net Realized Gains (Losses)		Net Unrealized Gains (Losses)			Purchases, Issuances and Settlements, Net			Transfers Out of Level 3		Dec. 31, 2014
Private equity investments	$	18,222	$	3,101	$	(1,894	)	$	(1,098	)	$	—	$	18,331
Real estate	5,755		431		(219		)	722			—		6,689
Total	$	23,977	$	3,532	$	(2,113	)	$	(376	)	$	—	$	25,020



(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

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)	2014			2013
Accumulated Benefit Obligation at Dec. 31	$	458,793		$	402,509

Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	434,307		$	454,184
Service cost	9,184			9,615
Interest cost	20,444			17,908
Actuarial loss (gain)	63,209			(27,185		)
Transfer (to) from other plan	(1,939		)	3,625
Benefit payments	(24,515		)	(23,840		)
Obligation at Dec. 31	$	500,690		$	434,307



(Thousands of Dollars)	2014			2013
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	393,393		$	376,138
Actual return on plan assets	30,159			15,455
Employer contributions	4,869			22,015
Transfer (to) from other plan	(1,637		)	3,625
Benefit payments	(24,515		)	(23,840		)
Fair value of plan assets at Dec. 31	$	402,269		$	393,393

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(Thousands of Dollars)	2014			2013
Funded Status of Plans at Dec. 31:
Funded status ^(a)	$	(98,421	)	$	(40,914	)


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



(Thousands of Dollars)	2014		2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	252,063	$	208,594
Prior service cost	39		93
Total	$	252,102	$	208,687



(Thousands of Dollars)	2014		2013
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	$	14,437	$	15,843
Noncurrent regulatory assets	237,665		192,844
Total	$	252,102	$	208,687



Measurement date	Dec. 31, 2014	Dec. 31, 2013



	2014		2013
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.11	%	4.75	%
Expected average long-term increase in compensation level	3.75		3.75
Mortality table	RP 2014		RP 2000

Mortality — In 2014, the Society of Actuaries published a new mortality table and projection scale that increased the overall life expectancy of males and females. SPS has reviewed its own population through a credibility analysis and adopted the RP 2014 table with modifications based on its population and specific experience.

Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. Required contributions were made in 2012 through 2015 to meet minimum funding requirements.

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


•	$90.0 million in January 2015, of which $11.6 million was attributable to SPS;


•	$130.6 million in 2014, of which $4.9 million was attributable to SPS;


•	$192.4 million in 2013, of which $22.0 million was attributable to SPS; and


•	$198.1 million in 2012, of which $13.1 million was attributable to SPS.

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

Plan Amendments — In 2014 and 2013, there were no plan amendments made which affected the benefit obligation.

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



(Thousands of Dollars)	2014			2013			2012
Service cost	$	9,184		$	9,615		$	8,520
Interest cost	20,444			17,908			19,697
Expected return on plan assets	(26,179		)	(23,970		)	(24,928		)
Amortization of prior service cost	54			870			1,438
Amortization of net loss	13,326			17,148			12,897
Net periodic pension cost	16,829			21,571			17,624
Credits (costs) not recognized due to effects of regulation	3,170			(1,269		)	(4,300		)
Net benefit cost recognized for financial reporting	$	19,999		$	20,302		$	13,324



	2014		2013		2012
Significant Assumptions Used to Measure Costs:
Discount rate	4.75	%	4.00	%	5.00	%
Expected average long-term increase in compensation level	3.75		3.75		4.00
Expected average long-term rate of return on assets	6.90		6.49		6.68

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 $4.1 million, $4.9 million and $4.1 million in 2014, 2013 and 2012, 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 2015 pension cost calculations is 7.22 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 $2.6 million in 2014, $2.4 million in 2013 and $2.3 million in 2012.

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. These assets are invested in a manner consistent with the investment strategy for the pension plan.

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



	2014		2013
Domestic and international equity securities	25	%	41	%
Short-to-intermediate fixed income securities	57		40
Alternative investments	13		13
Cash	5		6
Total	100	%	100	%

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

The following tables present, for each of the fair value hierarchy levels, SPS’ proportionate allocation of the total postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2014 and 2013:



	Dec. 31, 2014
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents ^(a)	$	2,513	$	—		$	—	$	2,513
Derivatives	—		18			—		18
Government securities	—		4,639			—		4,639
Insurance contracts	—		4,807			—		4,807
Corporate bonds	—		5,175			—		5,175
Asset-backed securities	—		345			—		345
Mortgage-backed securities	—		1,074			—		1,074
Commingled funds	—		26,960			—		26,960
Other	—		(175		)	—		(175		)
Total	$	2,513	$	42,843		$	—	$	45,356



	Dec. 31, 2013
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents ^(a)	$	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


^(a)	Includes restricted cash of $0.1 million at Dec. 31, 2014 and 2013.

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For the year ended Dec. 31, 2014 there were no assets transferred in or out of Level 3. The following tables present the changes in SPS’ Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2013 and 2012:



(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

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



(Thousands of Dollars)	2014			2013
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	54,982		$	59,260
Service cost	1,246			1,368
Interest cost	2,572			2,352
Medicare subsidy reimbursements	18			63
Plan participants’ contributions	728			698
Actuarial gain	(11,828		)	(5,215		)
Benefit payments	(3,376		)	(3,544		)
Obligation at Dec. 31	$	44,342		$	54,982



(Thousands of Dollars)	2014			2013
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	46,738		$	46,222
Actual return on plan assets	1,073			3,228
Plan participants’ contributions	728			698
Employer contributions	193			134
Benefit payments	(3,376		)	(3,544		)
Fair value of plan assets at Dec. 31	$	45,356		$	46,738



(Thousands of Dollars)	2014		2013
Funded Status of Plans at Dec. 31:
Funded status ^(a)	$	1,014	$	(8,244	)


^(a)	Amounts are recognized in noncurrent assets and noncurrent liabilities on SPS’ balance sheet as of Dec. 31, 2014 and 2013, respectively.



(Thousands of Dollars)	2014			2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Credit:
Net gain	$	(14,677	)	$	(5,344	)
Prior service credit	(3,432		)	(3,833		)
Total	$	(18,109	)	$	(9,177	)

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(Thousands of Dollars)	2014			2013
Amounts Not Yet Recognized as Components of Net Periodic Benefit Credit Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory liabilities	$	(892	)	$	(319	)
Noncurrent regulatory liabilities	(17,217		)	(8,858		)
Total	$	(18,109	)	$	(9,177	)



Measurement date	Dec. 31, 2014	Dec. 31, 2013



	2014		2013
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	4.08	%	4.82	%
Mortality table	RP 2014		RP 2000
Health care costs trend rate — initial	6.50	%	7.00	%

Effective Jan. 1, 2015, the initial medical trend rate was decreased from 7.0 percent to 6.5 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is four years. Xcel Energy Inc. and SPS base the medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by the retiree medical plan.

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



	One-Percentage Point
(Thousands of Dollars)	Increase		Decrease
APBO	$	4,555	$	(3,834	)
Service and interest components	451		(371		)

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 $17.1 million, $17.6 million and $47.1 million during 2014, 2013 and 2012, respectively, of which $0.2 million, $0.1 million and $4.4 million were attributable to SPS. Xcel Energy expects to contribute approximately $12.8 million during 2015, of which amounts attributable to SPS will be zero.

Plan Amendments — In 2014 and 2013, there were no plan amendments made which affected the benefit obligation.

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



(Thousands of Dollars)	2014			2013			2012
Service cost	$	1,246		$	1,368		$	1,259
Interest cost	2,572			2,352			2,831
Expected return on plan assets	(3,247		)	(3,183		)	(2,701		)
Amortization of transition obligation	—			—			1,545
Amortization of prior service credit	(401		)	(484		)	(148		)
Amortization of net (gain) loss	(321		)	(6		)	1,256
Net periodic postretirement benefit (credit) cost	$	(151	)	$	47		$	4,042



	2014		2013		2012
Significant Assumptions Used to Measure Costs:
Discount rate	4.82	%	4.10	%	5.00	%
Expected average long-term rate of return on assets	7.20		7.11		6.75

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
2015	$	25,988	$	3,166	$	24	$	3,142
2016	27,029		3,171		31		3,140
2017	27,674		3,119		32		3,087
2018	28,896		3,034		30		3,004
2019	29,377		2,992		29		2,963
2020-2024	156,430		14,498		153		14,345


8.	Other (Expense) Income, Net

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



(Thousands of Dollars)	2014			2013			2012
Interest income	$	246		$	663		$	379
Other nonoperating income	183			9			36
Insurance policy expense	(488		)	(532		)	(369		)
Other (expense) income, net	$	(59	)	$	140		$	46


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.

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.

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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, 2014, 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. This could include the purchase or sale of energy or energy-related products and FTRs.

The following table details the gross notional amounts of commodity FTRs at Dec. 31, 2014 and 2013:


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

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

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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, 2014, one of SPS’ eight most significant counterparties for these activities, comprising $15.2 million or 16 percent of this credit exposure, had an investment grade credit rating from Standard & Poor’s, Moody’s or Fitch Ratings. Six of the eight most significant counterparties, comprising $44.4 million or 47 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 $1.7 million or 2 percent of this credit exposure, had credit quality less than investment grade, based on SPS’ internal analysis. All eight 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)	2014			2013			2012
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(1,161	)	$	(1,332	)	$	(1,504	)
After-tax net realized losses on derivative transactions reclassified into earnings	172			171			172
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(989	)	$	(1,161	)	$	(1,332	)

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, 2014, 2013 and 2012.

Changes in the fair value of FTRs resulting in pre-tax net losses of $3.9 million and pre-tax net gains of $9.9 million for the years ended Dec. 31, 2014 and 2013, respectively, were reclassified as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on expected recovery of FTR settlements through fuel and purchased energy cost recovery mechanisms.

FTR settlement losses of $8.2 million were recognized for the year ended Dec. 31, 2014, recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

SPS had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2014, 2013 and 2012. 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 at Dec. 31, 2014:



	Dec. 31, 2014
	Fair Value						Fair Value Total		Counterparty Netting ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting ^(b)			Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	25,774	$	25,774	$	(9,890	)	$	15,884
Total current derivative assets	$	—	$	—	$	25,774	$	25,774	$	(9,890	)	15,884
PPAs ^(a)												7,892
Current derivative instruments												$	23,776
Noncurrent derivative assets
PPAs ^(a)												$	33,164
Noncurrent derivative instruments												$	33,164
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	9,890	$	9,890	$	(9,890	)	$	—
Total current derivative liabilities	$	—	$	—	$	9,890	$	9,890	$	(9,890	)	—
PPAs ^(a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs ^(a)												$	30,643
Noncurrent derivative instruments												$	30,643

^(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, 2014. At Dec. 31, 2014, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2013:



	Dec. 31, 2013
	Fair Value						Fair Value Total		Counterparty Netting ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3		Fair Value Total		Counterparty Netting ^(b)			Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	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)

^(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.

The following table presents the changes in Level 3 commodity derivatives for the years ended Dec. 31, 2014 and 2013:



	Year Ended Dec. 31
(Thousands of Dollars)	2014			2013
Balance at Jan. 1	$	9,933		$	—
Purchases	50,244			9,933
Settlements	(44,283		)	—
Net transactions recorded during the period:
Losses recognized as regulatory assets	(10		)	—
Balance at Dec. 31	$	15,884		$	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 years ended Dec. 31, 2014 and 2013.

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Fair Value of Long-Term Debt

As of Dec. 31, 2014 and 2013, other financial instruments for which the carrying amount did not equal fair value were as follows:



	2014				2013
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,349,691	$	1,572,414	$	1,199,865	$	1,307,035

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, 2014 and 2013, 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 2015 Electric Rate Case — In December 2014, SPS filed a retail electric, non-fuel rate case in Texas with each of its Texas municipalities and the PUCT seeking an overall increase in annual revenue of approximately $64.75 million, or 6.7 percent. The filing is based on an HTY ended June 2014, adjusted for known and measurable changes, an ROE of 10.25 percent, an electric rate base of approximately $1.56 billion and an equity ratio of 53.97 percent.

As part of its request, SPS is seeking a waiver of the PUCT post-test year adjustment rule which would allow for inclusion of $442 million (total company) additional capital investment for the period July 1, 2014 through Dec. 31, 2014.

The following table summarizes the net request:



(Millions of Dollars)	Request
Investment for capital expenditures — post-test year adjustments	$	29.60
Depreciation expense	13.90
Wholesale load reductions	12.00
Purchased power capacity costs	3.20
Other, net	6.05
Total	$	64.75

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


•	Intervenor Direct Testimony — April 1, 2015;


•	Staff Direct Testimony — April 8, 2015;


•	Staff and Intervenor Cross-Rebuttal Testimony — April 22, 2015;


•	Rebuttal Testimony — April 24, 2015; and


•	Evidentiary Hearing — May 11, 2015.

The parties have agreed the rates will be effective June 11, 2015. A PUCT decision is anticipated in the second half of 2015.

Texas 2014 Electric Rate Case — In January 2014, SPS filed a retail electric rate case in Texas seeking a net increase in annual revenue of approximately $52.7 million, or 5.8 percent. The net increase reflected 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. In April 2014, SPS revised its request to a net increase of $48.1 million.

The rate filing was based on an 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 reflected an increase in depreciation expense of approximately $16 million.

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In September 2014, SPS, PUCT staff, and intervenors filed a non-unanimous settlement agreement which would increase SPS’ rates by $37 million, or 3.5 percent, retroactive to June 1, 2014. Starting Oct. 1, 2014, SPS began collecting the rate increase through interim rates subject to refund. SPS expects to recover the rate increase for June through September 2014 through a separate surcharge, for which it has recognized approximately $15.4 million of revenue in 2014.

The settlement includes an ROE of 9.7 percent solely for the purpose of calculating the AFUDC and determining baselines in future filings for the TCRF. In October 2014, the ALJs approved the stipulation and recommended that SPS file to implement the surcharge following the PUCT’s final order.

Although the parties to the settlement agreement have not prepared a calculation of the $37 million increase and do not agree about which specific costs are included, or not, in the agreed settlement revenue requirement, SPS’ reconciliation of its original request to the settlement increase is as follows:



(Millions of Dollars)	Settlement Agreement
Base rate increase request, January 2014	$	81.5
Revisions for updated information	(4.6		)
Revised request, April 2014	76.9
Remove proposed increase in depreciation	(16.0		)
Remove adjustment allocators for certain wholesale load reduction	(12.0		)
Revised amortizations (rate case expenses, pension and other post-employment benefits expense and gain on sale to Lubbock)	(9.0		)
Non-specified settlement adjustments	(2.9		)
Settlement base rate increase	$	37.0

In December 2014, the PUCT approved the settlement and authorized SPS to file to implement the surcharge. In January 2015, SPS filed an application to implement a surcharge of approximately $15.6 million, including interest, to be recovered from March through June 2015, subject to a true-up. A hearing was held in February 2015 and a decision is expected in the first quarter of 2015.

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 was $13 million. The PUCT issued an order allowing the TCRF to go into effect on an interim basis effective Jan. 1, 2014. In May 2014, the ALJ terminated the interim TCRF due to a settlement in principle being reached with intervenors and the PUCT staff in the pending Texas electric rate case. In July 2014, the PUCT approved the settlement agreement between the parties allowing SPS to recover $4 million annually through the TCRF. In September 2014, SPS filed a proposal with the PUCT to refund approximately $3.7 million during November 2014 for interim rates collected in excess of the final rates approved. Under a settlement among the parties, SPS implemented the refund in November 2014, pending PUCT approval. The PUCT approved the refund on Dec. 18, 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 was based on a 2014 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 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. The request reflected 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.

In March 2014, the NMPRC approved an overall increase of approximately $33.1 million. The increase reflects a base rate increase of $12.7 million and rider recovery of $18.1 million for renewable energy costs, both based on an ROE of 9.96 percent and an equity ratio of 53.89 percent. Final rates were effective April 5, 2014. In April 2014, the NMAG filed a request for rehearing. The rehearing request was denied by the NMPRC. In June 2014, the NMAG filed an appeal of the NMPRC’s denial to the New Mexico Supreme Court. A decision is expected by the second quarter of 2016.

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Pending and Recently Concluded Regulatory Proceedings — FERC

Wholesale Rate Complaints — In April 2012, Golden Spread Electric Cooperative, Inc. (Golden Spread), a wholesale cooperative customer, 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. In July 2013, Golden Spread filed a second complaint, again asking that the base ROE in the SPS production and transmission formula rates be reduced to 9.15 and 9.65 percent, respectively.

In June 2014, the FERC issued an order in a different ROE proceeding adopting a new ROE methodology for electric utilities. The new ROE methodology requires electric utilities to use a two-step discounted cash flow analysis to estimate cost of equity that incorporates both short-term and long-term growth projections.

The FERC also issued orders consolidating the Golden Spread ROE complaints and setting them for settlement judge procedures and hearings and indicated the parties should apply the new two-step discounted cash flow ROE methodology to the proceedings. The FERC established effective dates for the refunds as April 20, 2012 and July 19, 2013. Settlement judge procedures were unsuccessful and the complaints were set for hearing procedures, with an initial ALJ decision to be issued by Nov. 25, 2015 and a final FERC order to be issued no earlier than 2016. In January 2015, Golden Spread filed testimony requesting that wholesale production and transmission formula rates be reduced to 8.78 percent and 9.28 percent, respectively, for the period April 20, 2012 to July 18, 2013, and reduced to 8.51 percent and 9.01 percent, respectively, for the period July 19, 2013 to Oct. 19, 2014.

Golden Spread, along with certain New Mexico cooperatives and the West Texas Municipal Power Agency, separately filed a third rate complaint in October 2014, requesting that the base ROE in the SPS production and transmission formula rates be reduced to 8.61 percent and 9.11 percent, respectively. The complainants requested a refund effective date of Oct. 20, 2014. In January 2015, the FERC issued an order setting the third complaint for hearing procedures and granting the complainants’ requested refund effective date.

FERC Complaint Case Orders — In August 2013, the FERC issued an order on rehearing related to a 2004 complaint case brought by Golden Spread and PNM and an Order on Initial Decision in a subsequent 2006 production 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.

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, which are currently pending. As of Dec. 31, 2013, SPS had accrued $44.5 million related to the August 2013 Orders and an additional $5.9 million of principal and interest was accrued during 2014.

On Jan. 30, 2015, SPS filed to revise the production formula rates for six of its wholesale customers, including Golden Spread, effective Feb. 1, 2015. The filing proposes several modifications, including a reduction in wholesale depreciation rates and the use of a 12CP demand-related cost allocator. If approved, principal and interest accruals from the August 2013 Orders would cease as of the effective date. FERC action is pending.

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. In December 2013, SPS received $37.1 million and recognized a pre-tax gain of $13.6 million and regulatory liabilities for jurisdictional gain sharing of $7.2 million. The gain is reflected in the statement of income as a reduction to O&M expenses. In December 2014, Golden Spread submitted a preliminary challenge asserting that the gain should be shared with wholesale transmission customers. SPS has disputed this claim. It is uncertain if the matter will result in a formal proceeding with the FERC.

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Request for Waiver of SPP Tariff — In July 2014, SPS filed a request for the FERC to grant SPS a waiver of an SPP tariff regarding the billing of SPP administrative and transmission expansion charges for certain loads that left the SPS system at the end of 2013 through a sale of transmission assets to Sharyland. Under the SPP tariff provisions, SPP assesses these charges based on prior year load. Absent the waiver, SPS would be billed approximately $2.9 million by SPP in 2014 for loads that are no longer served by SPS. SPP has intervened to oppose the waiver request and Sharyland has intervened to support the waiver request. FERC action is pending.


11.	Commitments and Contingencies

Commitments

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

Transmission NTC — SPS has accepted NTCs for several hundred miles of transmission line and related substation projects based on needs identified through SPP’s various planning processes, including those associated with economics, reliability, generator interconnection or the load addition processes. Most significant is the TUCO to Yoakum County to Hobbs Plant, a 345 KV transmission line. This line will connect the TUCO substation near Lubbock, Texas with the Yoakum County substation, continuing on to the Hobbs Plant substation near Hobbs, N.M. SPS anticipates filing CCNs for this line in Texas and in New Mexico in mid-2015. The line is scheduled to be in service in 2020.

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 2015 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, 2014, are as follows:



(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2015	$	258.0	$	3.3	$	31.0
2016	225.1		—		30.8
2017	114.9		—		22.1
2018	—		—		20.6
2019	—		—		21.5
Thereafter	—		—		95.9
Total	$	598.0	$	3.3	$	221.9

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

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

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Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts, were payments for capacity of $52.4 million, $38.4 million and $36.2 million in 2014, 2013 and 2012, respectively. At Dec. 31, 2014, 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)
2015	$	56.6
2016	57.1
2017	58.3
2018	59.6
2019	19.5
Thereafter	36.1
Total ^(a)	$	287.2


^(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.

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 $63.1 million, $64.2 million and $59.9 million for 2014, 2013 and 2012, respectively. These expenses included capacity payments for PPAs accounted for as operating leases of $57.1 million, $59.0 million and $56.0 million in 2014, 2013 and 2012, respectively, recorded to electric fuel and purchased power expenses.

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



(Millions of Dollars)	Operating Leases		PPA ^{(a) (b)} Operating Leases		Total Operating Leases
2015	$	3.3	$	52.0	$	55.3
2016	3.4		49.0		52.4
2017	2.4		49.0		51.4
2018	2.0		49.0		51.0
2019	1.9		49.0		50.9
Thereafter	11.4		671.8		683.2


^(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.

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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, 2014 and 2013, 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.

Environmental Contingencies

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

Site Remediation — Various federal and state environmental laws impose liability, without regard to the legality of the original conduct, where hazardous substances or other regulated materials have been released to the environment. SPS may sometimes pay all or a portion of the cost to remediate sites where past activities of SPS or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former manufactured gas plants operated by SPS, its predecessors, or other entities; and third-party sites, such as landfills, for which SPS is alleged to be a PRP that sent 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 (CWA) 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. The final rule is now expected in September 2015. 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.

Federal CWA Waters of the United States Rule — In April 2014, the EPA and the U.S. Army Corps of Engineers issued a proposed rule that significantly expands the types of water bodies regulated under the CWA. If finalized as proposed, this rule could delay the siting of new pipelines, transmission lines and distribution lines, increase project costs and expand permitting and reporting requirements. The ultimate impact of the proposed rule will depend on the specific requirements of the final rule and cannot be determined at this time. A final rule is not anticipated before the second quarter of 2015.

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Coal Ash Regulation — SPS’ operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. In 2010, the EPA published a proposed rule on the regulation of coal combustion byproducts (coal ash) as hazardous or nonhazardous waste. The EPA issued a pre-publication version of the final rule in December 2014, which once promulgated will impose new rules to regulate coal ash as a nonhazardous solid waste. SPS’ costs for the management and disposal of coal ash will not significantly increase under the new rule.

Air

GHG Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. Comments were due to the EPA on Dec. 1, 2014 and a final rule is anticipated in mid-summer 2015. Following adoption of the final rule, states must develop implementation plans by June 2016, with the possibility of an extension to June 2017 (June 2018 if submitting a joint plan with other states). Among other things, the proposed rule would require that state plans include enforceable measures to ensure emissions from existing power plants in the state achieve the EPA’s state-specific interim (2020-2029) and final (2030 and thereafter) emission performance targets. The plan will likely require additional emission reductions in states in which SPS operates. It is not possible to evaluate the impact of existing source standards until the EPA promulgates a final rule and states have adopted their applicable state plans.

GHG NSPS Proposal — In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which would set performance standards (maximum carbon dioxide emission rates) for coal- and natural gas-fired power plants. For coal power plants, the NSPS requires an emissions level equivalent to partial carbon capture and storage (CCS) technology; for gas-fired power plants, the NSPS reflects 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. A final rule is anticipated in mid-summer 2015. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.

GHG NSPS for Modified and Reconstructed Power Plants — In June 2014, the EPA published a proposed NSPS that would apply to GHG emissions from power plants that are modified or reconstructed. A final rule is anticipated in mid-summer 2015. A modification is a change to an existing source that increases the maximum achievable hourly rate of emissions. A reconstruction involves the replacement of components at a unit to the extent that the capital cost of the new components exceeds 50 percent of the capital cost of an entirely new comparable unit. The proposed standards would not require installation of CCS technology. Instead, the proposed standard for coal-fired power plants would require a combination of best operating practices and equipment upgrades. The proposal for gas-fired power plants would require emissions standards based on efficient combined cycle technology. It is not possible to evaluate the impact of these proposed standards until the final requirements are known. In addition, it is not clear whether these requirements, once adopted, would apply to future changes at SPS’ power plants.

CSAPR — CSAPR addresses long range transport of PM and ozone by requiring reductions in SO₂ and NOx from utilities in the eastern half of the United States, including Texas, using an emissions trading program.

In August 2012, the D.C. Circuit vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated the EPA must continue administering CSAPR’s predecessor rule pending adoption of a valid replacement. In April 2014, the U.S. Supreme Court reversed and remanded the case to the D.C. Circuit. The Supreme Court held that the EPA’s rule design did not violate the CAA and that states had received adequate opportunity to develop their own plans. Because the D.C. Circuit overturned the CSAPR on two over-arching issues, there are many other issues the D.C. Circuit did not rule on that will now need to be considered on remand. In October 2014, the D.C. Circuit granted the EPA’s request to begin to implement CSAPR by imposing its 2012 compliance obligations starting in January 2015. In addition, the D.C. Circuit set a briefing schedule and plans to hear arguments on the remaining issues in the case in February 2015. While the litigation continues, the EPA will begin to administer the CSAPR in 2015.

Multiple changes to the SPS system since 2011 will substantially reduce estimated costs of complying with the CSAPR. These include the addition of 700 MW of wind power, the construction of Jones Units 3 and 4 to meet reserve requirements and provide quick start capability, reduced wholesale load and new PPAs, installation of NOx combustion controls on Tolk Units 1 and 2 and completion of certain transmission projects. As a result, SPS estimates compliance with the CSAPR in 2015 will cost approximately $7 million.

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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. In 2014, the U.S. Supreme Court decided to review the D.C. Circuit’s decision that upheld the MATS standard. It is not yet known what impact the Supreme Court’s decision may have on the MATS standard or its implementation schedule. 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 — The regional haze program is designed to address widespread, regionally homogeneous haze that results from emissions from a multitude of sources. 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 set emissions limits for those facilities.

Harrington Units 1 and 2 are potentially subject to BART. Texas developed a SIP that finds the CAIR equal to BART for EGUs. As a result, no additional controls beyond CAIR compliance would be required. In 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. In December 2014, the EPA proposed to approve the BART portion of the SIP, with the exception that the EPA would substitute CSAPR compliance for Texas’ reliance on CAIR. The EPA currently plans to issue its final rule in August 2015.

In May 2014, the EPA issued a request for information under the CAA related to SO₂ control equipment at Tolk Units 1 and 2. In its December 2014 proposal, the EPA plans to disapprove the reasonable progress portions of the SIP and instead adopt a Federal Implementation Plan. For SPS, the EPA proposed to require dry scrubbers on both Tolk units to reduce SO₂ emissions to help achieve reasonable progress goals the EPA would establish for Texas and Oklahoma national parks and wilderness areas. As proposed, the dry scrubbers would need to be installed and operating within five years of the EPA’s final action, currently expected in August 2015. SPS plans to file comments objecting to the installation of dry scrubbers on the units. Whether dry scrubbers are required is dependent on the EPA’s final decision. If required, they would cost approximately $600 million, with an annual operating cost of approximately $10.4 million.

Revisions to the 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. In December 2014, the EPA issued its final designations, which did not include areas in any states in which SPS operates.

Revisions to the NAAQS for Ozone — In December 2014, the EPA proposed to revise the NAAQS for ozone by lowering the eight-hour standard from 0.075 parts per million (ppm) to a level within the range of 0.065-0.070 ppm. The EPA is also taking comment on a level for the standard as low as 0.060 ppm. In areas where SPS operates, current monitored air quality concentrations are above the proposed level of 0.070 ppm in the Texas panhandle. The EPA is expected to adopt a new ozone standard in a final rule to be issued in October 2015. Depending on the level of the standard, impacted states would study the sources of the nonattainment and make emission reduction plans to attain the standards. These plans would be due to the EPA in 2020 or 2021. Such plans could include installation of further NOx controls on power plants. It is not possible to evaluate the impact of this proposal until the final standard is adopted, the designation of nonattainment areas is made in late 2017 based on air quality data years 2014-2016, and any required state plans are developed.

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 electric production includes certain plants. This asbestos abatement removal obligation originated in 1973 with the CAA, which applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal. AROs also have been recorded for steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills. The origination dates on the ARO recognition for ash-containment facilities at steam plants were the in-service dates of the various facilities.

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An ARO was recognized for the removal of electric transmission and distribution equipment, which consists of many small potential obligations associated with PCBs, mineral oil, storage tanks, 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.

In December 2014, the EPA issued a pre-publication version of a final rule imposing requirements for activities involving coal ash waste. The ruling, once effective, will not result in the creation of a new legal obligation and SPS’ estimated cash flows for the closure of coal ash landfills and impoundments are not expected to significantly increase as a result of the ruling.

A reconciliation of SPS’ AROs for the years ended Dec. 31, 2014 and 2013 is as follows:



(Thousands of Dollars)	Beginning Balance Jan. 1, 2014		Liabilities Recognized		Accretion		Cash Flow Revisions		Ending Balance Dec. 31, 2014 ^(a)
Electric plant
Steam production asbestos	$	11,608	$	—	$	795	$	4,554	$	16,957
Steam production ash containment	809		—		51		749		1,609
Electric distribution	6,104		—		223		—		6,327
Other	854		136		31		117		1,138
Total liability	$	19,375	$	136	$	1,100	$	5,420	$	26,031


^(a)	There were no ARO liabilities settled during the year ended Dec. 31, 2014.



(Thousands of Dollars)	Beginning Balance Jan. 1, 2013		Liabilities Settled			Accretion		Cash Flow Revisions			Ending Balance Dec. 31, 2013 ^(a)
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


^(a)	There were no new ARO liabilities recognized during the year ended Dec. 31, 2013.

Removal Costs — SPS records a regulatory liability for the plant removal costs of generation, transmission and distribution facilities that are recovered currently in rates. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long time periods over which the amounts were accrued and the changing of rates over time, SPS has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accordingly, the recorded amounts of estimated future removal costs are considered regulatory liabilities. Removal costs as of Dec. 31, 2014 and 2013 were $68 million and $53 million, respectively.

Legal Contingencies

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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. On Jan.16, 2015, Exelon Wind filed motions to dismiss or notices of non-suits for its state and federal lawsuits regarding the QF tariff, and for its state and federal lawsuits and regulatory proceedings regarding the LEOs. Later in January, the PUCT and state and federal courts issued orders dismissing the cases. The only remaining proceedings are pending before the FERC (one regarding the QF Tariff and the other regarding the LEOs).

SPS believes the likelihood of loss in these 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.

The components of regulatory assets shown on the balance sheets of SPS at Dec. 31, 2014 and 2013 are:



(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2014				Dec. 31, 2013
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations ^(a)	7	Various	$	17,256	$	240,980	$	17,382	$	200,158
Recoverable deferred taxes on AFUDC recorded in plant	1	Plant lives	—		36,878		—		31,362
Net AROs ^(b)	11	Plant lives	—		21,689		—		21,382
Conservation programs ^(c)	1	One to six years	3,451		5,020		1,951		7,753
Renewable resources and environmental initiatives	11	One to four years	6,726		5,124		3,428		17,671
Losses on reacquired debt	4	Term of related debt	1,104		2,594		1,225		3,697
Deferred income tax adjustment	1, 6	Typically plant lives	—		302		—		3,375
Recoverable electric energy costs	1	Less than one year	513		—		491		—
Texas Surcharge	10	Less than one year	15,388		—		—		—
Other		Various	7,568		10,718		3,118		5,017
Total regulatory assets			$	52,006	$	323,305	$	27,595	$	290,415


^(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.

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The components of regulatory liabilities shown on the balance sheets of SPS at Dec. 31, 2014 and 2013 are:



(Thousands of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2014				Dec. 31, 2013
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Plant removal costs	11	Plant lives	$	—	$	68,106	$	—	$	53,006
Deferred electric energy costs	1	Less than one year	53,971		—		55,395		—
Contract valuation adjustments ^(a)	1, 9	Term of related contract	20,211		2,521		14,243		6,849
Gain from asset sales	10	Various	2,577		4,468		11,172		4,201
Conservation programs ^(b)	1	Less than one year	1,425		—		1,465		—
Other		Various	9,539		40,093		1,484		17,448
Total regulatory liabilities			$	87,723	$	115,188	$	83,759	$	81,504


^(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, 2014 and 2013, approximately $53 million and $30 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 years ended Dec. 31, 2014 and 2013 were as follows:



	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Year Ended Dec. 31, 2014			Year Ended Dec. 31, 2013
Accumulated other comprehensive loss at Jan. 1	$	(1,161	)	$	(1,332	)
Losses reclassified from net accumulated other comprehensive loss	172			171
Net current period OCI	172			171
Accumulated other comprehensive loss at Dec. 31	$	(989	)	$	(1,161	)

Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2014 and 2013 were as follows:



	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Year Ended Dec. 31, 2014				Year Ended Dec. 31, 2013
Losses on cash flow hedges:
Interest rate derivatives	$	268		^(a)	$	268		^(a)
Total, pre-tax	268				268
Tax benefit	(96		)		(97		)
Total amounts reclassified, net of tax	$	172			$	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.

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



(Thousands of Dollars)	2014		2013		2012
Operating revenues:
Electric	$	23	$	1,331	$	6,539
Operating expenses:
Purchased power	9,614		8,136		9,271
Other operating expenses — paid to Xcel Energy Services Inc.	145,917		127,669		117,277
Interest expense	73		178		76
Interest income	3		—		10

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



	2014				2013
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	1,983	$	—	$	3,462	$	—
NSP-Wisconsin	—		31		—		26
PSCo	—		5,803		—		1,056
Other subsidiaries of Xcel Energy Inc.	—		13,956		12,378		14,305
	$	1,983	$	19,790	$	15,840	$	15,387


15.	Summarized Quarterly Financial Data (Unaudited)



	Quarter Ended
(Thousands of Dollars)	March 31, 2014		June 30, 2014		Sept. 30, 2014		Dec. 31, 2014
Operating revenues	$	448,400	$	492,536	$	552,779	$	443,655
Operating income	42,576		59,000		118,769		45,779
Net income	18,735		28,035		66,937		16,145



	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

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, 2014, 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.

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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, 2014, 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

Item 14 — Principal Accountant Fees and Services

Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2015 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, 2014.
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Statements of Income — For the three years ended Dec. 31, 2014, 2013 and 2012.
	Statements of Comprehensive Income — For the three years ended Dec. 31, 2014, 2013 and 2012.
	Statements of Cash Flows — For the three years ended Dec. 31, 2014, 2013 and 2012.
	Balance Sheets — As of Dec. 31, 2014 and 2013.
	Statements of Common Stockholder’s Equity — For the three years ended Dec. 31, 2014, 2013 and 2012.
	Statements of Capitalization — As of Dec. 31, 2014 and 2013.

2.	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2014, 2013 and 2012.

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*	Third Supplemental Indenture dated Oct. 1, 2003 to the indenture dated Feb. 1, 1999 between SPS and JPMorgan Chase Bank, as successor Trustee, creating $100 million principal amount of Series C and Series D Notes, 6 percent due 2033 (Exhibit 4.04 to Xcel Energy Form 10-Q (file no. 001-03034) for the quarter ended Sept. 30, 2003).
4.03*	Fourth Supplemental Indenture dated Oct. 1, 2006 between SPS and The Bank of New York, as successor Trustee (Exhibit 4.01 to Form 8-K (file no. 001-03789) dated Oct. 3, 2006).
4.04*	Red River Authority for Texas Indenture of Trust dated July 1, 1991 (Form 10-K, Aug. 31, 1991 -Exhibit 4(b)).
4.05*	Fifth Supplemental Indenture dated as of Nov. 1, 2008 between SPS 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)).
4.06*	Indenture dated as of Aug. 1, 2011 between SPS and U.S, Bank National Association, as Trustee (Exhibit 4.01 to Form 8-K dated Aug. 10, 2011 (file no. 001-03789)).
4.07*	Supplemental Indenture dated as of Aug. 3, 2011 between SPS and U.S. Bank National Association, as Trustee, creating $200 million principal amount of 4.50 percent First Mortgage Bonds, Series No. 1 due 2041 (Exhibit 4.02 to Form 8-K dated Aug. 10, 2011 (file no. 001-03789)).
4.08*	Sixth Supplemental Indenture dated as of June 1, 2014 between SPS and The Bank of New York Mellon Trust Company, N.A., as successor Trustee. (Exhibit 4.03 to SPS’ Form 8-K dated June 2, 2014 (file no. 001-03789)).
4.09*	Supplemental Indenture No. 2 dated as of June 1, 2014 between SPS and U.S. Bank National Association, as Trustee. (Exhibit 4.06 to SPS’ Form 8-K dated June 2, 2014 (file no. 001-03789)).
4.10*	Supplemental Indenture No. 3 dated as of June 1, 2014 between SPS and U.S. Bank National Association, as Trustee, creating $150 million principal amount of 3.30 percent First Mortgage Bonds, Series No. 3 due 2024. (Exhibit 4.02 to SPS’ Form 8-K dated June 9, 2014 (file no. 001-03789)).
10.01*+	Xcel Energy Inc. Nonqualified Pension Plan (2009 Restatement) (Exhibit 10.02 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.02*+	Xcel Energy Senior Executive Severance Change-in-Control Policy (2009 Amendment and Restatement) (Exhibit 10.05 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.03*+	Xcel Energy Inc. Non-Employee Directors Deferred Compensation Plan as amended and restated on Jan. 1, 2009 (Exhibit 10.08 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.04*+	Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Form U5B (file no. 001-03034) dated Nov. 16, 2000).
10.05*+	Xcel Energy Inc. Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).

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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. 001-03789) May 14, 1979 — Exhibit 5(B)).
10.09*	Coal Supply Agreement (Tolk Station) between SPS and TUCO dated April 30, 1979, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q for the quarter ended Feb. 28, 1982 (file no. 001-03789) — Exhibit 10(b)).
10.10*	Master Coal Service Agreement between Wheelabrator Coal Services Co. and TUCO dated Dec. 30, 1981, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q fo4r the quarter ended Feb. 28, 1982 (file no. 001-03789) — Exhibit 10(c)).
10.11*	Power Purchase Agreement dated May 23, 1997 between Borger Energy Associates, L.P, and SPS.
10.12*+	Amendment 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 Inc. Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix A to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).
10.15*+	Xcel Energy Inc. 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 Inc. 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix B to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).
10.17*+	Xcel Energy Inc. 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 Inc. 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 Inc. 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 Inc. 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 Inc. 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 Inc. as amended and restated effective Feb. 23, 2011 (Appendix A to the Xcel Energy Definitive Proxy Statement (file no. 001-03034) filed Apr. 5, 2011).
10.22*+	Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.07 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.23*+	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*+	First Amendment effective Nov. 29, 2011 to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011).
10.25*+	First Amendment dated Feb. 20, 2013 to the Xcel Energy Inc. Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended March 31, 2013).
10.26*+	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).
10.27*+	First Amendment dated May 21, 2013 to the Xcel Energy Inc. 2005 Long Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.21 to Form 10-Q 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. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.22 to Form 10-Q of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013).
10.29*+	Xcel Energy Inc. 2005 Long-Term Incentive Plan Form of Long-Term Incentive Award Agreement (Exhibit 10.23 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013).

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10.30*	Amended and Restated Credit Agreement, dated as of Oct. 14, 2014 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 (Exhibit 99.04 to Form 8-K of Xcel Energy, dated Oct. 14, 2014 (file no. 001-03034)).
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, 2014 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, 2014, 2013 AND 2012

(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:
2014	$	5,475	$	4,137	$	1,089	$	4,862	$	5,839
2013	4,722		3,437		1,076		3,760		5,475
2012	5,380		2,915		1,202		4,775		4,722


^(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. 23, 2015		/s/ TERESA S. MADDEN
		Teresa S. Madden
		Executive Vice President, Chief Financial Officer and Director
		(Principal Financial Officer)

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



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

/s/ TERESA S. MADDEN		/s/ JEFFREY S. SAVAGE
Teresa S. Madden		Jeffrey S. Savage
Executive Vice President, Chief Financial Officer and Director		Senior Vice President, Controller
(Principal Financial Officer)		(Principal Accounting Officer)

/s/ MARVIN E. MCDANIEL, JR.
Marvin E. McDaniel, Jr.
Director

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

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

(Amounts in Thousands) ^(a)

Dec. 31, 2014

Dec. 31, 2013

MWh of electricity