Edgar Filing: EL PASO ELECTRIC CO /TX/

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Form 10-Q

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, 2011

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

For the transition period from to

Commission file number 001-14206

El Paso Electric Company

(Exact name of registrant as specified in its charter)


Texas		74-0607870
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Stanton Tower, 100 North Stanton, El Paso, Texas		79901
(Address of principal executive offices)		(Zip Code)

(915) 543-5711

(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. YES x NO ¨

Indicate by check mark whether the registrant 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 of 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). YES x 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 definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

As of April 29, 2011, there were 42,107,716 shares of the Company’s no par value common stock outstanding.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

INDEX TO FORM 10-Q


		Page No.
PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements

Consolidated Balance Sheets – March 31, 2011 and December 31, 2010			1

Consolidated Statements of Operations – Three Months and Twelve Months Ended March 31, 2011 and 2010			3

Consolidated Statements of Comprehensive Operations – Three Months and Twelve Months Ended March 31, 2011 and 2010			4

Consolidated Statements of Cash Flows – Three Months Ended March 31, 2011 and 2010			5

Notes to Consolidated Financial Statements			6

Report of Independent Registered Public Accounting Firm			28

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		29

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		44

Item 4.	Controls and Procedures		44

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings		45

Item 1A.	Risk Factors		45

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		45

Item 6.	Exhibits		45

(i)

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS


	March 31, 2011			December 31, 2010
	(Unaudited)
ASSETS (In thousands)
Utility plant:
Electric plant in service	$	2,547,135		$	2,522,862
Less accumulated depreciation and amortization		(1,068,322	)		(1,047,498	)

Net plant in service		1,478,813			1,475,364
Construction work in progress		311,118			285,086
Nuclear fuel; includes fuel in process of $42,858 and $47,746, respectively		165,444			150,774
Less accumulated amortization		(54,324	)		(45,471	)

Net nuclear fuel		111,120			105,303

Net utility plant		1,901,051			1,865,753


Current assets:
Cash and cash equivalents		26,905			79,184
Accounts receivable, principally trade, net of allowance for doubtful accounts of $2,251 and $2,885, respectively		69,809			71,685
Accumulated deferred income taxes		19,955			25,818
Inventories, at cost		38,020			36,132
Income taxes receivable		16,767			12,656
Prepayments and other		6,682			4,543

Total current assets		178,138			230,018

Deferred charges and other assets:
Decommissioning trust funds		159,286			153,878
Regulatory assets		85,828			88,557
Other		28,146			26,560

Total deferred charges and other assets		273,260			268,995


Total assets	$	2,352,449		$	2,364,766

See accompanying notes to consolidated financial statements.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS (Continued)


	March 31, 2011			December 31, 2010
	(Unaudited)
CAPITALIZATION AND LIABILITIES (In thousands except for share data)
Capitalization:
Common stock, stated value $1 per share, 100,000,000 shares authorized, 65,189,444 and 65,121,689 shares issued, and 214,926 and 143,371 restricted shares, respectively	$	65,404		$	65,265
Capital in excess of stated value		306,015			305,068
Retained earnings		817,633			810,858
Accumulated other comprehensive loss, net of tax		(31,501	)		(33,177	)

		1,157,551			1,148,014
Treasury stock, 23,297,375 and 22,693,995 shares, respectively, at cost		(354,813	)		(337,639	)

Common stock equity		802,738			810,375
Long-term debt, net of current portion		849,758			849,745

Total capitalization		1,652,496			1,660,120


Current liabilities:
Current portion of long-term debt and financing obligations		12,951			4,704
Accounts payable, principally trade		35,913			41,795
Taxes accrued		25,020			29,172
Interest accrued		13,174			12,099
Overcollection of fuel revenues		17,783			18,976
Other		24,254			24,207

Total current liabilities		129,095			130,953


Deferred credits and other liabilities:
Accumulated deferred income taxes		293,758			286,730
Asset retirement obligation		95,003			92,911
Accrued pension liability		82,707			93,471
Accrued postretirement benefit liability		60,999			61,594
Regulatory liabilities		13,885			14,489
Other		24,506			24,498

Total deferred credits and other liabilities		570,858			573,693


Commitments and contingencies

Total capitalization and liabilities	$	2,352,449		$	2,364,766

See accompanying notes to consolidated financial statements.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands except for share data)


	Three Months Ended March 31,						Twelve Months Ended March 31,
	2011			2010			2011			2010
Operating revenues	$	176,112		$	204,168		$	849,195		$	841,728

Energy expenses:
Fuel		42,759			49,093			193,495			192,637
Purchased and interchanged power		18,474			28,847			81,543			108,052

		61,233			77,940			275,038			300,689

Operating revenues net of energy expenses		114,879			126,228			574,157			541,039

Other operating expenses:
Other operations		54,107			50,098			228,230			216,635
Maintenance		12,236			14,500			54,559			60,735
Depreciation and amortization		20,936			19,284			82,663			76,551
Taxes other than income taxes		13,127			11,743			55,873			49,224

		100,406			95,625			421,325			403,145

Operating income		14,473			30,603			152,832			137,894

Other income (deductions):
Allowance for equity funds used during construction		3,051			2,540			11,327			9,262
Investment and interest income, net		2,385			1,098			6,602			5,397
Miscellaneous non-operating income		270			2			1,636			897
Miscellaneous non-operating deductions		(715	)		(359	)		(3,562	)		(2,527	)

		4,991			3,281			16,003			13,029

Interest charges (credits):
Interest on long-term debt and financing obligations		13,498			12,201			52,123			48,789
Other interest		297			40			511			266
Capitalized interest		(1,256	)		(228	)		(3,515	)		(921	)
Allowance for borrowed funds used during construction		(1,849	)		(1,567	)		(6,953	)		(5,914	)

		10,690			10,446			42,166			42,220

Income before income taxes and extraordinary item		8,774			23,438			126,669			108,703
Income tax expense		1,999			11,989			41,026			39,930

Income before extraordinary item		6,775			11,449			85,643			68,773
Extraordinary gain related to Texas regulatory assets, net of tax		0			0			10,286			0


Net income	$	6,775		$	11,449		$	95,929		$	68,773


Basic earnings per share:
Income before extraordinary item	$	0.16		$	0.26		$	1.99		$	1.55
Extraordinary gain related to Texas regulatory assets, net of tax		0.00			0.00			0.24			0.00


Net income	$	0.16		$	0.26		$	2.23		$	1.55


Diluted earnings per share:
Income before extraordinary item	$	0.16		$	0.26		$	1.98		$	1.54
Extraordinary gain related to Texas regulatory assets, net of tax		0.00			0.00			0.24			0.00


Net income	$	0.16		$	0.26		$	2.22		$	1.54


Weighted average number of shares outstanding		42,308,097			43,738,947			42,776,922			44,273,168


Weighted average number of shares and dilutive potential shares outstanding		42,523,285			43,863,802			42,964,190			44,366,933

See accompanying notes to consolidated financial statements.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS

(Unaudited)

(In thousands)


	Three Months Ended March 31,						Twelve Months Ended March 31,
	2011			2010			2011			2010
Net income	$	6,775		$	11,449		$	95,929		$	68,773
Other comprehensive income (loss):
Unrecognized pension and postretirement benefit costs:
Net loss arising during period		0			0			(9,874	)		(48,580	)
Prior service benefit		0			0			26,605			0
Reclassification adjustments included in net income for amortization of:
Prior service benefit		(1,455	)		(700	)		(3,509	)		(2,754	)
Net loss		1,475			900			3,949			2,125
Net unrealized losses on marketable securities:
Net holding gains arising during period		2,173			2,423			6,415			20,630
Reclassification adjustments for net (gains) losses included in net income		(205	)		31			(114	)		(224	)
Net losses on cash flow hedges:
Reclassification adjustment for interest expense included in net income		88			83			343			323

Total other comprehensive income (loss) before income taxes		2,076			2,737			23,815			(28,480	)

Income tax benefit (expense) related to items of other comprehensive income (loss):
Unrecognized pension and postretirement benefit costs		(7	)		(73	)		(6,221	)		16,775
Net unrealized losses on marketable securities		(360	)		(491	)		(1,226	)		(4,082	)
Losses on cash flow hedges		(33	)		(30	)		(126	)		(117	)

Total income tax benefit (expense)		(400	)		(594	)		(7,573	)		12,576


Other comprehensive income (loss), net of tax		1,676			2,143			16,242			(15,904	)

Comprehensive income	$	8,451		$	13,592		$	112,171		$	52,869

See accompanying notes to consolidated financial statements.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)


	Three Months Ended March 31,
	2011			2010
Cash flows from operating activities:
Net income	$	6,775		$	11,449
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service		20,936			19,284
Amortization of nuclear fuel		9,243			6,985
Allowance for equity funds used during construction		(3,051	)		(2,540	)
Deferred income taxes, net		12,291			11,059
Other amortization and accretion		7,405			4,041
Other operating activities		(132	)		(308	)
Change in:
Accounts receivable		1,876			(3,678	)
Inventories		(1,888	)		953
Net overcollection (undercollection) of fuel revenues		(1,193	)		(6,000	)
Prepayments and other		(2,303	)		411
Accounts payable		(6,569	)		(15,360	)
Taxes accrued		(8,263	)		(2,737	)
Interest accrued		1,075			2,325
Other current liabilities		47			925
Deferred charges and credits		(13,891	)		(1,274	)

Net cash provided by operating activities		22,358			25,535

Cash flows from investing activities:
Cash additions to utility property, plant and equipment		(45,388	)		(47,145	)
Cash additions to nuclear fuel		(14,228	)		(15,739	)
Capitalized interest and AFUDC:
Utility property, plant and equipment		(4,900	)		(4,107	)
Nuclear fuel		(1,256	)		(228	)
Allowance for equity funds used during construction		3,051			2,540
Decommissioning trust funds:
Purchases, including funding of $2.1 and $2.1 million, respectively		(17,466	)		(22,354	)
Sales and maturities		14,231			19,504
Other investing activities		47			(378	)

Net cash used for investing activities		(65,909	)		(67,907	)

Cash flows from financing activities:
Repurchases of common stock		(16,675	)		(4,089	)
Financing obligations:
Proceeds		16,778			15,972
Payments		(8,531	)		(4,858	)
Other financing activities		(300	)		(78	)

Net cash provided by (used for) financing activities		(8,728	)		6,947

Net decrease in cash and cash equivalents		(52,279	)		(35,425	)
Cash and cash equivalents at beginning of period		79,184			91,790

Cash and cash equivalents at end of period	$	26,905		$	56,365

See accompanying notes to consolidated financial statements.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

A. Principles of Preparation

These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto in the Annual Report of El Paso Electric Company on Form 10-K for the year ended December 31, 2010 (the “2010 Form 10-K”). Capitalized terms used in this report and not defined herein have the meaning ascribed for such terms in the 2010 Form 10-K. In the opinion of the Company’s management, the accompanying consolidated financial statements contain all adjustments necessary to present fairly the financial position of the Company at March 31, 2011 and December 31, 2010; the results of its operations and comprehensive operations for the three and twelve months ended March 31, 2011 and 2010; and its cash flows for the three months ended March 31, 2011 and 2010. The results of operations and comprehensive operations and the cash flows for the three months ended March 31, 2011 are not necessarily indicative of the results to be expected for the full calendar year.

Pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), certain financial information has been condensed and certain footnote disclosures have been omitted. Such information and disclosures are normally included in financial statements prepared in accordance with generally accepted accounting principles. Certain prior period amounts have been reclassified to conform with the current period presentation.

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Revenues. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated based on monthly generation volumes and by applying an average revenue/kWh to the number of estimated kWhs delivered but not billed. Accounts receivable include accrued unbilled revenues of $12.7 million and $16.6 million at March 31, 2011 and December 31, 2010, respectively. The Company presents revenues net of sales taxes in its consolidated statements of operations.

Extraordinary Item. As a regulated electric utility, the Company prepares its financial statements in accordance with the FASB guidance for regulated operations. FASB guidance for regulated operations requires the Company to show certain items as assets or liabilities on its balance sheet when the regulator provides assurance that these items will be charged to and collected from its customers or refunded to its customers. In the final order for PUCT Docket No. 37690, the Company was allowed to include the previously expensed loss on reacquired debt associated with the refinancing of first mortgage bonds in 2005 in its calculation of the weighted cost of debt to be recovered from its customers. The Company recorded the impacts of the re-application of FASB guidance for regulated operations to its Texas jurisdiction in 2006 as an extraordinary item. In order to establish this regulatory asset, the Company recorded an extraordinary gain of $10.3 million, net of income tax expense of

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

$5.8 million, in its statements of operations for the quarter ended September 30, 2010. This item was recorded as a regulatory asset at September 30, 2010 pursuant to the final order received from the PUCT and will be amortized over the remaining life of the Company’s 6% Senior Notes due in 2035.

New accounting standards. In January 2010, the FASB issued new guidance to improve disclosure requirements related to fair value measurements and disclosures. The new requirements include (i) disclosure of significant transfers in and out of Level 1 and Level 2 fair value measurements and the reasons for the transfers; and (ii) disclosure in the reconciliation for Level 3 fair value measurements of information about purchases, sales, issuances, and settlements on a gross basis. The new guidance also clarifies existing disclosures and requires (i) an entity to provide fair value measurement disclosures for each class of assets and liabilities and (ii) disclosures about inputs and valuation techniques. The provisions of this new guidance were adopted in the first quarter of 2010 except for the reconciliation for the Level 3 fair value measurements on a gross basis which was adopted during the first quarter of 2011. During the three and twelve months ended March 31, 2011, the Company had no purchases, sales, issuances or settlements in the Level 3 category. This guidance requires additional disclosure on fair value measurements but does not impact the Company’s consolidated financial statements.

Supplemental Cash Flow Disclosures (in thousands)


	Three Months Ended March 31,
	2011			2010
Cash paid for:
Interest on long-term debt and financing obligations	$	9,763		$	9,610
Income taxes paid (refund)		(5,586	)		1,133
Non-cash financing activities:
Grants of restricted shares of common stock		1,989			779
Issuance of performance shares		565			662
Acquisition of treasury stock for options exercised		500			0

B. Regulation

General

The rates and services of the Company are regulated by incorporated municipalities in Texas, the PUCT, the NMPRC, and the FERC. The PUCT and the NMPRC have jurisdiction to review municipal orders, ordinances, and utility agreements regarding rates and services within their respective states and over certain other activities of the Company. The FERC has jurisdiction over the Company’s wholesale

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

transactions and compliance with federally-mandated reliability standards. The decisions of the PUCT, NMPRC and the FERC are subject to judicial review.

Texas Regulatory Matters

2009 Texas Retail Rate Case. On December 9, 2009, the Company filed an application with the PUCT for authority to change rates, to reconcile fuel costs, to establish formula-based fuel factors, and to establish an energy efficiency cost-recovery factor. This case was assigned PUCT Docket No. 37690. The filing included a base rate increase which was based upon an adjusted test year ended June 30, 2009.

On July 30, 2010, the PUCT approved a settlement in the 2009 Texas retail rate case in PUCT Docket No. 37690. The settlement called for an annual non-fuel base rate increase of $17.15 million effective for usage beginning July 1, 2010. This increase was partially offset by the provision that, consistent with a prior rate agreement, effective July 1, 2010, the Company shares 90% of off-system sales margins with customers and retains 10% of such margins. Previously, the Company retained 75% of off-system sales margins. Interim rates went into effect July 1, 2010 pending final approval by the PUCT. All additions to electric plant in service since June 30, 1993 through June 30, 2009 were deemed to be reasonable and necessary with the exception of one small addition. The Company’s new customer information system completed in April 2010 was also included in base rates with a ten-year amortization. The settlement provides for the reconciliation of fuel costs incurred through June 30, 2009 except for the recovery of final Four Corners’ coal mine reclamation costs. The fuel reconciliation (Docket No. 38361, discussed below) was bifurcated from the rate case to allow for litigation of the final coal mine reclamation costs. The PUCT also approved the use of a formula-based fuel factor which provides for more timely recovery of fuel costs. The PUCT approved a $19.7 million or 11% reduction in the Company’s fixed fuel factor as the initial rate under the approved fuel factor formula. The PUCT also approved an energy efficiency cost-recovery factor that includes the recovery of deferred energy efficiency costs over a three-year period.

Fuel Reconciliation Case (Severed from 2009 Rate Case). Pursuant to the stipulation in Docket No. 37690, a fuel reconciliation component of the rate case was severed and a separate docket, PUCT Docket No. 38361, was established to address one fuel reconciliation issue not settled by the parties. That single issue was a determination of the proper amount of the Four Corners’ coal mine final reclamation costs to be recovered from the Company’s Texas retail customers. The hearing on the merits of the case was held on August 11, 2010. On November 23, 2010 the Administrative Law Judge (the “ALJ”) issued the Proposal for Decision which approved the Company’s request. The PUCT issued a final order approving the Proposal for Decision on January 27, 2011.

Fuel and Purchased Power Costs. The Company’s actual fuel costs, including purchased power energy costs, are recoverable from its customers. The PUCT has adopted a fuel cost recovery rule (“Texas Fuel Rule”) that allows the Company to seek periodic adjustments to its fixed fuel factor. The Company received approval on July 30, 2010 in PUCT Docket No. 37690 (discussed above), to implement a formula to determine its fuel factor. The Company can seek to revise its fixed fuel factor

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

based upon the approved formula at least four months after its last revision except in the month of December. The Texas Fuel Rule requires the Company to request to refund fuel costs in any month when the over-recovery balance exceeds a threshold material amount and it expects fuel costs to continue to be materially over-recovered. The Texas Fuel Rule also permits the Company to seek to surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount and it expects fuel cost recovery to continue to be materially under-recovered. Fuel over and under-recoveries are considered material when they exceed 4% of the previous twelve months’ fuel costs. All such fuel revenue and expense activities are subject to periodic final review by the PUCT in fuel reconciliation proceedings.

On December 17, 2009, the Company filed a petition with the PUCT in Docket No. 37788 to refund $11.8 million in fuel cost over-recoveries, including interest, for the period September through November 2009. On January 20, 2010, a stipulation was filed that resolved all of the issues in this proceeding. The stipulation provided for the Company to implement a fuel refund for the net over-recovery of $11.8 million, including interest, in the month of February 2010. On January 21, 2010, the ALJ assigned to the docket issued an order approving the implementation of interim rates to allow the requested refund to be made. The PUCT issued a final order on February 11, 2010 approving the stipulation.

On May 12, 2010, the Company filed a petition with the PUCT which was assigned Docket No. 38253 to refund $10.5 million in fuel cost over-recoveries, including interest, for the period December 2009 through March 2010. On June 14, 2010, the Company and all other parties filed a stipulation that resolved all of the issues in this case. In the stipulation, the Company and the other parties agreed to increase the refund by $0.6 million to remove costs for the purchase of renewable energy credits from the Company’s fuel cost, and as a result of that adjustment and the associated recalculation of interest, the total refund was $11.1 million. On June 16, 2010, the ALJ assigned to the docket issued an order approving the implementation of interim rates to allow the requested refund to be made in July and August 2010. The PUCT issued a final order on July 15, 2010 approving the stipulation.

On October 20, 2010, the Company filed a petition with the PUCT which was assigned Docket No. 38802 to refund $12.8 million in fuel cost over-recoveries, including interest, for the period April 2010 through September 2010. In its filing, the Company requested the refund be made to customers in the single billing month of December 2010. On November 22, 2010, a stipulation was filed that resolved all issues in this case and requested that an order be issued that would allow the interim refund in December 2010 consistent with the Company’s filing. The ALJ issued an order approving the implementation of interim rates to allow the requested refund to be made in December. On December 16, 2010, the PUCT issued a final order approving the stipulation.

On November 23, 2010, the Company filed a petition with the PUCT which was assigned Docket No. 38895 to revise its fixed fuel factor pursuant to the fuel factor formula authorized in PUCT Docket No. 37690 for determining the Company’s fuel factor. The Company’s request was to decrease its fixed fuel factor by 14.7%. On December 2, 2010, the State Office of Administrative Hearings (“SOAH”) ALJ issued Order No. 1, establishing interim rates as requested, as well as a deadline of

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

December 3, 2010, for the purpose of requesting a hearing, and absent such a request, implementation of the revised fuel factor would become final by its own terms and without further PUCT order. No request was received; therefore, the revised fuel factor became final. On January 6, 2011, the SOAH ALJ dismissed the proceeding from the SOAH docket, the case was dismissed from the PUCT’s docket on that same date, and the case was closed.

On February 18, 2011, the Company filed a petition with the PUCT which was assigned Docket No. 39159 to refund $11.8 million in fuel cost over-recoveries, including interest, for the period October 2010 through December 2010. In its filing, the Company requested the refund be made to customers in the single billing month of April 2011. On March 25, 2011, the ALJ approved the implementation of the interim fuel refund in April 2011. The PUCT approved the fuel refund on April 29, 2011.

Application for Approval to Revise Energy Efficiency Cost Recovery Factor for 2011. On June 1, 2010, the Company filed with the PUCT an application for approval to revise its energy efficiency cost recovery factor (“EECRF”), which was assigned PUCT Docket No. 38226. The Company requested that its revised EECRF become effective beginning with the first billing cycle of its January 2011 billing month. In its application, the Company requested authority to increase its 2011 EECRF to a total of $6.6 million to recover $4.2 million in energy efficiency costs projected to be incurred in 2011, a performance bonus of $0.1 million for the Company’s 2009 program performance, and $2.3 million in annual amortization of the energy efficiency costs that were deferred pursuant to the PUCT’s final order in Docket No. 35612. A final order approving the Company’s application was issued on October 4, 2010.

Application for a Certificate of Convenience and Necessity (“CCN”) for Rio Grande Unit 9. On September 30, 2010, the Company filed a petition seeking a CCN to construct an 87 MW natural gas-fired combustion turbine unit at the Company’s existing Rio Grande Generating Station in the City of Sunland Park in southeast New Mexico. This case was assigned PUCT Docket No. 38717. A unanimous settlement to approve the CCN was filed on March 2, 2011 and a final order granting the CCN was approved on April 8, 2011.

Project to Investigate Early February 2011 Outages and Curtailments. On February 8, 2011, the PUCT opened Project No. 39134, Investigation into Power Outages in El Paso Electric’s Service Territory. In this project, the PUCT is investigating the Company’s power plant outages and customer curtailments that occurred February 2-4, 2011, as a result of the extreme cold weather in the El Paso area. There was no accompanying PUCT order for the opening of this project. The PUCT Staff has conducted discovery in the investigation. On February 14, 2011, the Company also filed a report on this weather event.

On February 15, 2011, the City Council of El Paso adopted a motion that when the results of hearings and investigations concerning the extreme cold weather event are concluded, the Mayor will call for Special City Council meetings or public hearings, on utility issue topics, at a time accessible to the public, inviting the public and the utility representatives to review the findings.

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New Mexico Regulatory Matters

2009 New Mexico Stipulation. On May 29, 2009, the Company filed a general rate case using a test year ended December 31, 2008. The 2009 rate case was docketed as NMPRC Case No. 09-00171-UT. A comprehensive unopposed stipulation (the “2009 New Mexico Stipulation”) was reached in this general rate case and filed on October 8, 2009. The 2009 New Mexico Stipulation provided for an increase in New Mexico jurisdictional non-fuel and purchased power base rate revenues of $5.5 million. The 2009 New Mexico Stipulation provided for the revision of depreciation rates for the Palo Verde nuclear generating plant to reflect a 20-year life extension and a revision of depreciation rates for other plant in service. The 2009 New Mexico Stipulation also provided for the continuation of the Company’s Fuel and Purchased Power Cost Adjustment Clause (“FPPCAC”) without conditions or variance. In addition, it modified the market pricing of capacity and energy provided by Palo Verde Unit 3 using a methodology based upon a previous purchased power contract with Credit Suisse Energy, LLC. On December 10, 2009, the NMPRC issued a final order conditionally approving and clarifying the unopposed stipulation, and the stipulated rates went into effect with January 2010 bills.

2010 Energy Efficiency Program Approval. On January 19, 2010, the Company filed its Application for Approval of its 2010 Energy Efficiency Programs pursuant to the New Mexico Efficient Use of Energy Act. The filing included changes and additions to the Company’s previously approved programs and sought revisions to the associated rate rider through which program costs are recovered. The parties to the proceeding entered into an uncontested stipulation to implement program changes and expansions as well as the rate rider to recover related costs. The NMPRC approved the stipulation in its final order issued August 12, 2010.

2010 Renewable Procurement Plan Pursuant to the Renewable Energy Act. On July 1, 2010, the Company filed its Application for Approval of its 2010 Renewable Procurement Plan, which was assigned NMPRC Case No. 10-00200-UT. The filing included renewable resources intended to meet the Company’s Renewable Portfolio Standard (“RPS”) requirements in 2011 and future years. The 2010 Renewable Procurement Plan included a number of projects to meet the Company’s RPS requirements, including three purchased power agreements for solar energy. In addition, the Company requested a variance from the solar diversity requirements in 2011 to be made up in later years from the new purchased power agreements for solar energy. Hearings were held on October 21, 2010. A final order was issued on December 16, 2010 that approved the Company’s 2010 Renewable Procurement plan, including granting the requested variance from the solar diversity requirements in 2011. However, the NMPRC maintained the 2010 rates and contract terms for energy produced by customer-owned renewable distributed generation facilities.

Application for Approval to Recover Regulatory Disincentives and Incentives. On August 31, 2010, the Company filed an application for approval of its proposed rate design methodology to recover regulatory disincentives and incentives associated with the Company’s energy efficiency and load management programs in New Mexico. On March 18, 2011, the Company entered into an uncontested stipulation which would provide for a rate per kWh of energy efficiency savings that would be

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recovered through the efficient use of energy rider. A hearing on the uncontested stipulation was held on April 26, 2011 and a final order is expected before July 2011.

Application for a CCN for Rio Grande Unit 9. On September 30, 2010, the Company filed a petition seeking a CCN to construct an 87 MW natural gas-fired combustion turbine unit at the Company’s existing Rio Grande Generating Station in the City of Sunland Park in southeast New Mexico. This case was assigned NMPRC Case No. 10-00301-UT. On March 4, 2011, NMPRC Staff filed testimony in support of the Company’s application and no party filed testimony or a position statement opposing the application. On April 13, 2011 an unopposed stipulation was filed in this case seeking approval of a CCN for the Company to construct, own and operate the 87 MW generating unit. A public hearing on this matter is scheduled for May 18, 2011 before the NMPRC.

Federal Regulatory Matters

Transmission Dispute with Tucson Electric Power Company (“TEP”). In January 2006, the Company filed a complaint with the FERC to interpret the terms of a Power Exchange and Transmission Agreement (the “Transmission Agreement”) entered into with TEP in 1982. TEP filed a complaint with the FERC one day later raising virtually identical issues. TEP claimed that, under the Transmission Agreement, it was entitled to up to 400 MW of firm transmission rights on the Company’s transmission system that would enable it to transmit power from the Luna Energy Facility (“LEF”) located near Deming, New Mexico to Springerville or Greenlee in Arizona. The Company asserted that TEP’s rights under the Transmission Agreement do not include transmission rights necessary to transmit such power as contemplated by TEP and that TEP must acquire any such rights in the open market from the Company at applicable tariff rates or from other transmission providers. On April 24, 2006, the FERC ruled in the Company’s favor, finding that TEP does not have transmission rights under the Transmission Agreement to transmit power from the LEF to Arizona. The ruling was based on written evidence presented and without an evidentiary hearing. TEP’s request for a rehearing of the FERC’s decision was granted in part and denied in part in an order issued October 4, 2006, and hearings on the disputed issues were held before an administrative law judge. In the initial decision dated September 6, 2007, the administrative law judge found that the Transmission Agreement allows TEP to transmit power from the LEF to Arizona but limits that transmission to 200 MW on any segment of the circuit and to non-firm service on the segment from Luna to Greenlee. The Company and TEP filed exceptions to the initial decision.

On November 13, 2008, the FERC issued an order on the initial decision finding that the transmission rights given to TEP in the Transmission Agreement are firm and are not restricted for transmission of power from Springerville as the receipt point to Greenlee as the delivery point. Therefore, pursuant to the order, TEP can use its transmission rights granted under the Transmission Agreement to transmit power from the LEF to either Springerville or Greenlee so long as it transmits no more than 200 MW over all segments at any one time.

The FERC also ordered that the Company refund to TEP all sums with interest that TEP had paid it for transmission under the applicable transmission service agreements since February 2006 for

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service relating to the LEF. On December 3, 2008, the Company refunded $9.7 million to TEP. The Company had established a reserve for the rate refund of approximately $7.2 million as of September 30, 2008, resulting in a pre-tax charge to earnings of approximately $2.5 million in 2008. The Company also paid TEP interest on the refunded balance of approximately $0.9 million, which was also charged to earnings in 2008. The Company filed a request for rehearing of the FERC’s decision on December 15, 2008, seeking reversal of the order on the merits and a return of any refunds made in the interim, as well as compensation for all service that the Company may provide to TEP from the LEF over the Company’s transmission system on a going forward basis. On July 7, 2010, the FERC denied the Company’s request for rehearing. On July 23, 2010, the Company filed a petition for review in the United States Court of Appeals for the District of Columbia Circuit (the “Court of Appeals”) and on August 18, 2010, TEP filed a motion to intervene in the proceeding. On January 14, 2011, the Company and TEP filed a joint consent motion, asking the Court to hold the proceedings in abeyance while the parties engaged in settlement discussions. The Court granted the motion on January 19, 2011.

On April 26, 2011, TEP and the Company entered into a proposed settlement (subject to FERC approval) to resolve this dispute. The proposed settlement would reduce TEP’s transmission rights under the Transmission Agreement from 200 MW to 170 MW and would require TEP to pay the Company a lump sum of $5 million, equivalent to the amount TEP would have paid the Company for 30 MW of transmission from February 1, 2006 through the settlement date, plus interest. Additionally, TEP and the Company will enter into two new firm transmission capacity agreements at applicable tariff rates for a total of 40 MW. The settlement agreement will be filed with the FERC and will become effective after (i) the FERC issues a final non-appealable order approving the settlement, and (ii) the FERC issues a final non-appealable order approving a settlement between the Company and Macho Springs Power I, LLC regarding the reimbursement of certain network upgrade costs associated with the interconnection of a wind generating facility to the Company’s transmission system. The Company will withdraw its appeal before the Court of Appeals when the settlement agreement becomes effective.

Under the terms of the proposed settlement, the Company would record approximately $4.3 million in transmission revenues for the period February 1, 2006 through March 31, 2011, and $0.7 million in interest income. The Company would share with its customers 25% of the transmission revenues earned before July 1, 2010, or approximately $0.7 million, through a credit to Texas fuel recoveries. The Company estimates that the proposed settlement will add approximately $0.6 million to its transmission revenues for the remaining nine months of 2011. If the settlement agreement does not become effective and if the Company is unsuccessful in its petition for review at the Court of Appeals, the Company will lose the opportunity to receive compensation from TEP for the disputed transmission service.

In an ancillary proceeding, TEP filed a lawsuit in the United States District Court for the District of Arizona in December 2008, seeking reimbursement for amounts TEP paid a third party transmission provider for purchases of transmission capacity between April 2006 and May 2007, allegedly totaling approximately $1.5 million, plus accrued interest. TEP alleges that the Company was obligated to provide TEP with that transmission capacity without charge under the Transmission Agreement. In September 2009, the Court granted a stay in this suit pending a resolution of the underlying FERC proceeding and any appeal thereof. If the settlement agreement described in the preceding paragraph becomes effective, TEP has agreed to withdraw this complaint.

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Inquiry into Early February 2011 Outages and Curtailments. On February 14, 2011, FERC directed its staff to initiate an inquiry into power plant outages and customer curtailments by power generators and gas suppliers in the Southwestern United States, including the Company, in early February 2011, as a result of the extreme cold weather. The inquiry has been assigned Docket No. AD11-9-000. FERC specifically stated that its inquiry is not an enforcement investigation. The agency encouraged its staff to identify the causes of the outages and to determine appropriate responses to prevent such outages in the future. There has been no staff report posted in the docket, and FERC has not taken any additional action on the matter.

C. Palo Verde

License Extension. On April 21, 2011, the Company, along with the other Palo Verde Participants, was notified that the NRC had renewed the operating licenses for all three units at Palo Verde. The renewed licenses for the nuclear power plants will now expire on June 1, 2045 for Unit 1, April 24, 2046 for Unit 2, and November 25, 2047 for Unit 3.

Oversight of the Nuclear Energy Industry in the Wake of the Earthquake and Tsunami in Japan. On March 11, 2011, a 9.0 magnitude earthquake occurred off the north-eastern coast of Japan. The earthquake produced a tsunami that caused significant damage to the Fukushima Daiichi Nuclear Power Station in Japan. Preliminary data available from the Fukushima Daiichi plant operator and Japanese government have each indicated that the earthquake and tsunami were beyond the plant’s required licensing and design parameters. Validation of that data will continue as more information becomes available.

The Nuclear Energy Institute (“NEI”) and the Institute of Nuclear Power Operations (“INPO”) are working closely to analyze the situation in Japan and develop action plans for U.S. nuclear power plants. APS, which operates Palo Verde, is actively engaged with NEI and INPO in these efforts. Additionally, the NRC is performing its own independent review of the events at Fukushima Daiichi. On March 23, 2011, the NRC Commissioners voted to launch a two-pronged review of U.S. nuclear power plant safety. The NRC announced that it supports the establishment of an agency task force that will conduct both a short- and long-term analysis of the lessons that can be learned from the situation in Japan. The NRC expects the task force to begin its long-term evaluations within 90 days and anticipates that a report with any recommended actions will be available within six months after the evaluations begin.

D. Common Stock

Repurchase Program. Since the inception of the stock repurchase program in 1999, the Company has repurchased approximately 23.2 million shares of common stock at an aggregate cost of $353.8 million, including commissions. During the first quarter of 2011, the Company repurchased 586,911 shares of common stock in the open market at an aggregate cost of $16.7 million under the Company’s 2010 Plan. On March 21, 2011, the Board of Directors authorized an additional repurchase

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of up to 2.5 million shares of the Company’s outstanding common stock (the “2011 Plan”). As of March 31, 2011, 2,589,360 shares remain available for repurchase under the Company’s authorized programs. The Company may in the future make purchases of its common stock pursuant to its authorized programs in open market transactions at prevailing prices and may engage in private transactions, where appropriate. The repurchased shares will be available for issuance under employee benefit and stock incentive plans, or may be retired.

Dividend Policy. On April 28, 2011 the Board of Directors declared a quarterly cash dividend of $0.22 per share payable on June 30, 2011 to shareholders of record on June 15, 2011. This is the first quarterly cash dividend declared by the Company since 1991.

Basic and Diluted Earnings Per Share. The basic and diluted earnings per share are presented below:


	Three Months Ended March 31,						Twelve Months Ended March 31,
	2011			2010			2011			2010
Weighted average number of common shares outstanding:
Basic number of common shares outstanding		42,308,097			43,738,947			42,776,922			44,273,168
Dilutive effect of unvested performance awards		169,426			72,343			126,051			45,961
Dilutive effect of stock options		45,762			52,512			61,217			47,804

Diluted number of common shares outstanding		42,523,285			43,863,802			42,964,190			44,366,933

Basic net income per common share:
Net income	$	6,775		$	11,449		$	95,929		$	68,773
Income allocated to participating restricted stock		(28	)		(44	)		(391	)		(255	)

Net income available to common shareholders	$	6,747		$	11,405		$	95,538		$	68,518

Diluted net income per common share:
Net income	$	6,775		$	11,449		$	95,929		$	68,773
Income reallocated to participating restricted stock		(28	)		(44	)		(390	)		(255	)

Net income available to common shareholders	$	6,747		$	11,405		$	95,539		$	68,518


Basic net income per common share	$	0.16		$	0.26		$	2.23		$	1.55


Diluted net income per common share	$	0.16		$	0.26		$	2.22		$	1.54

The calculation of the diluted number of common shares outstanding for the three months ended March 31, 2011 and 2010, excludes 94,076 and 79,990 shares, respectively, of restricted stock awards because their effect was antidilutive. The calculation of the diluted number of common shares outstanding for the twelve months ended March 31, 2011 and 2010, excludes 78,792 and 66,534 shares, respectively, of restricted stock awards because their effect was antidilutive.

No performance shares were excluded from the computation of diluted earnings per share for the three months ended March 31, 2011 and 2010. Performance shares of 24,225 and 87,382 were excluded from the computation of diluted earnings per share for the twelve months ended March 31, 2011 and 2010,

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respectively, as no payouts would be required based upon current performance. These amounts assume a 100% performance level payout.

No stock options were excluded from the computation of diluted earnings per share for the three and twelve months ended March 31, 2011 and 2010.

E. Income Taxes

The Company files income tax returns in the U.S. federal jurisdiction and in the states of Texas, New Mexico and Arizona. The Company is no longer subject to tax examination by the taxing authorities in the federal jurisdiction for years prior to 2007 and in the state jurisdictions for years prior to 1998. A deficiency notice relating to the Company’s 1998 through 2003 income tax returns in Arizona contests a pollution control credit, a research and development credit, and the sales and property apportionment factors. The Company is contesting these adjustments.

For the three months ended March 31, 2011 and 2010, the Company’s consolidated effective tax rate was 22.8% and 51.2%, respectively. For the twelve months ended March 31, 2011 and 2010 the Company’s consolidated effective tax rate was 32.8% and 36.7%, respectively. The Company’s consolidated effective tax rate for the three and twelve months ended March 31, 2011 differs from the federal statutory tax rate of 35% primarily due to the allowance for equity funds used during construction (“AEFUDC”) and state income taxes. AEFUDC in the first quarter of 2011 as compared to 2010 was larger due to larger balances of construction work in progress which accrues AEFUDC. In March 2010, the Patient Protection and Affordable Care Act (“PPACA”) was signed into law which contained a provision that the cost of providing certain prescription drug coverage will be reduced by the amount of the Medicare Part D subsidies received. The Company was required to recognize the impacts of the tax law change at the time of enactment. The Company’s consolidated effective tax rate without the effect of the enactment of the PPACA for the three and twelve months ended March 31, 2010, was 30.7% and 32.3%, respectively. The Company’s 2010 effective tax rates without the effect of the enactment of the PPACA differ from the federal statutory tax rate of 35% primarily due to state income taxes, AEFUDC, the tax rate on qualified decommissioning trust investment, and various permanent tax differences.

F. Commitments, Contingencies and Uncertainties

For a full discussion of commitments and contingencies, see Note J of Notes to Consolidated Financial Statements in the 2010 Form l0-K. In addition, see Note B above and Notes B and D of Notes to Consolidated Financial Statements in the 2010 Form 10-K regarding matters related to wholesale power sales contracts and transmission contracts subject to regulation and Palo Verde, including decommissioning, spent fuel storage, disposal of low-level radioactive waste, and liability and insurance matters.

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Power Purchase and Sale Contracts

To supplement its own generation and operating reserves, the Company engages in firm power purchase arrangements which may vary in duration and amount based on evaluation of the Company’s resource needs and the economics of the transactions. For a full discussion of power purchase and sale contracts that the Company has entered into with various counterparties, see Note J of Notes to Consolidated Financial Statements in the 2010 Form 10-K.

Environmental Matters

General. The Company is subject to laws and regulations with respect to air, soil and water quality, waste disposal and other environmental matters by federal, state, regional, tribal and local authorities. Those authorities govern facility operations and have continuing jurisdiction over facility modifications. Failure to comply with these environmental regulatory requirements can result in actions by regulatory agencies or other authorities that might seek to impose on the Company administrative, civil and/or criminal penalties or other sanctions. In addition, releases of pollutants or contaminants into the environment can result in costly cleanup obligations. These laws and regulations are subject to change and, as a result of those changes, the Company may face additional capital and operating costs to comply. Certain key environmental issues, laws and regulations facing the Company are described further below.

Air Emissions. The U.S. Clean Air Act (“CAA”) and comparable state laws and regulations relating to air emissions impose, among other obligations, limitations on pollutants generated during the Company’s operations, including sulfur dioxide (“SO2”), particulate matter, nitrogen oxides (“NOx”) and mercury.

Clean Air Interstate Rule. The U.S. Environmental Protection Agency’s (“EPA”) Clean Air Interstate Rule (“CAIR”) as applied to the Company, involves requirements to limit emissions of NOx from the Company’s power plants in Texas and/or purchase allowances representing other parties’ emissions reductions starting in 2009. Although the U.S. Court of Appeals for the District of Columbia voided CAIR in 2008, the Company must comply with CAIR until the EPA rewrites the rule as required by the Court’s final opinion. The 2010 reconciliation to comply with CAIR was filed before the March 2011 deadline and the Company purchased and expensed $0.3 million of allowances during 2010 to meet its estimated requirement.

Clean Air Transport Rule. In July 2010, the EPA proposed as a replacement to CAIR, the Clean Air Transport Rule (“CATR”). CATR would require 31 states, including Texas, and the District of Columbia to issue regulations and develop a scheme by which power plants in their respective jurisdictions will further reduce emissions of SO2 and NOx. Reductions would be required beginning in 2012, with further reductions likely to be required in 2014. The EPA expects CATR to be finalized in July 2011, but it is unclear when the states would issue implementing regulations. There are a number of other uncertainties relating to this proposed rule, including whether it will be ultimately finalized and how the states will implement the requirements. As a result, the ultimate impact of this rule on the Company’s operations cannot currently be determined, but it could be material.

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Ozone. NOx emissions can lead to the formation of ozone. Ozone levels are limited by the National Ambient Air Quality Standards established by the EPA. The EPA is in the process of revising these standards. If these revisions result in more stringent standards, the Company could be required to place additional NOx pollution control measures on certain of its generating facilities. Without knowing the new ozone standards, the ultimate impact on the Company’s facilities cannot be determined. However the impact of these regulations and associated costs could be material.

Climate Change. A significant portion of the Company’s generation assets are nuclear or gas-fired, and as a result, the Company believes that its greenhouse gas (“GHG”) emissions are low relative to electric power companies who rely on more coal-fired generation. However, regulations governing the emission of GHGs, such as carbon dioxide, could impose significant costs or limitations on the Company. In recent years, the U.S. Congress has considered new legislation to restrict or regulate GHG emissions, although federal efforts directed at enacting comprehensive climate change legislation stalled in 2010 and appear highly unlikely to recommence in 2011. Nonetheless, it is possible that federal legislation related to GHG emissions will be considered in Congress in the future. The EPA has also proposed using the CAA to limit carbon dioxide and other GHG emissions, and GHG emissions regulations have been adopted by EPA in recent years, with additional regulations proposed or in development.

Significant GHG emissions regulations have been adopted by EPA in recent years with additional regulations proposed or in development. In September 2009, the EPA adopted a rule requiring approximately 10,000 facilities comprising a substantial percentage of annual U.S. GHG emissions to inventory their emissions starting in 2010 and to report those emissions to the EPA beginning in 2011. The Company’s fossil fuel-fired power generating assets are subject to this rule. The Company also has inventoried and implemented procedures for electrical equipment containing sodium hexafluoride (SF6), another GHG. The Company is tracking these GHG emissions pursuant to EPA’s new SF6 reporting rule that was finalized in late 2010 and became effective January 1, 2011. The first report to EPA under this rule is due March 31, 2012.

EPA has also proposed and finalized other rulemakings on GHG emissions that affect electric utilities. Under EPA regulations finalized in May 2010 (referred to as the “Tailoring Rule”), the EPA began regulating GHG emissions from certain stationary sources in January 2011. The regulations are being implemented pursuant to two CAA programs: the Title V Operating Permit program and the program requiring a permit if undergoing construction or major modifications (referred to as the “PSD” program). Obligations relating to Title V permits will include recordkeeping and monitoring requirements. With respect to PSD permits, projects that cause a significant increase in GHG emissions (currently defined to be more than 75,000 tons or more per year or 100,000 tons or more per year, depending on various factors), will be required to implement “best available control technology”, or “BACT”. The EPA has issued guidance on what BACT entails for the control of GHGs and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. The ultimate impact of these new regulations on the Company’s operations cannot be determined at this time, but the cost of compliance with new regulations could be material. Also, on December 23, 2010, EPA announced a settlement agreement with states and environmental groups regarding setting new source performance standards for GHG emissions from new and existing coal-, gas- and oil-based power plants. Pursuant to this agreement, EPA will propose standards for both new

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or modified boilers and for existing facilities in August 2011, and finalize those standards by May 26, 2012. The impact of these rules on the Company is unknown at this time, but they could result in material costs.

In addition, almost half of the states, either individually or through multi state regional initiatives, have begun to consider how to address GHG emissions and are actively considering the development of emission inventories or regional GHG cap and trade programs. The State of New Mexico, where the Company operates one facility and has an interest in another facility, has joined with California and several other states in the Western Climate Initiative and is pursuing initiatives to reduce GHG emissions in the state. The New Mexico Environmental Improvement Board approved two separate rulemakings in November and December 2010 to limit GHG emissions from certain stationary sources. Under the November 2010 regulation, stationary sources that emit 25,000 metric tons or more of carbon dioxide a year would be required to reduce their GHG emissions by 2% per year from 2012 through 2020. The December 2010 regulation establishes a cap-and-trade system which would require certain industrial and electric generating facilities with carbon dioxide emissions in excess of 25,000 metric tons per year to reduce their emissions by 3% per year below 2010 levels. There are various uncertainties relating to these regulations, including whether current legal challenges to them will be successful, but as drafted, the Company does not expect these regulations to result in significant costs to the Company.

It is not currently possible to predict with confidence how any pending, proposed or future GHG legislation by Congress, the states, or multi-state regions or regulations adopted by EPA or the state environmental agencies will impact the Company’s business. However, any such legislation or regulation of GHG emissions or any future related litigation could result in increased compliance costs or additional operating restrictions or reduced demand for the power the Company generates, could require the Company to purchase rights to emit GHG, and could have a material adverse effect on the Company’s business, financial condition, reputation or results of operations.

Climate change also has potential physical effects that could be relevant to the Company’s business. In particular, some studies suggest that climate change could affect our service area by causing higher temperatures, less winter precipitation and less spring runoff, as well as by causing more extreme weather events. Such developments could change the demand for power in the region and could also impact the price or ready availability of water supplies or affect maintenance needs and the reliability of Company equipment.

The Company believes that material effects on the Company’s business or operations may result from the physical consequences of climate change, the regulatory approach to climate change ultimately selected and implemented by governmental authorities, or both. Substantial expenditures may be required for the Company to comply with such regulations in the future and, in some instances, those expenditures may be material. Given the very significant remaining uncertainties regarding whether and how these issues will be regulated, as well as the timing and severity of any physical effects of climate change, the Company believes it is impossible at present to meaningfully quantify the costs of these potential impacts.

Contamination Matters. The Company has a provision for environmental remediation obligations of approximately $0.4 million at March 31, 2011, related to compliance with federal and state environmental standards. However, unforeseen expenses associated with environmental

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compliance or remediation may occur and could have a material adverse effect on the future operations and financial condition of the Company.

The Company incurred the following expenditures during the three and twelve months ended March 31, 2011 and 2010 to comply with federal environmental statutes (in thousands):


	Three Months Ended March 31,				Twelve Months Ended March 31,
	2011		2010		2011		2010
Clean Air Act	$	58	$	217	$	456	$	677
Clean Water Act		56		34		200		572

The EPA has investigated releases or potential releases of hazardous substances, pollutants or contaminants at the Gila River Boundary Site, on the Gila River Indian Community reservation in Arizona and designated it as a Superfund site. The Company currently owns 16.29% of the site and will share in the cost of cleanup of this site. The Company has a tentative agreement with the EPA and a former property owner to resolve this matter and in 2011, the Company is expected to enter into a consent decree with the EPA at a cost to the Company of less than $0.1 million (which amount is included in the $0.4 million accrued at March 31, 2011).

Environmental Litigation and Investigations. On April 6, 2009, APS received a request from the EPA under Section 114 of the CAA seeking detailed information regarding projects and operations at Four Corners. APS has responded to this request. The Company is unable to predict the timing or content of EPA’s response or any resulting actions.

On February 16, 2010, a group of environmental organizations filed a petition with the United States Departments of Interior and Agriculture requesting that the agencies certify to the EPA that emissions from Four Corners are causing “reasonably attributable visibility impairment” under the CAA. If the agencies certify impairment, the EPA is required to evaluate and, if necessary, determine “best available retrofit technology (“BART”) for Four Corners. On January 19, 2011, a similar group of environmental organizations filed a lawsuit against the Departments of Interior and Agriculture, alleging, among other things, that the agencies failed to act on the February 2010 petition “without unreasonable delay” and requesting the court to order the agencies to act on the petition within 30 days. The Company cannot predict the outcome of the petition or whether any resulting actions could have an adverse effect on its capital or operating costs.

G. Litigation

The Company is a party to various legal actions. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. Based upon a review of these claims and applicable insurance coverage, to the extent that the Company has been able to reach a conclusion as to its ultimate liability, it believes that none of these claims will have a material adverse effect on the financial position, results of operations or cash flows of the Company.

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See Note B and Note F for discussion of the effects of government legislation and regulation on the Company.

H. Employee Benefits

Retirement Plans

The net periodic benefit cost recognized for the three and twelve months ended March 31, 2011 and 2010 is made up of the components listed below as determined using the projected unit credit actuarial cost method (in thousands):


	Three Months Ended March 31,						Twelve Months Ended March 31,
	2011			2010			2011			2010
Components of net periodic benefit cost:
Service cost	$	1,743		$	1,500		$	6,307		$	5,634
Interest cost		3,495			3,425			13,699			13,333
Amendments		0			0			838			0
Expected return on plan assets		(3,533	)		(3,500	)		(13,900	)		(15,064	)
Amortization of:
Net loss		1,583			900			4,232			2,125
Prior service cost		27			25			117			115

Net periodic benefit cost	$	3,315		$	2,350		$	11,293		$	6,143

During the three months ended March 31, 2011, the Company contributed $12.5 million of its projected $13.9 million 2011 annual contribution to its retirement plans.

Other Postretirement Benefits

The net periodic benefit cost recognized for the three and twelve months ended March 31, 2011 and 2010 is made up of the components listed below (in thousands):


	Three Months Ended March 31,						Twelve Months Ended March 31,
	2011			2010			2011			2010
Components of net periodic benefit cost:
Service cost	$	738		$	925		$	3,371		$	3,395
Interest cost		1,290			1,725			6,229			6,567
Expected return on plan assets		(458	)		(375	)		(1,612	)		(1,499	)
Amortization of:
Prior service benefit		(1,482	)		(725	)		(3,626	)		(2,869	)
Net gain		(108	)		0			(283	)		0

Net periodic benefit cost	$	(20	)	$	1,550		$	4,079		$	5,594

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

During the three months ended March 31, 2011, the Company contributed $2.2 million to fund its entire annual contribution to its postretirement plan for 2011.

I. Financial Instruments and Investments

FASB guidance requires the Company to disclose estimated fair values for its financial instruments. The Company has determined that cash and temporary investments, investment in debt securities, accounts receivable, decommissioning trust funds, long-term debt and financing obligations, accounts payable and customer deposits meet the definition of financial instruments. The carrying amounts of cash and temporary investments, accounts receivable, accounts payable and customer deposits approximate fair value because of the short maturity of these items. Investments in debt securities and decommissioning trust funds are carried at fair value.

Long-Term Debt and Financing Obligations. The fair values of the Company’s long-term debt and financing obligations, including the current portion thereof, are based on estimated market prices for similar issues and are presented below (in thousands):


	March 31, 2011				December 31, 2010
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Pollution Control Bonds	$	193,135	$	191,445	$	193,135	$	192,924
Senior Notes		546,623		581,129		546,610		574,700
Nuclear Fuel Financing (1):
RGRT Senior Notes		110,000		110,900		110,000		110,371
RCF		12,951		12,951		4,704		4,704

Total	$	862,709	$	896,425	$	854,449	$	882,699

(1)	Nuclear fuel financing as of March 31, 2011 is funded through the $110 million RGRT Senior Notes and the RCF. The interest rate on the Company’s nuclear fuel financing through the RCF is reset every quarter to reflect current market rates. Consequently, the carrying value approximates fair value.

Marketable Securities. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair value which was $159.3 million and $153.9 million at March 31, 2011 and December 31, 2010, respectively. These securities are classified as available for sale under FASB guidance for certain investments in debt and equity securities and are valued using prices and other relevant information generated by market transactions involving identical or comparable securities. The reported fair values include gross unrealized losses on marketable securities whose impairment the Company has deemed to be temporary. The tables below present the gross unrealized losses and the fair value of these securities, aggregated by investment category and length of

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

time that individual securities have been in a continuous unrealized loss position, at March 31, 2011 and December 31, 2010 (in thousands):


	March 31, 2011
	Less than 12 Months					12 Months or Longer					Total
	Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses
Description of Securities (1):
Federal Agency Mortgage Backed Securities	$	4,864	$	(76	)	$	436	$	(32	)	$	5,300	$	(108	)
U.S. Government Bonds		12,779		(213	)		0		0			12,779		(213	)
Municipal Obligations		12,653		(340	)		5,440		(219	)		18,093		(559	)
Corporate Obligations		1,381		(21	)		0		0			1,381		(21	)

Total debt securities		31,677		(650	)		5,876		(251	)		37,553		(901	)
Common stock		9,719		(1,074	)		1,191		(288	)		10,910		(1,362	)

Total temporarily impaired securities	$	41,396	$	(1,724	)	$	7,067	$	(539	)	$	48,463	$	(2,263	)

(1)	Includes approximately 108 securities.


	December 31, 2010
	Less than 12 Months					12 Months or Longer					Total
	Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses
Description of Securities (2):
Federal Agency Mortgage Backed Securities	$	2,290	$	(51	)	$	441	$	(27	)	$	2,731	$	(78	)
U.S. Government Bonds		9,583		(124	)		0		0			9,583		(124	)
Municipal Obligations		13,145		(278	)		3,763		(145	)		16,908		(423	)
Corporate Obligations		1,855		(18	)		0		0			1,855		(18	)

Total debt securities		26,873		(471	)		4,204		(172	)		31,077		(643	)
Common stock		6,943		(774	)		4,303		(420	)		11,246		(1,194	)

Total temporarily impaired securities	$	33,816	$	(1,245	)	$	8,507	$	(592	)	$	42,323	$	(1,837	)

(2)	Includes approximately 96 securities.

The Company monitors the length of time the security trades below its cost basis along with the amount and percentage of the unrealized loss in determining if a decline in fair value of marketable securities below original cost is considered to be other than temporary. In addition, the Company will research the future prospects of individual securities as necessary. As a result of these factors, as well as the Company’s intent and ability to hold these securities until their market price recovers, these securities are considered temporarily impaired. The Company will not have a requirement to expend monies held in trust before 2044 or a later period when the Company begins to decommission Palo Verde.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The reported fair values also include gross unrealized gains on marketable securities which have not been recognized in the Company’s net income. The table below presents the unrecognized gross unrealized gains and the fair value of these securities, aggregated by investment category (in thousands):


	March 31, 2011				December 31, 2010
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
Description of Securities:
Federal Agency Mortgage Backed Securities	$	16,770	$	685	$	18,472	$	793
U.S. Government Bonds		6,193		98		10,450		183
Municipal Obligations		15,005		583		15,633		592
Corporate Obligations		8,361		332		7,223		362

Total debt securities		46,329		1,698		51,778		1,930

Common stock		60,493		16,768		56,770		14,142
Temporary investments		4,001		0		3,007		0

Total	$	110,823	$	18,466	$	111,555	$	16,072

The Company’s marketable securities include investments in municipal, corporate and federal debt obligations. Substantially all of the Company’s mortgage backed securities, based on contractual maturity, are due in 10 years or more. The mortgage backed securities have an estimated weighted average maturity which generally range from 3 to 7 years and reflects anticipated future prepayments. The contractual year for maturity for all other available-for-sale securities as of March 31, 2011 is as follows (in thousands):


	Total		2011		2012 through 2015		2016 through 2020		2021 and Beyond
Municipal Debt Obligations	$	33,098	$	2,292	$	11,281	$	11,721	$	7,804
Corporate Debt Obligations		9,742		0		4,479		3,305		1,958
U.S. Government Bonds		18,972		2,105		7,788		5,887		3,192

The Company recognizes impairment losses on certain of its securities deemed to be other than temporary. In accordance with FASB guidance, these impairment losses are recognized in net income and a lower cost basis is established for these securities. For the three and twelve months ended March 31, 2011 and 2010 the Company recognized other than temporary impairment losses on its available-for-sale securities as follows (in thousands):


	Three Months Ended March 31,				Twelve Months Ended March 31,
	2011		2010		2011			2010
Gross unrealized holding losses included in pre-tax income	$	0	$	0	$	(263	)	$	(3,092	)

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The Company’s marketable securities in its decommissioning trust funds are sold from time to time and the Company uses the specific identification basis to determine the amount to reclassify out of accumulated other comprehensive income and into net income. The proceeds from the sale of these securities and the related effects on pre-tax income are as follows (in thousands):


	Three Months Ended March 31,						Twelve Months Ended March 31,
	2011			2010			2011			2010
Proceeds from sales of available-for-sale securities	$	14,231		$	19,504		$	56,383		$	87,023

Gross realized gains included in pre-tax income	$	264		$	397		$	897		$	3,809
Gross realized losses included in pre-tax income		(59	)		(428	)		(520	)		(493	)
Gross unrealized losses included in pre-tax income		0			0			(263	)		(3,092	)

Net gains (losses) in pre-tax income	$	205		$	(31	)	$	114		$	224

Net unrealized holding gains included in accumulated other comprehensive income	$	2,173		$	2,423		$	6,415		$	20,630
Net gains (losses) reclassified out of other accumulated comprehensive income		(205	)		31			(114	)		(224	)

Net gains (losses) in other comprehensive income	$	1,968		$	2,454		$	6,301		$	20,406

Fair Value Measurements. FASB guidance requires the Company to provide expanded quantitative disclosures for financial assets and liabilities recorded on the balance sheet at fair value. Financial assets carried at fair value include the Company’s decommissioning trust investments and investments in debt securities. The Company has no liabilities that are measured at fair value on a recurring basis. The FASB guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

•

Level 1 – Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Financial assets utilizing Level 1 inputs include the nuclear decommissioning trust investments in active exchange-traded equity securities and U.S. treasury securities that are in a highly liquid and active market.

•

Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. Financial assets utilizing Level 2 inputs include the nuclear decommissioning trust investments in other fixed income securities. The fair value of these financial instruments is based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

•

Level 3 – Unobservable inputs using data that is not corroborated by market data and primarily based on internal Company analysis using models and various other analyses. Financial assets utilizing Level 3 inputs include the Company’s investments in debt securities.

The securities in the Company’s decommissioning trust funds are valued using prices and other relevant information generated by market transactions involving identical or comparable securities. FASB guidance identifies this valuation technique as the “market approach” with observable inputs. The Company analyzes available-for-sale securities to determine if losses are other than temporary.

The fair value of the Company’s decommissioning trust funds and investments in debt securities, at March 31, 2011 and December 31, 2010, and the level within the three levels of the fair value hierarchy defined by FASB guidance are presented in the table below (in thousands):


Description of Securities	Fair Value as of March 31, 2011		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Trading Securities:
Investments in Debt Securities	$	2,837	$	0	$	0	$	2,837


Available for sale:
U.S. Government Bonds	$	18,972	$	18,972	$	0	$	0
Federal Agency Mortgage Backed Securities		22,070		0		22,070		0
Municipal Bonds		33,098		0		33,098		0
Corporate Asset Backed Obligations		9,742		0		9,742		0

Subtotal, Debt Securities		83,882		18,972		64,910		0

Common Stock		71,403		71,403		0		0
Cash and Cash Equivalents		4,001		4,001		0		0

Total available for sale	$	159,286	$	94,376	$	64,910	$	0

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


Description of Securities	Fair Value as of December 31, 2010		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Trading Securities:
Investments in Debt Securities	$	2,909	$	0	$	0	$	2,909


Available for sale:
U.S. Government Bonds	$	20,033	$	20,033	$	0	$	0
Federal Agency Mortgage Backed Securities		21,204		0		21,204		0
Municipal Bonds		32,541		0		32,541		0
Corporate Asset Backed Obligations		9,077		0		9,077		0

Subtotal, Debt Securities		82,855		20,033		62,822		0

Common Stock		68,016		68,016		0		0
Cash and Cash Equivalents		3,007		3,007		0		0

Total available for sale	$	153,878	$	91,056	$	62,822	$	0

There were no transfers in and out of Level 1 and Level 2 fair value measurements categories during the three and twelve month periods ending March 31, 2011 and 2010. There were no purchases, sales, issuances, and settlements related to the assets in the Level 3 fair value measurement category during the three and twelve month periods ending March 31, 2011 and 2010.

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

El Paso Electric Company:

We have reviewed the consolidated balance sheet of El Paso Electric Company and subsidiary as of March 31, 2011, the related consolidated statements of operations and comprehensive operations for the three-month and twelve-month periods ended March 31, 2011 and 2010, and the related consolidated statements of cash flows for the three-month periods ended March 31, 2011 and 2010. These consolidated financial statements are the responsibility of the Company’s management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to the consolidated financial statements referred to above for them to be in conformity with U.S. generally accepted accounting principles.

We have previously audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of El Paso Electric Company and subsidiary as of December 31, 2010, and the related consolidated statements of operations, comprehensive operations, changes in common stock equity, and cash flows for the year then ended (not presented herein); and in our report dated February 25, 2011, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2010, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ KPMG LLP

Houston, Texas

May 6, 2011

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The information contained in this Item 2 updates, and should be read in conjunction with, the information set forth in Part II, Item 7 of our 2010 Form 10-K.

FORWARD-LOOKING STATEMENTS

Certain matters discussed in this Quarterly Report on Form 10-Q other than statements of historical information are “forward-looking statements.” The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we “believe”, “anticipate”, “target”, “expect”, “pro forma”, “estimate”, “intend” and words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. Such statements address future events and conditions concerning and include, but are not limited to such things as:

•

capital expenditures,

•

earnings,

•

liquidity and capital resources,

•

ratemaking/regulatory matters,

•

litigation,

•

accounting matters,

•

possible corporate restructurings, acquisitions and dispositions,

•

compliance with debt and other restrictive covenants,

•

interest rates and dividends,

•

environmental matters,

•

nuclear operations, and

•

the overall economy of our service area.

These forward-looking statements involve known and unknown risks that may cause our actual results in future periods to differ materially from those expressed in any forward-looking statement. Factors that would cause or contribute to such differences include, but are not limited to, such things as:

•

our ability to recover our costs and earn a reasonable rate of return on our invested capital through rates,

•

ability of our operating partners to maintain plant operations and manage operation and maintenance costs at the Palo Verde and Four Corners plants, including costs to comply with any potential new or expanded regulatory requirements,

•

reductions in output at generation plants operated by the Company,

•

unscheduled outages, including outages at Palo Verde,

•

the size of our construction program and our ability to complete construction on budget and on a timely basis,

•

electric utility deregulation or re-regulation,

•

regulated and competitive markets,

•

ongoing municipal, state and federal activities,

•

economic and capital market conditions,

•

changes in accounting requirements and other accounting matters,

•

changing weather trends and the impact of severe weather conditions,

•

rates, cost recoveries and other regulatory matters including the ability to recover fuel costs on a timely basis,

•

changes in environmental regulations, including those related to air, water or greenhouse gas emissions or other environmental matters,

•

political, legislative, judicial and regulatory developments,

•

the impact of lawsuits filed against us,

•

the impact of changes in interest rates,

•

changes in, and the assumptions used for, pension and other post-retirement and post-employment benefit liability calculations, as well as actual and assumed investment returns on pension plan and other postretirement plan assets,

•

the impact of the U.S. health care reform legislation,

•

the impact of changing cost escalation and other assumptions on our nuclear decommissioning liability for Palo Verde,

•

Texas, New Mexico and electric industry utility service reliability standards,

•

homeland security considerations including those associated with the U.S./Mexico border region,

•

coal, uranium, natural gas, oil and wholesale electricity prices and availability, and

•

other circumstances affecting anticipated operations, sales and costs.

These lists are not all-inclusive because it is not possible to predict all factors. A discussion of some of these factors is included in this document under the heading “Risk Factors” and in the 2010 Form 10-K under the headings “Management’s Discussion and Analysis” “–Summary of Critical Accounting Policies and Estimates” and “–Liquidity and Capital Resources.” This report should be read in its entirety. No one section of this report deals with all aspects of the subject matter. Any forward-looking statement speaks only as of the date such statement was made, and we are not obligated to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made except as required by applicable laws or regulations.

Summary of Critical Accounting Policies and Estimates

The preparation of our financial statements requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and related notes for the periods presented and actual results could differ in future periods from those estimates. Critical accounting policies and estimates are both important to the portrayal of our financial condition and results of operations and require complex, subjective judgments and are more fully described in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2010 Form 10-K.

Summary

The following is an overview of our results of operations for the three and twelve month periods ended March 31, 2011 and 2010. Income before extraordinary item for the three and twelve month periods ended March 31, 2011 and 2010 is shown below:


	Three Months Ended March 31,				Twelve Months Ended March 31,
	2011		2010		2011		2010
Net income before extraordinary item (in thousands)	$	6,775	$	11,449	$	85,643	$	68,773
Basic earnings per share before extraordinary item		0.16		0.26		1.99		1.55

The following table and accompanying explanations show the primary factors affecting the after-tax change in income before extraordinary item between the 2011 and 2010 periods presented (in thousands):


	Three Months Ended			Twelve Months Ended
March 31, 2010 income before extraordinary item	$	11,449		$	68,773
Change in (net of estimated income tax):
Elimination of Medicare Part D tax benefit (a)		4,787			4,787
Decreased operations and maintenance expense at coal and gas-fired generating plants (b)		940			784
Increased AFUDC (c)		689			2,721
Increased (decreased) retail non-fuel base revenues (d)		(3,875	)		24,401
Decreased off-system sales margins retained (e)		(2,800	)		(5,607	)
Increased administrative and general expense (f)		(1,113	)		(5,180	)
Increased depreciation and amortization (g)		(1,041	)		(3,850	)
Increased taxes other than income taxes (h)		(872	)		(4,189	)
Increased (decreased) deregulated Palo Verde Unit 3 revenues (i)		(719	)		839
Increased customer accounts and service expense (j)		(697	)		(3,038	)
Decreased (increased) Palo Verde operations and maintenance expense (k)		(115	)		3,060
Other		142			2,142

March 31, 2011 income before extraordinary item	$	6,775		$	85,643

(a)	Income tax expense was incurred in 2010 to recognize a change in tax law enacted in the Patient Protection and Affordable Care Act to eliminate the tax benefit related to the Medicare Part D subsidies with no comparable tax expense in 2011.

(b)

Operations and maintenance expense at coal and gas-fired generating plants decreased due to the timing of planned maintenance. In 2010, we had a major overhaul at Four Corners Unit 4 and a major inspection at Newman Unit 4. These decreases for the three and twelve months ended March 31, 2011 were partially offset by additional costs incurred in 2011 associated with equipment damaged during the coldest winter weather in nearly 50 years in February 2011. The decreases for the twelve months ended March 31, 2011 were also partially offset by a planned maintenance outage at Newman Unit 2.

(c)	AFUDC for the twelve months ended March 31, 2011 increased compared to the same period last year primarily due to higher balances of construction work in progress subject to AFUDC.

(d)

Non-fuel retail base revenues decreased for the three months ending March 31, 2011 compared to the same period last year primarily due to new lower winter non-fuel base rates in Texas. Non-fuel retail base revenues increased for the twelve months ending March 31, 2011 primarily due to new non-fuel base rates in New Mexico and Texas. The new rate structure in New Mexico, effective January 1, 2010, and in Texas, effective July 1, 2010, resulted in net increases in base rates during the peak summer season of May through October and net decreases in base rates during November through April. Non-fuel retail base revenues exclude fuel recovered through New Mexico base rates.

(e)	Off-system sales margins retained decreased for the three and twelve month periods ended March 31, 2011 compared to the same periods last year as a result of increased sharing of off-system sales margins with customers, lower average market prices for power, and a decline in MWh sales.

(f)

Administrative and general expenses increased for the three months ended March 31, 2011 compared to the same period last year primarily due to increased outside services. Administrative and general expenses increased for the twelve months ended March 31, 2011 compared to the same period last year primarily due to increased pension and benefits expenses, increased outside services, and increased regulatory expense to reflect amortization of rate case expenses for Texas and New Mexico.

(g)	Depreciation and amortization expense increased for the three and twelve months ended March 31, 2011 compared to the same period last year due to increased depreciable plant balances and higher depreciation rates effective in July 2010.

(h)	Taxes other than income taxes increased for the three and twelve months ended March 31, 2011 compared to the same periods last year primarily due to revenue-related taxes reflecting a higher tax rate in El Paso and increased property taxes.

(i)

Revenues from retail sales of deregulated Palo Verde Unit 3 power decreased primarily due to lower proxy prices for the three months ended March 31, 2011 when compared to the same period last year. For the twelve months ended March 31, 2011 compared to the same period last year, revenues from retail sales of deregulated Palo Verde Unit 3 power increased due to higher proxy prices and increased production at Palo Verde Unit 3 in the current period.

(j)	Customer accounts and service expense increased for the twelve months ended March 31, 2011 compared to the same period last year primarily due to increased uncollectible customer accounts and the transition to a new customer billing system.

(k)	Palo Verde operations and maintenance expenses decreased for the twelve months ended March 31, 2011 compared to the same period last year primarily due to decreased maintenance costs as the result of reduced costs for scheduled refueling outages.

Historical Results of Operations

The following discussion includes detailed descriptions of factors affecting individual line items in the results of operations. The amounts presented below are presented on a pre-tax basis.

Operating revenues

We realize revenue from the sale of electricity to retail customers at regulated rates and the sale of energy in the wholesale power market generally at market based prices. Sales for resale (which are wholesale sales within our service territory) accounted for less than 1% of revenues. Off-system sales are wholesale sales into markets outside our service territory. Off-system sales are primarily made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations. We shared 25% of off-system sales margins with our Texas and New Mexico customers and retained 75% of off-system sales margins through June 30, 2010. Pursuant to rate agreements in prior years, effective July 1, 2010, we share 90% of off-system sales margins with our Texas and New Mexico customers, and we retain 10% of off-system sales margins. We are sharing 25% of our off-system sales margins with our sales for resale customer under the terms of a contract which was effective April 1, 2008.

Revenues from the sale of electricity include fuel costs that are recovered from our customers through fuel adjustment mechanisms. A significant portion of fuel costs are also recovered through base rates in New Mexico. We record deferred fuel revenues for the difference between actual fuel costs and recoverable fuel revenues until such amounts are collected from or refunded to customers. “Non-fuel base revenues” refers to our revenues from the sale of electricity excluding recovery of such fuel costs.

Retail non-fuel base revenue percentages by customer class are presented below:


	Three Months Ended March 31,						Twelve Months Ended March 31,
	2011			2010			2011			2010
Residential		43	%		41	%		41	%		41	%
Commercial and industrial, small		32			36			35			36
Commercial and industrial, large		9			8			8			7
Sales to public authorities		16			15			16			16

Total retail non-fuel base revenues		100	%		100	%		100	%		100	%

No retail customer accounted for more than 3% of our non-fuel base revenues during such periods. As shown in the table above, residential and small commercial customers comprise 75% or more of our revenues. While this customer base is more stable, it is also more sensitive to changes in weather conditions. The new rate structure in New Mexico and Texas increases base rates during the peak summer season of May through October while decreasing base rates during November through April for our residential and small commercial and industrial customers. As a result, our business is seasonal, with higher kWh sales and revenues during the summer cooling season.

Weather significantly impacts our residential, small commercial and industrial customers, and to a lesser extent, our sales to public authorities. For the quarter ended March 31, 2011, retail non-fuel base revenues were negatively impacted by milder winter weather when compared to the first quarter of 2010. Heating and cooling degree days can be used to evaluate the effect of weather on energy use. For each degree the average outdoor temperature varies from a standard of 65 degrees Fahrenheit a degree day is recorded. The table below shows heating and cooling degree days compared to a 10-year average.


	Three Months Ended March 31,				10-Year Average		Twelve Months Ended March 31,				10-Year Average*
	2011		2010		10-Year Average		2011		2010		10-Year Average*
Heating degree days		1,265		1,396		1,224		2,142		2,510		2,280
Cooling degree days		41		9		22		2,770		2,740		2,562

*	Calendar year basis.

Customer growth is a key driver of the growth of retail sales. The average number of retail customers grew 1.4% and 1.6%, respectively, for the three and twelve months ended March 31, 2011 when compared to the same periods last year. See the tables presented on pages 36 and 37 which provide detail on the average number of retail customers and the related revenues and kWh sales.

Retail non-fuel base revenues. The new rate structure in New Mexico, effective January 1, 2010, and in Texas, effective July 1, 2010, resulted in net increases in base rates during the peak summer season of May through October and net decreases in base rates during November through April. This will cause our revenues to be more seasonal than in the past.

Retail non-fuel base revenues decreased by $6.2 million or 5.6% for the three months ended March 31, 2011 when compared to the same period last year primarily due to a $6.0 million decrease in revenues from small commercial and industrial customers due to new seasonal non-fuel base rates in Texas. Retail non-fuel base revenues received from large commercial and industrial customers decreased $0.4 million due to a 3.1% decrease in kWh sales. Retail non-fuel base revenues received from residential customers increased $0.1 million due to a 1.5% growth in the average number of customers served. This increase was partially offset by decreased kWh sales to residential customers of 2.7% due to milder winter weather in 2011 compared to the first quarter of 2010. During the first quarter of 2011, heating degree days were 9% below the same period in 2010 and 3% above the 10-year average. Revenues from public authorities increased $0.1 million due to a 2.9% increase in kWh sales.

Retail non-fuel base revenues for the twelve months ended March 31, 2011 increased by $38.7 million, or 7.9%, compared to the same period in 2010. The increase was due to new non-fuel base rates in New Mexico and Texas and a 2.7% increase in kWh sales to retail customers. KWh sales to residential customers increased 2.7% reflecting a 1.7% growth in the average number of customers served. KWh sales to public authorities increased 3.9% largely due to increased sales to military bases. KWh sales to small commercial and industrial customers increased 1.2% and kWh sales to large commercial and industrial customers increased 4.1% reflecting the improving local economic conditions.

Fuel revenues. Fuel revenues consist of: (i) revenues collected from customers under fuel recovery mechanisms approved by the state commissions and the FERC, (ii) deferred fuel revenues which are comprised of the difference between fuel costs and fuel revenues collected from customers, and (iii) fuel costs recovered in base rates in New Mexico. In New Mexico and with our sales for resale customer, the fuel adjustment clause allows us to recover under-recoveries or refund over-recoveries of current fuel costs above the amount recovered in base rates with a two-month lag. In Texas, fuel costs

are recovered through a fixed fuel factor. Effective July 1, 2010, we can seek to revise our fixed fuel factor based upon our approved formula at least four months after our last revision except in the month of December. In addition, if we materially over-recover fuel costs, we must seek to refund the over-recovery, and if we materially under-recover fuel costs, we may seek a surcharge to recover those costs. Fuel over and under recoveries are considered material when they exceed 4% of the previous twelve months’ fuel costs.

In the first quarter of 2011, we under-recovered our fuel costs for all three jurisdictions by $1.0 million compared to a fuel over-recovery of $5.7 million in the first quarter of 2010. In January 2011, we implemented a reduced fixed fuel factor in Texas and in March 2011 we received approval to refund $11.8 million of fuel over-recoveries for the period October 2010 through December 2010 to our Texas customers in April 2011. During the first quarter of 2010, we refunded $11.8 million of fuel over-recoveries to Texas customers. Over-recoveries or under-recoveries in New Mexico and from our FERC customer are refunded through fuel adjustment clauses with a two month lag.

In the twelve-month period ended March 31, 2011 we over-collected fuel costs by $28.7 million compared to $48.9 million for the same time period in 2010. Refunds of $23.0 million were returned to our Texas customers in the twelve-months ended March 31, 2011 compared to refunds, net of fuel surcharges, of $24.6 million in the twelve months ended March 31, 2010.

Off-system sales. Off-system sales are primarily made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations. Typically, we realize a significant portion of our off-system sales margins in the first quarter of each calendar year when our native load is lower than at other times of the year, allowing for the sale in the wholesale market of relatively larger amounts of off-system energy generated from lower cost generating resources. Palo Verde’s availability is an important factor in realizing these off-system sales margins. The table below shows the MWhs, sales revenue, fuel costs, total margins, and retained margins made on off-system sales for the three and twelve month periods (in thousands except for MWhs).


	Three Months Ended March 31,					Twelve Months Ended March 31,
	2011			2010		2011		2010
MWh sales		767,620			847,738		2,742,614		2,785,319
Sales revenues	$	21,366		$	38,703	$	87,980	$	116,150
Fuel cost	$	20,263		$	32,862	$	80,917	$	102,632
Total margin	$	1,103		$	5,841	$	7,063	$	13,518
Retained margin	$	(61	)	$	4,382	$	1,244	$	10,142

Off-system sales decreased $17.3 million and $28.2 million for the three and twelve month periods ended March 31, 2011 when compared to the same periods last year as the result of lower average market prices for power and a decline in MWh sales. The Company shared 25% of off-system sales margins with customers and retained 75% of off-system sales margins through June 30, 2010 pursuant to rate agreements in prior years. Effective July 1, 2010, we share 90% of off-system sales margins with customers and retain 10% of off-system sales margins. Off-system sales margins were negatively impacted by power purchases required for system reliability during extremely cold weather in February 2011. As a result, retained margins decreased $4.4 million for the three months ended March 31, 2011 when compared to the same period last year. For the twelve months ended March 31, 2011, retained margins decreased $8.9 million when compared to the same period last year.

Comparisons of kWh sales and operating revenues are shown below (in thousands):


						Increase (Decrease)
Quarter Ended March 31:	2011		2010			Amount			Percent
kWh sales:
Retail:
Residential		541,282		556,280			(14,998	)		(2.7	)%
Commercial and industrial, small		478,521		484,282			(5,761	)		(1.2	)
Commercial and industrial, large		229,232		236,613			(7,381	)		(3.1	)
Sales to public authorities		334,969		325,557			9,412			2.9

Total retail sales		1,584,004		1,602,732			(18,728	)		(1.2	)

Wholesale:
Sales for resale		11,653		9,180			2,473			26.9
Off-system sales		767,620		847,738			(80,118	)		(9.5	)

Total wholesale sales		779,273		856,918			(77,645	)		(9.1	)

Total kWh sales		2,363,277		2,459,650			(96,373	)		(3.9	)

Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	44,977	$	44,835		$	142			0.3	%
Commercial and industrial, small		33,214		39,199			(5,985	)		(15.3	)
Commercial and industrial, large		8,801		9,213			(412	)		(4.5	)
Sales to public authorities		17,020		16,916			104			0.6

Total retail non-fuel base revenues		104,012		110,163			(6,151	)		(5.6	)

Wholesale:
Sales for resale		550		307			243			79.2

Total non-fuel base revenues		104,562		110,470			(5,908	)		(5.3	)

Fuel revenues:
Recovered from customers during the period		25,863		38,033			(12,170	)		(32.0	)(1)
Under (over) collection of fuel		1,038		(5,690	)		6,728			N/A
New Mexico fuel in base rates		16,369		15,829			540			3.4

Total fuel revenues		43,270		48,172			(4,902	)		(10.2	)
Off-system sales		21,366		38,703			(17,337	)		(44.8	)
Other		6,914		6,823			91			1.3	(2)

Total operating revenues	$	176,112	$	204,168		$	(28,056	)		(13.7	)

Average number of retail customers:
Residential		334,832		329,734			5,098			1.5	%
Commercial and industrial, small		37,064		36,547			517			1.4
Commercial and industrial, large		50		48			2			4.2
Sales to public authorities		4,536		4,965			(429	)		(8.6	)

Total		376,482		371,294			5,188			1.4

(1)	Excludes an $11.8 million refund in 2010 related to prior periods Texas deferred fuel revenues.

(2)	Represents revenues with no related kWh sales.


							Increase (Decrease)
Twelve Months Ended March 31:	2011			2010			Amount			Percent
kWh sales:
Retail:
Residential		2,493,836			2,428,301			65,535			2.7	%
Commercial and industrial, small		2,289,776			2,262,394			27,382			1.2
Commercial and industrial, large		1,080,032			1,037,802			42,230			4.1
Sales to public authorities		1,551,801			1,492,956			58,845			3.9

Total retail sales		7,415,445			7,221,453			193,992			2.7

Wholesale:
Sales for resale		56,110			55,717			393			0.7
Off-system sales		2,742,614			2,785,319			(42,705	)		(1.5	)

Total wholesale sales		2,798,724			2,841,036			(42,312	)		(1.5	)

Total kWh sales		10,214,169			10,062,489			151,680			1.5

Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	217,757		$	200,442		$	17,315			8.6	%
Commercial and industrial, small		182,405			176,863			5,542			3.1
Commercial and industrial, large		43,432			36,211			7,221			19.9
Sales to public authorities		86,564			77,909			8,655			11.1

Total retail non-fuel base revenues		530,158			491,425			38,733			7.9

Wholesale:
Sales for resale		2,186			2,037			149			7.3

Total non-fuel base revenues		532,344			493,462			38,882			7.9

Fuel revenues:
Recovered from customers during the period		158,418			183,653			(25,235	)		(13.7	)(1)
Under (over) collection of fuel		(28,680	)		(48,942	)		20,262			(41.4	)
New Mexico fuel in base rates		72,416			69,495			2,921			4.2

Total fuel revenues		202,154			204,206			(2,052	)		(1.0	)
Off-system sales		87,980			116,150			(28,170	)		(24.3	)
Other		26,717			27,910			(1,193	)		(4.3	)(2)

Total operating revenues	$	849,195		$	841,728		$	7,467			0.9

Average number of retail customers:
Residential		333,143			327,490			5,653			1.7	%
Commercial and industrial, small		36,665			36,230			435			1.2
Commercial and industrial, large		49			49			0			0.0
Sales to public authorities		4,594			4,947			(353	)		(7.1	)

Total		374,451			368,716			5,735			1.6

(1)	Excludes $23.0 million refunds in 2011 and refunds net of surcharges of $24.6 million in 2010 related to Texas deferred fuel revenues from prior periods.

(2)	Represents revenues with no related kWh sales.

Energy expenses

Our sources of energy include electricity generated from our nuclear, natural gas and coal generating plants and purchased power. Palo Verde represents approximately 39% of our available net generating capacity and approximately 68% and 59% of our Company-generated energy for the three and twelve months ended March 31, 2011, respectively. Fluctuations in the price of natural gas which also is the primary factor influencing the price of purchased power have had a significant impact on our cost of energy.

Energy expenses decreased $16.7 million or 21.4% for the three months ended March 31, 2011 when compared to 2010 primarily due to (i) decreased natural gas costs of $11.6 million due to a 17.9% decrease in the average price of natural gas and a 15.3% decrease in MWhs generated with natural gas, and (ii) decreased costs of purchased power of $10.4 million due to a 30.5% decrease in the market prices for power and a 7.9% decrease in the MWhs purchased. These decreases were partially offset by (i) increased coal costs of $2.9 million due to the amortization of final coal reclamation costs in our Texas and New Mexico jurisdictions of $2.6 million, and (ii) increased nuclear fuel costs of $2.3 million due to a 21.7% increase in the cost of nuclear fuel burned and a 3.9% increase in the MWhs generated with nuclear fuel. The table below details the sources and costs of energy for the three months ended March 31, 2011 and 2010.


	Three Months Ended March 31,
	2011						2010
Fuel Type	Cost		MWh		Cost per MWh		Cost		MWh		Cost per MWh
	(in thousands)						(in thousands)
Natural gas (a)	$	26,343		467,994	$	56.29	$	37,917		552,802	$	68.59
Coal (b)		5,363		166,971		32.12		2,434		120,409		20.21
Nuclear		11,053		1,329,807		8.31		8,742		1,280,312		6.83

Total		42,759		1,964,772		21.76		49,093		1,953,523		25.13
Purchased power		18,474		561,928		32.88		28,847		610,023		47.29

Total energy	$	61,233		2,526,700		24.23	$	77,940		2,563,546		30.40

(a)	The 2011 period excludes $6.6 million of natural gas expense and the related 149,340 MWhs for Newman Unit 5 phase II pre-commercial testing. This test generation generally was sold in the wholesale power markets.

(b)	The 2011 period includes amortization of final coal reclamation costs of $2.6 million.

Our energy expenses decreased $25.7 million or 8.5% for the twelve months ended March 31, 2011 when compared to 2010 primarily due to (i) decreased costs of purchased power of $26.5 million due to a 15.9% decrease in the average price of power purchased and a 10.2% decrease in MWhs purchased, and (ii) decreased natural gas costs of $9.2 million due to a 16.0% decrease in the average price of natural gas partially offset by an 11.9% increase in MWhs generated with natural gas. The decrease in energy expense was partially offset by (i) a $7.3 million increase in nuclear fuel expense due to a 19.3% increase in the cost of nuclear fuel burned and a 4.2% increase in MWhs generated with nuclear fuel, and (ii) a $2.7 million increase in coal costs due to the amortization of final coal reclamation costs in our Texas and New Mexico jurisdictions of $3.1 million. The table below details the sources and costs of energy for the twelve month periods ended March 31, 2011 and 2010.


	Twelve Months Ended March 31,
	2011						2010
Fuel Type	Cost		MWh		Cost per MWh		Cost		MWh		Cost per MWh
	(in thousands)						(in thousands)
Natural gas (a)	$	141,994		2,805,302	$	50.62	$	151,144		2,506,910	$	60.29
Coal		13,940		696,798		20.01		11,246		665,877		16.89
Nuclear (b)		37,561		4,974,808		7.55		30,247		4,776,028		6.33

Total		193,495		8,476,908		22.83		192,637		7,948,815		24.23
Purchased power		81,543		2,372,774		34.37		108,052		2,643,349		40.88

Total energy	$	275,038		10,849,682		25.35	$	300,689		10,592,164		28.39

(a)	The 2011 period excludes $6.6 million of natural gas expense and the related 149,340 MWhs for Newman Unit 5 phase II pre-commercial testing. This test generation generally was sold in the wholesale power markets.

(b)	Reduced by a DOE payment of $3.3 million for spent fuel storage costs recorded in the fourth quarter of 2010.

Other operations expense

Other operations expense increased $4.0 million, or 8.0%, for the three months ended March 31, 2011 compared to the same period last year due primarily to (i) increased administrative and general expense of $1.6 million due to increased outside services and increased regulatory expense for amortization of rate case expenses, (ii) increased Palo Verde operations expense of $1.2 million at all three units, and (iii) increased customer accounts and service expense of $1.1 million due to increased uncollectible customer accounts and costs incurred during the transition to a new customer billing system.

Other operations expense increased $11.6 million, or 5.4%, for the twelve months ended March 31, 2011 compared to the same period last year primarily due to (i) increased administrative and general expense of $7.9 million primarily due to increased pension and benefits expenses reflecting changes in actuarial assumptions used to calculate expense for our pension plans, increased outside services, and increased regulatory expense for amortization of rate case expenses and (ii) increased customer accounts and service expense of $4.8 million primarily related to increased uncollectible customer accounts and costs incurred during the transition to a new customer billing system.

Maintenance expense

Maintenance expense decreased $2.3 million, or 15.6%, for the three months ended March 31, 2011 compared to the same period last year primarily due to decreased maintenance expense at our coal and gas fired generating plants as a result of the timing of planned maintenance and decreased maintenance expense at Palo Verde during refueling outages. Maintenance expense decreased $6.2 million, or 10.2%, for the twelve months ended March 31, 2011 compared to the same period last year primarily due to decreased maintenance at Palo Verde of $4.0 million and decreased maintenance of $2.6 million related to our coal and gas fired generating plants reflecting the timing of planned outages at these plants.

Depreciation and amortization expense

Depreciation and amortization expense increased $1.7 million and $6.1 million, or 8.6% and 8.0%, for the three and twelve months ended March 31, 2011 compared to the same period last year primarily due to increases in depreciable plant balances and higher depreciation rates.

Taxes other than income taxes

Taxes other than income taxes increased $1.4 million and $6.6 million, or 11.8% and 13.5%, for the three and twelve months ended March 31, 2011 compared to the same period last year primarily due to higher revenue-related taxes in Texas resulting from an increase in billed revenues, an increase in the franchise tax rate for the City of El Paso in August 2011, and an increase in taxable property and property tax rates, which were partially offset by a decrease in payroll taxes.

Other income (deductions)

Other income (deductions) increased $1.7 million and $3.0 million for the three and twelve month periods ended March 31, 2011 compared to the same periods last year due to increased allowance for equity funds used during construction as a result of higher balances of construction work in progress and increased investment and interest income.

Interest charges (credits)

Interest charges (credits) increased $0.2 million, or 2%, for the three months ended March 31, 2011 compared to the same period last year primarily due to increased commitment fees on our new revolving credit facility entered into in September 2010. Interest charges (credits) for the twelve month period ended March 31, 2011 decreased less than $0.1 million compared to the same period last year and reflect an increase in allowance for borrowed funds used during construction (“ABFUDC”) as a result of increased construction work in progress subject to ABFUDC offset by increased commitment fees on our new revolving credit facility.

Income tax expense

Income tax expense decreased by $10.0 million, or 83.3%, in the first quarter of 2011 compared to 2010. In March 2010, we recognized the impact of the tax deduction for the Medicare Part D subsidies from the Patient Protection and Affordable Care Act (“PPACA”) with no comparable amount in 2011. Excluding this one-time adjustment, decreased tax expense reflects decreased pre-tax income and non-taxable AEFUDC. Income tax expense, before extraordinary item, increased by $1.1 million, or 2.7%, in the twelve months ended March 31, 2011 compared to 2010 primarily due to increased pre-tax income.

Extraordinary Item

As a regulated electric utility, we prepare our financial statements in accordance with the FASB guidance for regulated operations. FASB guidance for regulated operations requires us to show certain items as assets or liabilities on our balance sheet when the regulator provides assurance that these items will be charged to and collected from our customers or refunded to our customers. In the final order for PUCT Docket No. 37690, we were allowed to include the previously expensed loss on reacquired debt associated with the refinancing of first mortgage bonds in 2005 in our calculation of the weighted cost of debt to be recovered from our customers. We recorded the impacts of the re-application of FASB guidance for regulated operations to our Texas jurisdiction in 2006 as an extraordinary item. In order to establish this regulatory asset, we recorded an extraordinary gain of $10.3 million, net of income tax expense of $5.8 million, in our statements of operations for the quarter ended September 30, 2010. This

item was recorded as a regulatory asset at September 30, 2010 pursuant to the final order received from the PUCT and will be amortized over the remaining life of our 6% Senior Notes due in 2035.

New accounting standards

In January 2010, the FASB issued new guidance to improve disclosure requirements related to fair value measurements and disclosures. The new requirements include (i) disclosure of significant transfers in and out of Level 1 and Level 2 fair value measurements and the reasons for the transfers, and (ii) disclosure in the reconciliation for Level 3 fair value measurements of information about purchases, sales, issuances, and settlements on a gross basis. The new guidance also clarifies existing disclosures and requires (i) an entity to provide fair value measurement disclosures for each class of assets and liabilities, and (ii) disclosures about inputs and valuation techniques. The provisions of this new guidance were adopted in the first quarter of 2010 except for the reconciliation for the Level 3 fair value measurements on a gross basis which was adopted during the first quarter of 2011. During the three and twelve months ended March 31, 2011, we had no purchases, sales, issuances or settlements in the Level 3 category. This guidance requires additional disclosure on fair value measurements but does not impact our consolidated financial statements.

Inflation

For the last several years, inflation has been relatively low and, therefore, has had little impact on our results of operations and financial condition.

Liquidity and Capital Resources

We continue to maintain a strong capital structure which allows us to obtain financing from the capital markets at a reasonable cost. At March 31, 2011, our capital structure, including common stock, long-term debt, and the current portion of long-term debt and financing obligations, consisted of 48.2% common stock equity and 51.8% debt. At March 31, 2011, we had on hand $26.9 million in cash and cash equivalents, most of which was in funds invested in United States Treasury securities.

Our principal liquidity requirements in the near-term are expected to consist of capital expenditures to expand and support electric service obligations, expenditures for nuclear fuel inventory, interest payments on our indebtedness, and operating expenses including fuel costs, non-fuel operation and maintenance costs and taxes. In addition, on April 28, 2011, our Board of Directors declared a quarterly dividend of $0.22 per share payable on June 30, 2011. We expect to pay quarterly cash dividends totaling approximately $27 million during 2011. In addition, we may repurchase common stock in the future.

Capital requirements and resources have been impacted by the timing of the recovery of fuel costs through fuel recovery mechanisms in Texas and New Mexico and our sales for resale customer. We recover actual fuel costs from customers through fuel adjustment mechanisms in Texas, New Mexico, and from our sales for resale customer. We record deferred fuel revenues for the under-recovery or over-recovery of fuel costs until they can be recovered from or refunded to customers. In Texas, fuel costs are recovered through a fixed fuel factor. Effective July 1, 2010, we can seek to revise our fixed fuel factor based upon our approved formula at least four months after our last revision except in the month of December which allows us to adjust fuel rates to reflect changes in costs of natural gas.

Capital Requirements. During the three months ended March 31, 2011, our capital requirements primarily consisted of expenditures for the construction and purchase of electric utility plant, purchases of nuclear fuel, and the repurchase of common stock. Projected utility construction expenditures are to expand and update our transmission and distribution systems, add new generation, and make capital improvements and replacements at Palo Verde and other generating facilities. Newman Unit 5, a 288 MW gas-fired combined cycle combustion turbine generating unit, was completed in two phases at an estimated cost of approximately $230 million, including AFUDC. The first phase of Newman Unit 5 was completed in May 2009 and the second phase was completed April 30, 2011. As of March 31, 2011, we had expended $222.8 million, including AFUDC, on Newman Unit 5, including $13.1 million during 2011. Estimated construction expenditures for all capital projects for 2011 are approximately $205 million, and we expect cash from operations will continue to be a primary source of funds for these capital expenditures. See Part I, Item 1, “Business –Construction Program” in our 2010 Form 10-K. Capital expenditures were $45.4 million in the three months ended March 31, 2011 compared to $47.1 million in the three months ended March 31, 2010.

Since 1999, we have returned cash to stockholders through a stock repurchase program pursuant to which we have bought approximately 23.2 million shares of common stock at an aggregate cost of $353.8 million, including commissions. Under our program, purchases can be made at open market prices or in private transactions, and repurchased shares are available for issuance under employee benefit and stock incentive plans, or may be retired. During the first quarter of 2011, we repurchased 586,911 shares of common stock in the open market at an aggregate cost of $16.7 million as authorized under our 2010 Plan. On March 21, 2011, the Board of Directors authorized additional repurchases of

up to 2.5 million shares of the Company’s outstanding common stock (the “2011 Plan”). As of March 31, 2011, 2,589,360 shares remain available for repurchase under our stock repurchase programs.

Our cash requirements for federal and state income taxes vary from year to year based on taxable income, which is influenced by the timing of revenues and expenses recognized for income tax purposes. Due to accelerated tax deductions, tax payments are expected to be minimal in 2011.

We continually evaluate our funding requirements related to our retirement plans, other postretirement benefit plans, and decommissioning trust funds. We contributed $12.5 million of the projected $13.9 million 2011 annual contribution to our retirement plans during the three months ended March 31, 2011. In the three months ended March 31, 2011, we contributed $2.2 million to fund our OPEB plan for the entire year of 2011, and $2.1 million of the projected $8.5 million 2011 annual contribution to our decommissioning trust funds. We are in compliance with the funding requirements of the federal government for our benefit plans and decommissioning trust.

Capital Resources. During the three months ended March 31, 2011, we had decreased cash from operations when compared to the same period in 2010 due primarily to payments of $14.7 million in the first quarter of 2011 to fund our pension and OPEB employee benefit plans for substantially all of 2011 compared to $2.7 million in funding in the first quarter of 2010, partially offset by an increase in net cash payments for operations.

We maintain a $200 million revolving credit facility for interim financing of construction and operations and the financing of nuclear fuel through the Rio Grande Resources Trust (“RGRT”). RGRT is the trust through which we finance our portion of nuclear fuel for Palo Verde and is consolidated in the Company’s financial statements. The revolving credit facility has a term ending September 2014, and the Company may request that the facility be increased up to $300 million during the term of the facility subject to the lenders’ agreement. The terms of the agreement provide that amounts we borrow under the facility may be used for working capital and general corporate purposes. The total amount borrowed for nuclear fuel by RGRT at March 31, 2011 was $123.0 million of which $13.0 million was borrowed under the revolving credit facility and $110 million was borrowed through senior notes. Borrowings by RGRT for nuclear fuel as of March 31, 2010, were $118.1 million including accrued interest and fees, all of which was borrowed under the revolving credit facility then in effect. Interest costs on borrowings to finance nuclear fuel are accumulated by RGRT and charged to the Company as fuel is consumed and recovered from customers through fuel recovery charges. No borrowings were outstanding under the revolving credit facility at March 31, 2011 for working capital or general corporate purposes.

We expect to have sufficient liquidity to finance construction expenditures and other capital requirements through 2011 through cash balances, cash from operations and our revolving credit facility. In addition, we may seek to issue debt in the capital markets to finance capital requirements.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk due to changes in interest rates, equity prices and commodity prices. See our 2010 Form 10-K, Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” for a complete discussion of the market risks we face and our market risk sensitive assets and liabilities. As of March 31, 2011, there have been no material changes in the market risks we faced or the fair values of assets and liabilities disclosed in Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” in our 2010 Form 10-K.

Item 4.

Controls and Procedures

Evaluation of disclosure controls and procedures. Under the supervision and with the participation of our management, including our chief executive officer and our chief financial officer, we conducted an evaluation pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934 of our disclosure controls and procedures as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934. Based on that evaluation, our chief executive officer and our chief financial officer concluded that, as of March 31, 2011, our disclosure controls and procedures are effective.

Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting in connection with the evaluation required by paragraph (d) of the Securities Exchange Act of 1934 Rules 13a-15 or 15d-15, that occurred during the quarter ended March 31, 2011, that materially affected, or that were reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

We hereby incorporate by reference the information set forth in Part I of this report under Notes B and G of Notes to Consolidated Financial Statements.

Item 1A.

Risk Factors

Our 2010 Form 10-K includes a detailed discussion of our risk factors.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

(c)

Issuer Purchases of Equity Securities.


Period	Total Number of Shares Purchased			Average Price Paid per Share (Including Commissions)		Total Number of Shares Purchased as Part of a Publicly Announced Program		Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs (a)
January 1 to January 31, 2011		0		$	0		0		676,271
February 1 to February 28, 2011		120,000			27.65		120,000		556,271
March 1 to March 31, 2011		483,380	(b)		28.61		466,911		2,589,360

(a)	On March 21, 2011, the Company’s Board of Directors authorized a stock repurchase program permitting the repurchase of up to 2.5 million additional shares of its outstanding common stock.

(b)	Total Number of Shares Purchased includes 16,469 shares acquired through a stock option exercise. The Average Price Paid per Share (including commissions) was not affected by the 16,469 shares acquired through a stock option exercise.

Item 6.

Exhibits

See Index to Exhibits incorporated herein by reference.

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.


		EL PASO ELECTRIC COMPANY

By:		/s/ DAVID G. CARPENTER
		David G. Carpenter
		Senior Vice President - Chief Financial Officer
		(Duly Authorized Officer and Principal Financial Officer)

Dated: May 6, 2011

EL PASO ELECTRIC COMPANY

INDEX TO EXHIBITS


Exhibit Number		Exhibit

	†10.01	Form of Directors’ Restricted Stock Award Agreement between the Company and certain directors of the Company. (Identical in all material respects to Exhibit 10.07 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999)

	10.02	Amended and Restated Employment Agreement between the Company and David W. Stevens, dated March 2, 2011. Amendment to Exhibit 10.49 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.

	15	Letter re Unaudited Interim Financial Information

	31.01	Certifications pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

	32.01	Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

	101.INS	XBRL Instance Document

	101.SCH	XBRL Taxonomy Extension Schema Linkbase Document

	101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

	101.LAB	XBRL Taxonomy Extension Label Linkbase Document

	101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

†	In lieu of non-employee director cash compensation, six agreements, dated as of January 1 and April 1, 2011, substantially identical in all material respects to this Exhibit, have been entered into with Catherine A. Allen; Kenneth R. Heitz; and Patricia Z. Holland-Branch; directors of the Company.