SPS 10Q 3.31.2014

(Amounts in Thousands) ^(a)

March 31, 2014

Dec. 31, 2013

Megawatt hours of electricity

10-Q 1 sps10q3312014.htm 10-Q SPS 10Q 3.31.2014

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended March 31, 2014



¨	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)		(Zip Code)

(303) 571-7511

(Registrant’s telephone number, including area code)

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

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

Indicate by check mark 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 ¨		Accelerated filer ¨
Non-accelerated filer x		Smaller reporting company ¨
(Do not check if smaller reporting company)

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.



Class		Outstanding at May 5, 2014
Common Stock, $1 par value		100 shares

Southwestern Public Service Company meets the conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H (2) to such Form 10-Q.

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PART I — FINANCIAL INFORMATION
Item l —	Financial Statements (Unaudited)	3
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 4 —	Controls and Procedures	22

PART II — OTHER INFORMATION
Item 1 —	Legal Proceedings	23
Item 1A —	Risk Factors	23
Item 4 —	Mine Safety Disclosures	23
Item 5 —	Other Information	23
Item 6 —	Exhibits	23

SIGNATURES		24

Certifications Pursuant to Section 302		1
Certifications Pursuant to Section 906		1
Statement Pursuant to Private Litigation		1

This Form 10-Q is filed by Southwestern Public Service Company, a New Mexico corporation (SPS). SPS is a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. wholly owns the following subsidiaries: Northern States Power Company, a Minnesota corporation (NSP-Minnesota); Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado, a Colorado corporation (PSCo); and SPS. NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are also referred to collectively as utility subsidiaries. Additional information on Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) is available on various filings with the Securities and Exchange Commission (SEC).

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PART 1 — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands)



	Three Months Ended March 31
	2014			2013
Operating revenues	$	448,400		$	374,257

Operating expenses
Electric fuel and purchased power	289,204			231,234
Operating and maintenance expenses	69,398			64,570
Demand side management program expenses	3,064			3,040
Depreciation and amortization	30,512			30,205
Taxes (other than income taxes)	13,646			12,149
Total operating expenses	405,824			341,198

Operating income	42,576			33,059

Other income (expense), net	41			(48		)
Allowance for funds used during construction — equity	3,640			2,622

Interest charges and financing costs
Interest charges — includes other financing costs of $730 and $736, respectively	19,281			17,773
Allowance for funds used during construction — debt	(2,127		)	(1,609		)
Total interest charges and financing costs	17,154			16,164

Income before income taxes	29,103			19,469
Income taxes	10,368			6,885
Net income	$	18,735		$	12,584

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)



	Three Months Ended March 31
	2014		2013
Net income	$	18,735	$	12,584
Other comprehensive income
Derivative instruments:
Reclassification of losses to net income, net of tax of $24 for each of the three months ended March 31, 2014 and 2013	43		42
Other comprehensive income	43		42
Comprehensive income	$	18,778	$	12,626

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)



	Three Months Ended March 31
	2014			2013
Operating activities
Net income	$	18,735		$	12,584
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	31,059			30,724
Demand side management program amortization	418			418
Deferred income taxes	22,166			10,433
Amortization of investment tax credits	(85		)	(82		)
Allowance for equity funds used during construction	(3,640		)	(2,622		)
Net derivative losses	66			66
Changes in operating assets and liabilities:
Accounts receivable	12,526			4,777
Accrued unbilled revenues	(2,413		)	(7,384		)
Inventories	5,131			6,856
Prepayments and other	(15,455		)	(10,870		)
Accounts payable	9,454			11,987
Net regulatory assets and liabilities	(16,994		)	(7,047		)
Other current liabilities	3,908			6,556
Pension and other employee benefit obligations	(3,513		)	(20,739		)
Change in other noncurrent assets	2,951			(2,593		)
Change in other noncurrent liabilities	1,758			(2,683		)
Net cash provided by operating activities	66,072			30,381

Investing activities
Utility capital/construction expenditures	(137,637		)	(106,376		)
Allowance for equity funds used during construction	3,640			2,622
Investments in utility money pool arrangement	(10,000		)	(12,000		)
Repayments from utility money pool arrangement	10,000			12,000
Net cash used in investing activities	(133,997		)	(103,754		)

Financing activities
(Repayments of) proceeds from short-term borrowings, net	(15,000		)	7,000
Borrowings under utility money pool arrangement	231,000			49,000
Repayments under utility money pool arrangement	(169,000		)	(29,000		)
Capital contributions from parent	40,000			65,000
Dividends paid to parent	(18,082		)	(16,773		)
Net cash provided by financing activities	68,918			75,227

Net change in cash and cash equivalents	993			1,854
Cash and cash equivalents at beginning of period	1,011			482
Cash and cash equivalents at end of period	$	2,004		$	2,336

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(7,570	)	$	(5,171	)
Cash (paid) received for income taxes, net	(2,522		)	1,015
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	30,938		$	31,586

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE COMPANY

BALANCE SHEETS (UNAUDITED)

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



	March 31, 2014			Dec. 31, 2013
Assets
Current assets
Cash and cash equivalents	$	2,004		$	1,011
Accounts receivable, net	67,734			70,951
Accounts receivable from affiliates	6,531			15,840
Accrued unbilled revenues	111,620			109,207
Inventories	32,007			37,138
Regulatory assets	30,416			27,595
Derivative instruments	13,684			17,826
Deferred income taxes	69,655			85,362
Prepayments and other	35,026			19,571
Total current assets	368,677			384,501

Property, plant and equipment, net	3,395,274			3,284,030

Other assets
Regulatory assets	282,654			290,415
Derivative instruments	39,083			41,056
Other	14,671			17,068
Total other assets	336,408			348,539
Total assets	$	4,100,359		$	4,017,070

Liabilities and Equity
Current liabilities
Short-term debt	$	69,000		$	84,000
Borrowings under utility money pool arrangement	100,000			38,000
Accounts payable	162,544			143,879
Accounts payable to affiliates	13,809			15,387
Regulatory liabilities	60,633			83,759
Taxes accrued	16,262			23,584
Accrued interest	25,853			16,883
Dividends payable	18,181			18,082
Derivative instruments	3,574			3,583
Other	77,036			75,355
Total current liabilities	546,892			502,512

Deferred credits and other liabilities
Deferred income taxes	765,720			757,778
Regulatory liabilities	74,258			81,504
Asset retirement obligations	19,644			19,375
Derivative instruments	33,316			34,207
Pension and employee benefit obligations	51,574			55,087
Other	4,730			3,051
Total deferred credits and other liabilities	949,242			951,002

Commitments and contingencies
Capitalization
Long-term debt	1,199,937			1,199,865
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at March 31, 2014 and Dec. 31, 2013, respectively	—			—
Additional paid in capital	1,045,463			1,005,463
Retained earnings	359,943			359,389
Accumulated other comprehensive loss	(1,118		)	(1,161		)
Total common stockholder’s equity	1,404,288			1,363,691
Total liabilities and equity	$	4,100,359		$	4,017,070

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE COMPANY

Notes to Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of SPS as of March 31, 2014, and Dec. 31, 2013; the results of its operations, including the components of net income and comprehensive income, for the three months ended March 31, 2014 and 2013; and its cash flows for the three months ended March 31, 2014 and 2013. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2014 up to the date of issuance of these financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2013 balance sheet information has been derived from the audited 2013 financial statements included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2013. These notes to the financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the financial statements and notes thereto included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2013, filed with the SEC on Feb. 24, 2014. Due to the seasonality of SPS’ electric sales, interim results are not necessarily an appropriate base from which to project annual results.


1.	Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the financial statements in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2013, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.


2.	Accounting Pronouncements

Recently issued accounting pronouncements that have been adopted in the current period did not materially impact the financial statements, and no material impact is expected from accounting pronouncements issued and pending implementation.


3.	Selected Balance Sheet Data



(Thousands of Dollars)	March 31, 2014			Dec. 31, 2013
Accounts receivable, net
Accounts receivable	$	73,543		$	76,426
Less allowance for bad debts	(5,809		)	(5,475		)
	$	67,734		$	70,951



(Thousands of Dollars)	March 31, 2014		Dec. 31, 2013
Inventories
Materials and supplies	$	24,011	$	21,600
Fuel	7,996		15,538
	$	32,007	$	37,138



(Thousands of Dollars)	March 31, 2014			Dec. 31, 2013
Property, plant and equipment, net
Electric plant	$	4,789,975		$	4,714,398
Construction work in progress	445,751			388,323
Total property, plant and equipment	5,235,726			5,102,721
Less accumulated depreciation	(1,840,452		)	(1,818,691		)
	$	3,395,274		$	3,284,030


4.	Income Taxes

Except to the extent noted below, the circumstances set forth in Note 6 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2013 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

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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 June 2015. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of March 31, 2014, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $10 million of income tax expense for the 2009 through 2011 claims and the anticipated claim for 2013. SPS is not expected to accrue any income tax expense related to this adjustment. Xcel Energy is continuing to work through the audit process, but the outcome and timing of a resolution is uncertain.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of March 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 effective tax rate (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)	March 31, 2014		Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions	$	0.2	$	1.2
Unrecognized tax benefit — Temporary tax positions	2.3		2.9
Total unrecognized tax benefit	$	2.5	$	4.1

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



(Millions of Dollars)	March 31, 2014			Dec. 31, 2013
NOL and tax credit carryforwards	$	(1.3	)	$	(2.4	)

It is reasonably possible that SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. As the IRS examination moves closer to completion, the change in the unrecognized tax benefit is not expected to be material.

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 March 31, 2014 and Dec. 31, 2013 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2014 or Dec. 31, 2013.


5.	Rate Matters

Except to the extent noted below, the circumstances set forth in Note 10 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2013 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Pending Regulatory Proceedings — Public Utility Commission of Texas (PUCT)

Texas 2014 Electric Rate Case — In January 2014, SPS filed a retail electric rate case in Texas with each of its Texas municipalities and the PUCT for a net increase in annual revenue of approximately $52.7 million, or 5.8 percent. The net increase reflected a base rate increase, revenue credits transferred from base rates to rate riders or the fuel clause, and resetting the Transmission Cost Recovery Factor (TCRF) to zero when the final base rates become effective.

The rate filing was based on a historic test year ending June 2013, a requested return on equity (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 April 2014, SPS revised its requested rate increase to approximately $48.1 million, or 5.3 percent, based on updated information. The following table summarizes SPS’ revised request:



(Millions of Dollars)	SPS Request
Adjusted base rate increase	$	76.9
Resetting TCRF	(12.9		)
Credit to customers for gain on sale to Lubbock moved to a rider	(4.9		)
Adjusted net increase in base revenue	59.1
Fuel clause offsets	(11.0		)
Adjusted retail customer net bill impact	$	48.1

The PUCT has suspended SPS’ proposed rates through Oct. 31, 2014. If the PUCT has not issued a final order by July 11, 2014, then SPS’ current rates will not change, but final rates, when approved by the PUCT, will be made effective retroactive to July 12, 2014. SPS, intervenors and other parties have commenced settlement negotiations.

Next steps in the procedural schedule are as follows:


•	Intervenor testimony — May 22, 2014;


•	PUCT Staff testimony — May 29, 2014;


•	Cross-rebuttal testimony — June 12, 2014;


•	Rebuttal testimony — June 16, 2014;


•	Evidentiary hearing — June 25, 2014; and


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

Electric, Purchased Gas and Resource Adjustment Clauses

TCRF Rider — In November 2013, SPS filed with the PUCT to implement the TCRF for Texas retail customers. The requested increase in revenues is $13 million. The PUCT issued an order allowing the TCRF to go into effect on an interim basis effective Jan. 1, 2014. In April and May 2014, several parties including both intervenors and the PUCT Staff filed testimony recommending various reductions or modifications to the proposed TCRF.

Next steps in the procedural schedule are as follows:


•	SPS Rebuttal testimony — May 8, 2014; and


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

Recently Concluded Regulatory Proceedings — New Mexico Public Regulation Commission (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 forecast test year, 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. This reflects a base and fuel increase of $20.9 million, an increase of rider revenue of $12.1 million and a decrease to other of $0.5 million.

In March 2014, the NMPRC approved an overall increase of approximately $33.1 million. The increase includes: an ROE of 9.96 percent, an equity ratio of 53.89 percent, allowance of the prepaid pension asset in rate base of approximately $2.4 million, allowance of certain non-labor operating and maintenance (O&M) escalations and recovery of approximately $18.1 million of renewable energy costs through rider revenue instead of base revenue. As a result of a change in the amount of fuel costs recovered through base rates, SPS will no longer be required to credit customers for $2.3 million through the fuel clause adjustment (FCA). Final rates were effective April 5, 2014. On April 25, 2014, the New Mexico Attorney General filed a request for rehearing. The rehearing request is pending with the NMPRC, which has until May 15, 2014 to grant or deny the request.

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The following table summarizes the NMPRC’s approval from SPS’ revised request:



(Millions of Dollars)	NMPRC Approval
SPS revised request, September 2013	$	32.5
Fuel clause adjustment credit — non-renewable energy costs	2.3
SPS revised request, fuel adjusted	34.8
ROE (9.96 percent)	(1.2		)
Rate rider adjustment — renewable energy costs	6.0
Base rate reduction for rate rider — renewable energy costs	(6.0		)
Other, net	(0.5		)
Approved increase, March 2014	$	33.1

Means of recovery:
Base revenue	$	12.7
Rider revenue	18.1
Fuel clause	2.3
	$	33.1

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

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

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

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

As of Dec. 31, 2013, SPS had accrued $44.5 million related to these case orders and an additional $1.9 million of principal and interest was accrued during the first quarter of 2014. Pending the timing and resolution of this matter, the annual impact to revenues through 2014 could be up to $6 million and decreasing to $4 million on June 1, 2015.

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

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


6.	Commitments and Contingencies

Except to the extent noted below and in Note 5, the circumstances set forth in Notes 10 and 11 to the financial statements in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2013, appropriately represent, in all material respects, the current status of commitments and contingent liabilities and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to SPS’ financial position.

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Purchased Power Agreements (PPAs)

Under certain PPAs, SPS purchases power from independent power producing entities that own natural gas fueled power plants 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 had approximately 827 megawatts (MW) of capacity under long-term PPAs as of each of March 31, 2014 and Dec. 31, 2013 with entities that have been determined to be variable interest entities. 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. These agreements have expiration dates through the year 2033.

Indemnification Agreements

In connection with the sale of certain Texas electric transmission assets to Sharyland Distribution and Transmission Services, LLC in 2013, SPS agreed to indemnify the purchaser for losses arising out of any breach of the representations, warranties and covenants under the related asset purchase agreement and for losses arising out of certain other matters, including pre-closing liabilities. SPS’ indemnification obligation is capped at $37.1 million, in the aggregate. The indemnification provisions for most representations and warranties expire in December 2014. The remaining representations and warranties, which relate to due organization and transaction authorization, survive indefinitely. As of March 31, 2014 and Dec. 31, 2013, SPS has recorded a $0.4 million liability related to this indemnity.

Environmental Contingencies

Environmental Requirements

Water and waste

Federal Clean Water Act Effluent Limitations Guidelines (ELG) — In June 2013, the U.S. Environmental Protection Agency (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.

Air

Cross-State Air Pollution Rule (CSAPR) — In 2011, the EPA issued the CSAPR to address long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO₂) and nitrous oxide (NOx) from utilities in the eastern half of the United States, including Texas. The CSAPR would set more stringent requirements than the proposed Clean Air Transport Rule and require plants in Texas to reduce their SO₂ and annual NOx emissions. The rule would also create an emissions trading program.

In August 2012, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated the EPA must continue administering the Clean Air Interstate Rule (CAIR) 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 Court held that the EPA’s rule design did not violate the Clean Air Act 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. Because it is not yet known how the litigation over the remaining issues will be resolved, it is not yet known what requirements may be imposed in the future, or their timing.

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

CAIR — In 2005, the EPA issued the CAIR to further regulate SO₂ and NOx emissions. Under the CAIR’s cap and trade structure, companies can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems. In the SPS region, installation of low-NOx combustion control technology was completed in 2012 on Tolk Unit 1. SPS plans to install the same combustion control technology on Tolk Unit 2 in the second quarter of 2014. These installations will reduce or eliminate SPS’ need to purchase NOx emission allowances. SPS had sufficient SO₂ allowances to comply with the CAIR in 2013 and has sufficient allowances through 2015. At March 31, 2014, the estimated annual CAIR NOx allowance cost for SPS did not have a material impact on the results of operations, financial position or cash flows.

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Regional Haze Rules — In 2005, the EPA amended the best available retrofit technology (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 state implementation plan (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 electric generating units (EGUs). As a result, no additional controls beyond CAIR compliance would be required. In May 2012, the EPA deferred its review of the SIP in its final rule allowing states to find that CSAPR compliance meets BART requirements for EGUs. It is not yet known how the U.S. Supreme Court’s April 2014 decision on the CSAPR may impact the EPA’s approval of the SIP.

Legal Contingencies

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

Employment, Tort and Commercial Litigation

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


7.	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 March 31, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	100		$	100
Amount outstanding at period end	100			38
Average amount outstanding	30			46
Maximum amount outstanding	100			100
Weighted average interest rate, computed on a daily basis	0.21		%	0.15		%
Weighted average interest rate at period end	0.21			0.25

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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 March 31, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	300		$	300
Amount outstanding at period end	69			84
Average amount outstanding	103			32
Maximum amount outstanding	158			140
Weighted average interest rate, computed on a daily basis	0.25		%	0.30		%
Weighted average interest rate at period end	0.24			0.27

Letters of Credit — SPS may use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At March 31, 2014 and Dec. 31, 2013, there were $21.0 million and $25.5 million letters of credit outstanding, respectively, under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

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

At March 31, 2014, SPS had the following committed credit facility available (in millions):



Credit Facility ^(a)		Drawn ^(b)		Available
$	300.0	$	90.0	$	210.0


^(a)	Credit facility expires in July 2017.


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

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. SPS had no direct advances on the credit facility outstanding at March 31, 2014 and Dec. 31, 2013.


8.	Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

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

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

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

Specific valuation methods include the following:

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

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

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

Electric commodity derivatives held by SPS include transmission congestion instruments purchased from the Southwest Power Pool, Inc. (SPP), generally referred to as financial transmission rights (FTRs). FTRs purchased from a regional transmission organization (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 March 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, as well as for trading purposes. 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 March 31, 2014 and Dec. 31, 2013:


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

Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were $0.1 million for each of the three months ended March 31, 2014 and 2013.

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During the three months ended March 31, 2014, changes in the fair value of FTRs resulting in pre-tax net losses of $1.4 million were recognized as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on expected recovery of FTR settlements through fuel and purchased energy cost recovery mechanisms.

FTR settlement gains of $2.8 million were recognized for the three months ended March 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 three months ended March 31, 2014 and 2013. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

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

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

SPS’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity and transmission activities. At March 31, 2014, three of SPS’ 10 most significant counterparties for these activities, comprising $16.4 million or 17 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. The remaining seven significant counterparties, comprising $46.6 million or 48 percent of this credit exposure, were not rated by these agencies, but based on SPS’ internal analysis, had credit quality consistent with investment grade. All 10 of these significant counterparties are RTOs, municipal or cooperative electric entities or other utilities.

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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 March 31, 2014:



	March 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	$	—	$	—	$	10,433	$	10,433	$	(4,642	)	$	5,791
Total current derivative assets	$	—	$	—	$	10,433	$	10,433	$	(4,642	)	5,791
PPAs ^(a)												7,893
Current derivative instruments												$	13,684
Noncurrent derivative assets
PPAs ^(a)												$	39,083
Noncurrent derivative instruments												$	39,083
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	4,642	$	4,642	$	(4,642	)	$	—
Total current derivative liabilities	$	—	$	—	$	4,642	$	4,642	$	(4,642	)	—
PPAs ^(a)												3,574
Current derivative instruments												$	3,574
Noncurrent derivative liabilities
PPAs ^(a)												$	33,316
Noncurrent derivative instruments												$	33,316

^(a)

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

^(b)

SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2014. At March 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 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 three months ended March 31, 2014, and there were no Level 3 commodity derivatives during the three months ended March 31, 2013:



(Thousands of Dollars)	2014
Balance at Jan. 1	$	9,933
Purchases	1,056
Settlements	(1,101		)
Net transactions recorded during the period:
Losses recognized as regulatory assets and liabilities	(4,097		)
Balance at March 31	$	5,791

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 three months ended March 31, 2014 and 2013.

Fair Value of Long-Term Debt

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



	March 31, 2014				Dec. 31, 2013
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,199,937	$	1,361,503	$	1,199,865	$	1,307,035

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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 March 31, 2014 and Dec. 31, 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.


9.	Other Income (Expense), Net

Other income (expense), net consisted of the following:



	Three Months Ended March 31
(Thousands of Dollars)	2014			2013
Interest income	$	187		$	113
Other nonoperating income	—			3
Insurance policy expense	(144		)	(164		)
Other nonoperating expense	(2		)	—
Other income (expense), net	$	41		$	(48	)


10.	Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)



	Three Months Ended March 31
	2014			2013			2014			2013
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,296		$	2,404		$	312		$	342
Interest cost	5,111			4,477			643			588
Expected return on plan assets	(6,545		)	(5,993		)	(812		)	(796		)
Amortization of prior service cost (credit)	14			218			(100		)	(121		)
Amortization of net loss (gain)	3,332			4,287			(80		)	(2		)
Net periodic benefit cost (credit)	4,208			5,393			(37		)	11
Credits (costs) not recognized due to the effects of regulation	707			(1,075		)	—			—
Net benefit cost (credit) recognized for financial reporting	$	4,915		$	4,318		$	(37	)	$	11

In January 2014, contributions of $130.0 million were made across three of Xcel Energy’s pension plans, of which $4.4 million was attributable to SPS. Xcel Energy does not expect additional pension contributions during 2014.


11.	Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three months ended March 31, 2014 and 2013 were as follows:



	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended March 31, 2014			Three Months Ended March 31, 2013
Accumulated other comprehensive loss at Jan. 1	$	(1,161	)	$	(1,332	)
Losses reclassified from net accumulated other comprehensive loss	43			42
Net current period other comprehensive income	43			42
Accumulated other comprehensive loss at March 31	$	(1,118	)	$	(1,290	)

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Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2014 and 2013 were as follows:



	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended March 31, 2014				Three Months Ended March 31, 2013
Losses on cash flow hedges:
Interest rate derivatives	$	67		^(a)	$	66		^(a)
Total, pre-tax	67				66
Tax benefit	(24		)		(24		)
Total amounts reclassified, net of tax	$	43			$	42


^(a)	Included in interest charges.

Item 2 — 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 H (1) (a) and (b) of Form 10-Q for wholly owned subsidiaries. It is replaced with management’s narrative analysis of the results of operations set forth in general instructions H (2) (a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format).

Financial Review

The following discussion and analysis by management focuses on those factors that had a material effect on SPS’ financial condition, results of operations, and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited financial statements and the related notes to the financial statements. Due to the seasonality of SPS’ electric sales, such interim results are not necessarily an appropriate base from which to project annual results.

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of SPS to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where SPS has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by SPS; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric market; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee work force factors; and the other risk factors listed from time to time by SPS in reports filed with the SEC, including “Risk Factors” in Item 1A of SPS’ Form 10-K for the year ended Dec. 31, 2013, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended March 31, 2014.

Results of Operations

SPS’ net income was approximately $18.7 million for the three months ended March 31, 2014, compared with net income of approximately $12.6 million for the same period in 2013. The increase was primarily due to the positive impact of higher electric rates and interim transmission rider revenue in Texas, partially offset by increased O&M expenses.

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Electric Revenues and Margin

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. The design of 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 tables detail the electric revenues and margin:



	Three Months Ended March 31
(Millions of Dollars)	2014			2013
Electric revenues	$	448		$	374
Electric fuel and purchased power	(289		)	(231		)
Electric margin	$	159		$	143

The following tables summarize the components of the changes in electric revenues and electric margin for the three months ended March 31:

Electric Revenues



(Millions of Dollars)	2014 vs. 2013
Fuel and purchased power cost recovery	$	41
Transmission revenue	11
Retail rate increase (Texas)	10
Trading	5
Demand revenue	4
Estimated impact of weather	3
Retail sales growth	2
Firm wholesale	(3		)
Other, net	1
Total increase in electric revenues	$	74

Electric Margin



(Millions of Dollars)	2014 vs. 2013
Retail rate increase (Texas)	$	10
Transmission revenue, net of costs	4
Demand revenue	4
Estimated impact of weather	3
Retail sales growth	2
Firm wholesale	(4		)
Other, net	(3		)
Total increase in electric margin	$	16

Non-Fuel Operating Expense and Other Items

O&M Expenses — O&M expenses increased $4.8 million, or 7.5 percent, for the three months ended March 31, 2014 compared with the same period in 2013. The following table summarizes the changes in O&M expenses:



(Millions of Dollars)	2014 vs. 2013
Employee benefits	$	2
Electric distribution costs	1
Plant generation costs	1
Other, net	1
Total increase in O&M expenses	$	5

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Depreciation and Amortization — Depreciation and amortization increased $0.3 million, or 1.0 percent, for the three months ended March 31, 2014 compared with the same period in 2013. The increase is primarily due to normal system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $1.5 million, or 12.3 percent, for the three months ended March 31, 2014 compared with the same period in 2013. The increase is primarily due to an increase in property taxes in Texas.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC increased $1.5 million for the three months ended March 31, 2014 compared with the same period in 2013. The increase is primarily due to the expansion of transmission facilities.

Interest Charges — Interest charges increased $1.5 million, or 8.5 percent, for the three months ended March 31, 2014 compared with the same period in 2013. The increase is primarily due to higher long-term debt levels, partially offset by lower interest rates.

Income Taxes — Income tax expense increased $3.5 million for the three months ended March 31, 2014 compared with the same period in 2013. The increase in income tax expense was primarily due to higher pretax earnings in 2014. The ETR was 35.6 percent for the three months ended March 31, 2014, compared with 35.4 percent for the same period in 2013.

Public Utility Regulation

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

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, accounting practices and certain other activities of SPS, including enforcement of North American Electric Reliability Corporation (NERC) mandatory electric reliability standards. State and local agencies have jurisdiction over many of SPS’ activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2013. In addition to the matters discussed below, see Note 5 to the financial statements for a discussion of other regulatory matters.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) — In 2011, the FERC issued Order 1000 adopting new requirements for transmission planning, cost allocation and development to be effective prospectively. In Order 1000, the FERC required utilities to develop tariffs that provide for joint regional transmission planning and cost allocation for all FERC-jurisdictional utilities within a region. In addition, Order 1000 required that regions coordinate to develop interregional plans for transmission planning and cost allocation. A key provision of Order 1000 is a requirement that FERC-jurisdictional wholesale transmission tariffs exclude provisions that would grant the incumbent transmission owner a federal Right of First Refusal (ROFR) to build certain types of transmission projects in its service area. Various parties appealed Order 1000 final rules to the D.C. Circuit Court of Appeals. The date for a Court decision in the appeal is uncertain.

The removal of a federal ROFR would eliminate rights that SPS currently has under the SPP tariff to build certain transmission projects within their footprints. Rather, the FERC required that the opportunity to build such projects would extend to competitive transmission developers. Compliance with Order 1000 for SPS will occur through the SPP tariff. SPP made its initial compliance filings to incorporate new provisions into its tariffs regarding regional planning and cost allocation.

Transmission-only subsidiaries (TransCo)

Xcel Energy anticipates forming a TransCo that could bid for projects subject to a competitive bidding process in SPP.

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SPS

The FERC issued its initial order on SPP’s Order 1000 regional compliance filing in July 2013. The FERC identified several areas that will require a further compliance filing by SPP to address regional compliance issues. Among other things, the FERC rejected SPP’s proposal to retain a ROFR for new transmission projects with operational voltages between 100 KV and 300 KV. Requests for rehearing of the FERC’s July 2013 order were filed in August 2013 and are pending the FERC’s action. The further SPP regional compliance filing was filed in November 2013. The SPP regional compliance tariffs went into effect March 1, 2014, subject to the outcome of the additional FERC proceedings. The SPP interregional compliance filing was submitted in July 2013 and is pending the FERC’s action. With respect to ROFR rights of incumbent utilities, Xcel Energy believes that Texas statutes protect the right of incumbent utilities operating outside of ERCOT to construct and own transmission interconnected to their systems, though this view is disputed by some parties. The State of New Mexico does not have legislation protecting ROFR rights for incumbent utilities.

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. Xcel Energy is currently in the process of evaluating the new requirements and identifying initiatives needed to meet the compliance deadlines. Compliance is anticipated to require activities across the organization, including Business Systems, Transmission, Energy Supply and Security Services.

On March 7, 2014, FERC issued an order directing NERC to develop a new critical infrastructure protection standard related to physical security. The order directs NERC to file this standard for approval with FERC within 90 days. NERC has prepared a draft of the proposed standard for industry review and comment. The NERC Board of Trustees will consider industry input and votes on the standards and submit a final standard to FERC no later than June 5, 2014. Xcel Energy is participating in the standard development process and will submit its comments on the proposal to NERC. Xcel Energy is also in the process of evaluating the potential impact on the company as the standard is being developed.

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 March 2014, FERC issued an order setting all of the cases for settlement judge proceedings, or hearings if settlement fails. The Xcel Energy utilities have intervened in the various dockets, arguing that non-firm use by MISO should not be subject to SPP transmission charges. 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. The settlement judge process began in April 2014.

Item 4 — 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 March. 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.

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.

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Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

Additional Information

See Note 6 to the financial statements for further discussion of legal claims and environmental proceedings. See Note 5 to the financial statements for discussion of proceedings involving utility rates and other regulatory matters.

Item 1A — RISK FACTORS

SPS’ risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2013, which is incorporated herein by reference.

Item 4 — MINE SAFETY DISCLOSURES

None.

Item 5 — OTHER INFORMATION

None.

Item 6 — EXHIBITS



*	Indicates incorporation by reference



3.01*	Amended and Restated Articles of Incorporation of SPS 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)).
31.01	Principal Executive Officer’s certifications 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 certifications 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’ Quarterly Report on Form 10-Q for the quarter ended March 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) Notes to Financial Statements, and (vi) document and entity information.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		Southwestern Public Service Company

May 5, 2014	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Vice President and Controller

		/s/ TERESA S. MADDEN
		Teresa S. Madden
		Senior Vice President, Chief Financial Officer and Director