SOUTHWESTERN PUBLIC SERVICE CO - FORM 10-Q

SOUTHWESTERN PUBLIC SERVICE CO - FORM 10-Q - August 1, 2014

Attached files

Attached files

SOUTHWESTERN PUBLIC SERVICE CO Reports

file	filename
EX-31.01 - EXHIBIT 31.01 - SOUTHWESTERN PUBLIC SERVICE CO	spsex3101q22014.htm
EX-32.01 - EXHIBIT 32.01 - SOUTHWESTERN PUBLIC SERVICE CO	spsex3201q22014.htm
EX-31.02 - EXHIBIT 31.02 - SOUTHWESTERN PUBLIC SERVICE CO	spsex3102q22014.htm
EX-99.01 - EXHIBIT 99.01 - SOUTHWESTERN PUBLIC SERVICE CO	spsex9901q22014.htm
EXCEL - IDEA: XBRL DOCUMENT - SOUTHWESTERN PUBLIC SERVICE CO	Financial_Report.xls

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 June 30, 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 Aug. 1, 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.

TABLE OF CONTENTS



PART I — FINANCIAL INFORMATION
Item l —	Financial Statements (Unaudited)	3
Item 2 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 4 —	Controls and Procedures	25

PART II — OTHER INFORMATION
Item 1 —	Legal Proceedings	25
Item 1A —	Risk Factors	26
Item 4 —	Mine Safety Disclosures	26
Item 5 —	Other Information	26
Item 6 —	Exhibits	26

SIGNATURES		27

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 June 30						Six Months Ended June 30
	2014			2013			2014			2013
Operating revenues	$	492,536		$	461,831		$	940,936		$	836,088

Operating expenses
Electric fuel and purchased power	314,146			289,012			603,350			520,246
Operating and maintenance expenses	68,963			67,451			138,361			132,021
Demand side management program expenses	2,849			3,210			5,913			6,250
Depreciation and amortization	35,071			31,055			65,583			61,260
Taxes (other than income taxes)	12,507			12,634			26,153			24,783
Total operating expenses	433,536			403,362			839,360			744,560

Operating income	59,000			58,469			101,576			91,528

Other (expense) income, net	(129		)	105			(88		)	57
Allowance for funds used during construction — equity	2,895			2,200			6,535			4,822

Interest charges and financing costs
Interest charges — includes other financing costs of $731, $739, $1,461 and $1,475, respectively	19,645			17,844			38,926			35,617
Allowance for funds used during construction — debt	(1,721		)	(1,410		)	(3,848		)	(3,019		)
Total interest charges and financing costs	17,924			16,434			35,078			32,598

Income before income taxes	43,842			44,340			72,945			63,809
Income taxes	15,807			16,134			26,175			23,019
Net income	$	28,035		$	28,206		$	46,770		$	40,790

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)



	Three Months Ended June 30				Six Months Ended June 30
	2014		2013		2014		2013
Net income	$	28,035	$	28,206	$	46,770	$	40,790
Other comprehensive income
Derivative instruments:
Reclassification of losses to net income, net of tax of $24 and $48 for each of the three and six months ended June 30, 2014 and 2013, respectively	42		43		85		85
Other comprehensive income	42		43		85		85
Comprehensive income	$	28,077	$	28,249	$	46,855	$	40,875

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)



	Six Months Ended June 30
	2014			2013
Operating activities
Net income	$	46,770		$	40,790
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	66,692			62,304
Demand side management program amortization	837			837
Deferred income taxes	51,678			26,501
Amortization of investment tax credits	(170		)	(164		)
Allowance for equity funds used during construction	(6,535		)	(4,822		)
Net derivative losses	133			133
Changes in operating assets and liabilities:
Accounts receivable	(15,131		)	(19,542		)
Accrued unbilled revenues	(33,034		)	(36,171		)
Inventories	2,022			3,102
Prepayments and other	(12,786		)	4,764
Accounts payable	16,949			24,335
Net regulatory assets and liabilities	(34,055		)	(27,545		)
Other current liabilities	1,536			4,724
Pension and other employee benefit obligations	(3,122		)	(19,816		)
Change in other noncurrent assets	3,558			(3,714		)
Change in other noncurrent liabilities	2,198			(2,915		)
Net cash provided by operating activities	87,540			52,801

Investing activities
Utility capital/construction expenditures	(281,398		)	(254,309		)
Allowance for equity funds used during construction	6,535			4,822
Investments in utility money pool arrangement	(22,000		)	(12,000		)
Repayments from utility money pool arrangement	22,000			12,000
Net cash used in investing activities	(274,863		)	(249,487		)

Financing activities
Proceeds from short-term borrowings, net	15,000			40,000
Proceeds from issuance of long-term debt	148,510			—
Borrowings under utility money pool arrangement	382,000			280,000
Repayments under utility money pool arrangement	(420,000		)	(214,000		)
Capital contributions from parent	100,000			125,000
Dividends paid to parent	(36,264		)	(33,886		)
Net cash provided by financing activities	189,246			197,114

Net change in cash and cash equivalents	1,923			428
Cash and cash equivalents at beginning of period	1,011			482
Cash and cash equivalents at end of period	$	2,934		$	910

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(33,668	)	$	(31,165	)
Cash received (paid) for income taxes, net	8,705			(1,669		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	22,423		$	46,739

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)



	June 30, 2014			Dec. 31, 2013
Assets
Current assets
Cash and cash equivalents	$	2,934		$	1,011
Accounts receivable, net	91,724			70,951
Accounts receivable from affiliates	10,198			15,840
Accrued unbilled revenues	142,241			109,207
Inventories	35,116			37,138
Regulatory assets	31,833			27,595
Derivative instruments	41,835			17,826
Deferred income taxes	64,313			85,362
Prepayments and other	32,357			19,571
Total current assets	452,551			384,501

Property, plant and equipment, net	3,520,730			3,284,030

Other assets
Regulatory assets	278,777			290,415
Derivative instruments	37,110			41,056
Other	14,795			17,068
Total other assets	330,682			348,539
Total assets	$	4,303,963		$	4,017,070

Liabilities and Equity
Current liabilities
Short-term debt	$	99,000		$	84,000
Borrowings under utility money pool arrangement	—			38,000
Accounts payable	163,733			143,879
Accounts payable to affiliates	11,600			15,387
Regulatory liabilities	77,796			83,759
Taxes accrued	17,722			23,584
Accrued interest	17,122			16,883
Dividends payable	24,369			18,082
Derivative instruments	3,565			3,583
Other	78,628			75,355
Total current liabilities	493,535			502,512

Deferred credits and other liabilities
Deferred income taxes	791,162			757,778
Regulatory liabilities	92,382			81,504
Asset retirement obligations	19,917			19,375
Derivative instruments	32,425			34,207
Pension and employee benefit obligations	51,965			55,087
Other	5,064			3,051
Total deferred credits and other liabilities	992,915			951,002

Commitments and contingencies
Capitalization
Long-term debt	1,349,518			1,199,865
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at June 30, 2014 and Dec. 31, 2013, respectively	—			—
Additional paid in capital	1,105,463			1,005,463
Retained earnings	363,608			359,389
Accumulated other comprehensive loss	(1,076		)	(1,161		)
Total common stockholder’s equity	1,467,995			1,363,691
Total liabilities and equity	$	4,303,963		$	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 June 30, 2014, and Dec. 31, 2013; the results of its operations, including the components of net income and comprehensive income, for the three and six months ended June 30, 2014 and 2013; and its cash flows for the six months ended June 30, 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 June 30, 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

Revenue Recognition - In May 2014, the Financial Accounting Standards Board issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (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)	June 30, 2014			Dec. 31, 2013
Accounts receivable, net
Accounts receivable	$	97,260		$	76,426
Less allowance for bad debts	(5,536		)	(5,475		)
	$	91,724		$	70,951



(Thousands of Dollars)	June 30, 2014		Dec. 31, 2013
Inventories
Materials and supplies	$	24,299	$	21,600
Fuel	10,817		15,538
	$	35,116	$	37,138



(Thousands of Dollars)	June 30, 2014			Dec. 31, 2013
Property, plant and equipment, net
Electric plant	$	4,991,826		$	4,714,398
Construction work in progress	353,482			388,323
Total property, plant and equipment	5,345,308			5,102,721
Less accumulated depreciation	(1,824,578		)	(1,818,691		)
	$	3,520,730		$	3,284,030

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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.

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 a 2009 carryback claim. As of June 30, 2014, the IRS had proposed an adjustment to several 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 June 30, 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)	June 30, 2014		Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions	$	0.2	$	1.2
Unrecognized tax benefit — Temporary tax positions	2.5		2.9
Total unrecognized tax benefit	$	2.7	$	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)	June 30, 2014			Dec. 31, 2013
NOL and tax credit carryforwards	$	(1.7	)	$	(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 June 30, 2014 and Dec. 31, 2013 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 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.

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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. In April 2014, SPS revised its request to a net increase of $48.1 million, based on updated information.

The rate filing is 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.

SPS, intervenors, and other parties have commenced settlement negotiations. A final settlement is anticipated to be filed with the PUCT in the third quarter of 2014. A final decision is anticipated later this year and final rates are expected to be effective retroactive to June 1, 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 was $13 million. The PUCT issued an order allowing the TCRF to go into effect on an interim basis effective Jan. 1, 2014. In July 2014, the PUCT approved a settlement agreement between the parties allowing SPS to recover $4 million annually through the TCRF. As of June 30, 2014, SPS had recorded an accrual for estimated refunds.

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. 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 New Mexico Attorney General (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 in 2015.

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

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Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Wholesale Rate Complaints — In April 2012, Golden Spread Electric Cooperative, Inc. (Golden Spread) filed a rate complaint alleging that the base ROE included in the SPS production formula rate of 10.25 percent, and the SPS transmission base formula rate ROE of 10.77 percent, are unjust and unreasonable. 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, instead of only short-term growth. The FERC also issued orders consolidating the Golden Spread complaints and setting them for settlement judge procedures and hearings and indicated the parties should apply the new ROE methodology to this proceeding. The effective dates of the refunds are April 20, 2012 and July 19, 2013. The first settlement conference was held in July 2014 and further settlement conferences are anticipated. SPS continues to evaluate the impact of the new FERC ROE methodology. In July 2014, SPS requested rehearing of the June 2014 orders.

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, 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 $3.9 million of principal and interest was accrued during the first six months 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.

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.

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SPS had approximately 827 megawatts (MW) of capacity under long-term PPAs as of each of June 30, 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 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 June 30, 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 (CWA) 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.

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 first quarter of 2015.

Air

EPA Greenhouse Gas (GHG) Permitting — In 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which were applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold. These rules were upheld by the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit), but in June 2014 the U.S. Supreme Court reversed the EPA’s GHG emission thresholds for this program. The Supreme Court decided the EPA could not adopt GHG thresholds that would require permitting for new and modified large stationary sources. However, the Supreme Court also decided if a new or modified stationary source becomes subject to the permitting requirements by exceeding emission thresholds for other pollutants, then GHG emissions may be evaluated as part of the permitting process. SPS is unable to determine the cost of compliance with these new EPA requirements as it is not clear whether these requirements will apply to future changes at SPS’ power plants.

GHG Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. Comments are due to the EPA on Oct. 16, 2014 and a final rule is anticipated in June 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.

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GHG New Source Performance Standard (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. 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. Comments are due to the EPA on Oct. 16, 2014 and a final rule is anticipated in June 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 are not based on and 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.

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 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 Supreme Court held that the EPA’s rule design did not violate the Clean Air Act (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 June 2014, the EPA filed a motion with the D.C. Circuit asking it to lift the stay of the CSAPR. The EPA requested CSAPR’s 2012 compliance obligations be imposed starting in January 2015. The D.C. Circuit has not yet ruled on the motion to lift the stay. Because it is not yet known how the litigation over the remaining issues will be resolved or how the D.C. Circuit will rule on the motion to lift the stay, 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 and in 2014 on Tolk Unit 2. 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 June 30, 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.

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 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, or the EPA’s June 2014 motion requesting the D.C. Circuit lift its stay of the CSAPR, may impact the EPA’s approval of the BART requirements in the SIP.

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In May 2014, the EPA issued a request for information under the CAA related to SO₂ control equipment at Tolk Units 1 and 2. The EPA stated it is conducting an analysis of the cost and feasibility of SO₂ controls on certain sources, including the Tolk facility, as part of its review of the SIP. The EPA has preliminarily identified Tolk as a contributor to haze in the Wichita Mountains Wildlife Refuge in Oklahoma, and is planning further analysis of SO₂ control options. The EPA plans to make a proposal in November 2014 that could include SO₂ emission controls at Tolk and anticipates issuing a final decision in August 2015. The costs and timing of potential additional SO₂ controls at Tolk are dependent on the EPA’s proposal and final decision, neither of which is yet known.

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 June 30, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	100		$	100
Amount outstanding at period end	—			38
Average amount outstanding	6			46
Maximum amount outstanding	54			100
Weighted average interest rate, computed on a daily basis	0.23		%	0.15		%
Weighted average interest rate at period end	N/A			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 June 30, 2014			Twelve Months Ended Dec. 31, 2013
Borrowing limit	$	300		$	300
Amount outstanding at period end	99			84
Average amount outstanding	165			32
Maximum amount outstanding	241			140
Weighted average interest rate, computed on a daily basis	0.25		%	0.30		%
Weighted average interest rate at period end	0.27			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 June 30, 2014 and Dec. 31, 2013, there were $41.0 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 June 30, 2014, SPS had the following committed credit facility available (in millions):



Credit Facility ^(a)		Drawn ^(b)		Available
$	300.0	$	140.0	$	160.0


^(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 June 30, 2014 and Dec. 31, 2013.

Long-Term Borrowings

In June 2014, SPS issued $150 million of 3.30 percent first mortgage bonds due June 15, 2024.

In connection with SPS’ issuance of $150 million of 3.30 percent first mortgage bonds due June 15, 2024, SPS issued $250 million of collateral 8.75 percent first mortgage bonds due Dec. 1, 2018 to the trustee under its senior unsecured indenture in order to secure its previously issued Series G Senior Notes, 8.75 percent due Dec. 1, 2018, equally and ratably with SPS’ first mortgage bonds as required by the terms of such Series G Senior Notes.


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.

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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.

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 June 30, 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.

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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 June 30, 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 and six months ended June 30, 2014 and 2013.

During the three and six months ended June 30, 2014, changes in the fair value of FTRs resulting in pre-tax net losses of $1.0 million and $2.4 million, respectively, 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 losses of $1.9 million and gains of $0.9 million were recognized for the three and six months ended June 30, 2014, respectively, 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 and six months ended June 30, 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 June 30, 2014, one of SPS’ eight most significant counterparties for these activities, comprising $20.6 million or 19 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 $47.6 million or 45 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 eight 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 June 30, 2014:



	June 30, 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	$	—	$	—	$	57,572	$	57,572	$	(23,630	)	$	33,942
Total current derivative assets	$	—	$	—	$	57,572	$	57,572	$	(23,630	)	33,942
PPAs ^(a)												7,893
Current derivative instruments												$	41,835
Noncurrent derivative assets
PPAs ^(a)												$	37,110
Noncurrent derivative instruments												$	37,110
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	23,630	$	23,630	$	(23,630	)	$	—
Total current derivative liabilities	$	—	$	—	$	23,630	$	23,630	$	(23,630	)	—
PPAs ^(a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs ^(a)												$	32,425
Noncurrent derivative instruments												$	32,425

^(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 June 30, 2014. At June 30, 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 tables present the changes in Level 3 commodity derivatives for the three and six months ended June 30, 2014, and there were no Level 3 commodity derivatives during the three and six months ended June 30, 2013:



(Thousands of Dollars)	Three Months Ended June 30, 2014
Balance at April 1	$	5,791
Purchases	38,419
Settlements	(13,554		)
Net transactions recorded during the period:
Gains recognized as regulatory assets and liabilities	3,286
Balance at June 30	$	33,942

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(Thousands of Dollars)	Six Months Ended June 30, 2014
Balance at Jan. 1	$	9,933
Purchases	39,475
Settlements	(14,655		)
Net transactions recorded during the period:
Losses recognized as regulatory assets and liabilities	(811		)
Balance at June 30	$	33,942

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 and six months ended June 30, 2014 and 2013.

Fair Value of Long-Term Debt

As of June 30, 2014 and Dec. 31, 2013, other financial instruments for which the carrying amount did not equal fair value were as follows:



	June 30, 2014				Dec. 31, 2013
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,349,518	$	1,541,197	$	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 June 30, 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 (Expense) Income, Net

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



	Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2014			2013			2014			2013
Interest income	$	53		$	147		$	240		$	260
Other nonoperating income	2			2			—			5
Insurance policy expense	(184		)	(44		)	(328		)	(208		)
Other (expense) income, net	$	(129	)	$	105		$	(88	)	$	57


10.	Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)



	Three Months Ended June 30
	2014			2013			2014			2013
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,296		$	2,403		$	311		$	342
Interest cost	5,111			4,477			643			588
Expected return on plan assets	(6,545		)	(5,992		)	(811		)	(796		)
Amortization of prior service cost (credit)	13			217			(101		)	(121		)
Amortization of net loss (gain)	3,331			4,287			(81		)	(1		)
Net periodic benefit cost (credit)	4,206			5,392			(39		)	12
Credits (costs) not recognized due to the effects of regulation	708			(317		)	—			—
Net benefit cost (credit) recognized for financial reporting	$	4,914		$	5,075		$	(39	)	$	12

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	Six Months Ended June 30
	2014			2013			2014			2013
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	4,592		$	4,807		$	623		$	684
Interest cost	10,222			8,954			1,286			1,176
Expected return on plan assets	(13,090		)	(11,985		)	(1,623		)	(1,592		)
Amortization of prior service cost (credit)	27			435			(201		)	(242		)
Amortization of net loss (gain)	6,663			8,574			(161		)	(3		)
Net periodic benefit cost (credit)	8,414			10,785			(76		)	23
Credits (costs) not recognized due to the effects of regulation	1,415			(1,392		)	—			—
Net benefit cost (credit) recognized for financial reporting	$	9,829		$	9,393		$	(76	)	$	23

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 and six months ended June 30, 2014 and 2013 were as follows:



	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended June 30, 2014			Three Months Ended June 30, 2013
Accumulated other comprehensive loss at April 1	$	(1,118	)	$	(1,290	)
Losses reclassified from net accumulated other comprehensive loss	42			43
Net current period other comprehensive income	42			43
Accumulated other comprehensive loss at June 30	$	(1,076	)	$	(1,247	)



	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Six Months Ended June 30, 2014			Six Months Ended June 30, 2013
Accumulated other comprehensive loss at Jan. 1	$	(1,161	)	$	(1,332	)
Losses reclassified from net accumulated other comprehensive loss	85			85
Net current period other comprehensive income	85			85
Accumulated other comprehensive loss at June 30	$	(1,076	)	$	(1,247	)

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2014 and 2013 were as follows:



	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2014				Three Months Ended June 30, 2013
Losses on cash flow hedges:
Interest rate derivatives	$	66		^(a)	$	67		^(a)
Total, pre-tax	66				67
Tax benefit	(24		)		(24		)
Total amounts reclassified, net of tax	$	42			$	43

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	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2014				Six Months Ended June 30, 2013
Losses on cash flow hedges:
Interest rate derivatives	$	133		^(a)	$	133		^(a)
Total, pre-tax	133				133
Tax benefit	(48		)		(48		)
Total amounts reclassified, net of tax	$	85			$	85


^(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 June 30, 2014.

Results of Operations

SPS’ net income was approximately $46.8 million for the six months ended June 30, 2014, compared with net income of approximately $40.8 million for the same period in 2013. The increase was primarily due to the positive impact of higher electric rates in Texas and New Mexico and weather-normalized sales growth (which is adjusted against a 30-year average of actual historical weather conditions), partially offset by increased O&M expenses and depreciation.

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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:



	Six Months Ended June 30
(Millions of Dollars)	2014			2013
Electric revenues	$	941		$	836
Electric fuel and purchased power	(603		)	(520		)
Electric margin	$	338		$	316

The following tables summarize the components of the changes in electric revenues and electric margin for the six months ended June 30:

Electric Revenues



(Millions of Dollars)	2014 vs. 2013
Fuel and purchased power cost recovery	$	47
Retail rate increases ^(a)	21
Transmission revenue	20
Trading	14
Demand revenue	5
Sales mix	5
Retail sales growth, excluding weather impact	3
Firm wholesale	(11		)
Other, net	1
Total increase in electric revenues	$	105

Electric Margin



(Millions of Dollars)	2014 vs. 2013
Retail rate increases ^(a)	$	21
Transmission revenue, net of costs	12
Demand revenue	5
Sales mix	5
Retail sales growth, excluding weather impact	3
Firm wholesale	(11		)
Purchased capacity costs	(7		)
Texas wind renewable energy credits	(6		)
Fuel handling and procurement	(3		)
Other, net	3
Total increase in electric margin	$	22


^(a)	Retail rates in New Mexico were implemented in 2014. In addition, retail rates in Texas were implemented in the second quarter of 2013.

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Non-Fuel Operating Expense and Other Items

Operating and Maintenance (O&M) Expenses — O&M expenses increased $6.3 million, or 4.8 percent, for the six months ended June 30, 2014 compared with the same period in 2013. The following table summarizes the changes in O&M expenses:



(Millions of Dollars)	2014 vs. 2013
Plant generation costs	$	3
Employee benefits	2
Electric and gas distribution expenses	1
Total increase in O&M expenses	$	6

Depreciation and Amortization — Depreciation and amortization increased $4.3 million, or 7.1 percent, for the six months ended June 30, 2014 compared with the same period in 2013. The increase is primarily due to normal system expansion and a change in amortization as a result of regulatory outcomes.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $1.4 million, or 5.5 percent, for the six months ended June 30, 2014 compared with the same period in 2013. The increase is primarily due to an increase in property and general taxes.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC increased $2.5 million for the six months ended June 30, 2014 compared with the same period in 2013. The increase is primarily due to the expansion of transmission facilities.

Interest Charges — Interest charges increased $3.3 million, or 9.3 percent, for the six months ended June 30, 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 $3.2 million for the six months ended June 30, 2014 compared with the same period in 2013. The increase in income tax expense is primarily due to higher pretax earnings in 2014. The ETR was 35.9 percent for the six months ended June 30, 2014, compared with 36.1 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 and real time energy and ancillary services market similar to the regional market operated by Midcontinent Independent 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 fuel clause adjustment (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. SPS has also filed changes to its QF tariffs in Texas and New Mexico to revise the pricing applied to QF purchases to be consistent with the new market. In February 2014, SPS was granted interim approval of the revised QF tariff in Texas to coincide with the start of the IM. The New Mexico revised QF tariff was approved in March 2014.

SPS Transmission Notifications to Construct (NTCs) — 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 in the process of evaluating these projects and their costs internally before submitting certificates of convenience and necessity (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 Southeast New Mexico.

In April 2014, SPS filed a CCN with the NMPRC for a new 345 kilovolt 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 $53 million. Approval for the CCN is pending.

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Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, 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.

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 Order 1000, FERC instead required that the opportunity to build such projects would extend to competitive transmission developers. SPP made its initial compliance filings to incorporate new provisions into their tariffs regarding regional planning and cost allocation. Various parties appealed Order 1000 final rules to the D.C. Circuit. The date for a Court decision in the appeal is uncertain.

The FERC ruled on the initial regional compliance filings for SPP, directing further compliance changes and thus the SPP regional compliance filings remain pending action by the FERC. Initial filings to address interregional planning and cost allocation requirements with other regions were made by SPP and are pending action by the FERC.

Xcel Energy believes that Texas statutes protect the ROFR of incumbent utilities operating outside of the Electric Reliability Council of Texas (ERCOT) region 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 establishing ROFR rights for incumbent utilities. The FERC issued its initial order on SPP’s Order 1000 regional compliance filing in July 2013. The FERC identified several areas that required 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 SPP regional compliance filing was filed in November 2013 and is currently pending. 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.

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 July 2014, the FERC issued a notice of proposed rulemaking (NOPR) generally proposing to adopt NERC’s proposed CIP standard related to physical security for bulk electric system facilities. However, the FERC proposed a modification to the standard that would allow certain governmental authorities, including FERC, to revise an entity’s list of critical facilities. The new standard would likely be effective in 2015. SPS is currently in the process of evaluating and identifying the critical facilities impacted to better determine the cost of protections necessary to meet the standard. The additional cost for compliance is anticipated to be recoverable through rates.

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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 Xcel Energy, are uncertain at this time. In June 2014, the FERC accepted a proposed tariff change by MISO to recover transmission charges imposed by SPP retroactive to Jan. 29, 2014, and set the issues for settlement judge and hearing procedures.

FERC Order 745 Vacated, Demand Response Compensation in Organized Wholesale Energy Markets (Order 745) — In 2011, the FERC issued a final rule requiring that demand resources participating in organized wholesale markets (such as SPP) be paid the locational marginal price for avoided energy consumption. Numerous parties objected to the rule. On appeal, the D.C. Circuit Court of Appeals vacated and remanded FERC’s order. The Court found that the order was an impermissible intrusion by the FERC into retail electric matters reserved to the states. The FERC has requested rehearing en banc (review by the entire appeals court panel) and that request remains pending. After issuance of the Court’s decision, FirstEnergy Service Company (FirstEnergy) filed a complaint requesting FERC to require PJM Interconnection, LLC (PJM) to remove all portions of the PJM Tariff allowing or requiring PJM to include demand response as suppliers to PJM’s wholesale markets. This complaint also remains pending. Neither the Court’s vacatur of Order 745 nor FirstEnergy’s complaint against PJM have material implications for SPS at this time. However, these actions create uncertainty regarding future participation of demand resources in the SPP wholesale organized market.

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 June 30, 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.

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.

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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)).
4.01*	Fifth Supplemental Indenture dated as of November 1, 2008 between SPS and The Bank of New York Mellon Trust Company, N.A., as successor Trustee. (Exhibit 4.02 to SPS’ Form 8-K dated June 2, 2014 (file no. 001-03789)).
4.02*	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)).
4.03*	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)).
4.04*	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)).
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 June 30, 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

Aug. 1, 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

(Amounts in Thousands) ^(a)

June 30, 2014

Dec. 31, 2013

Megawatt hours of electricity