Edgar Filing: EL PASO ELECTRIC CO /TX/

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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 June 30, 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 July 29, 2011, there were 41,822,857 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 – June 30, 2011 and December 31, 2010			1

Consolidated Statements of Operations – Three Months, Six Months and Twelve Months Ended June 30, 2011 and 2010			3

Consolidated Statements of Comprehensive Operations – Three Months, Six Months and Twelve Months Ended June 30, 2011 and 2010			5

Consolidated Statements of Cash Flows – Six Months Ended June 30, 2011 and 2010			6

Notes to Consolidated Financial Statements			7

Report of Independent Registered Public Accounting Firm			32

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		33

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		50

Item 4.	Controls and Procedures		50

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings		51

Item 1A.	Risk Factors		51

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		51

Item 6.	Exhibits		51

(i)

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS


	June 30, 2011			December 31, 2010
	(Unaudited)
ASSETS (In thousands)
Utility plant:
Electric plant in service	$	2,718,910		$	2,522,862
Less accumulated depreciation and amortization		(1,085,881	)		(1,047,498	)

Net plant in service		1,633,029			1,475,364
Construction work in progress		161,080			285,086
Nuclear fuel; includes fuel in process of $33,209 and $47,746, respectively		164,815			150,774
Less accumulated amortization		(51,617	)		(45,471	)

Net nuclear fuel		113,198			105,303

Net utility plant		1,907,307			1,865,753


Current assets:
Cash and cash equivalents		5,106			79,184
Accounts receivable, principally trade, net of allowance for doubtful accounts of $2,267 and $2,885, respectively		107,457			71,685
Accumulated deferred income taxes		11,185			25,818
Inventories, at cost		38,415			36,132
Income taxes receivable		2,508			12,656
Undercollection of fuel revenues		6,851			0
Prepayments and other		9,804			4,543

Total current assets		181,326			230,018

Deferred charges and other assets:
Decommissioning trust funds		162,702			153,878
Regulatory assets		88,107			88,557
Other		28,030			26,560

Total deferred charges and other assets		278,839			268,995

Total assets	$	2,367,472		$	2,364,766

See accompanying notes to consolidated financial statements.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS (Continued)


	June 30, 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, 65,241,772 and 65,121,689 shares issued, and 199,619 and 143,371 restricted shares, respectively	$	65,441		$	65,265
Capital in excess of stated value		306,926			305,068
Retained earnings		841,375			810,858
Accumulated other comprehensive loss, net of tax		(30,981	)		(33,177	)

		1,182,761			1,148,014
Treasury stock, 23,621,213 and 22,693,995 shares, respectively, at cost		(364,459	)		(337,639	)

Common stock equity		818,302			810,375
Long-term debt		849,771			849,745

Total capitalization		1,668,073			1,660,120


Current liabilities:
Short-term borrowings under the revolving credit facility		39,642			4,704
Accounts payable, principally trade		52,700			41,795
Taxes accrued		25,350			29,172
Interest accrued		12,108			12,099
Overcollection of fuel revenues		0			18,976
Other		22,795			24,207

Total current liabilities		152,595			130,953


Deferred credits and other liabilities:
Accumulated deferred income taxes		287,765			286,730
Accrued pension liability		83,918			93,471
Asset retirement obligation		69,295			92,911
Accrued postretirement benefit liability		62,683			61,594
Regulatory liabilities		15,007			14,489
Other		28,136			24,498

Total deferred credits and other liabilities		546,804			573,693


Commitments and contingencies

Total capitalization and liabilities	$	2,367,472		$	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 June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Operating revenues	$	242,605		$	211,397		$	418,717		$	415,565

Energy expenses:
Fuel		61,318			50,752			104,077			99,845
Purchased and interchanged power		16,297			19,552			34,771			48,399

		77,615			70,304			138,848			148,244

Operating revenues net of energy expenses		164,990			141,093			279,869			267,321

Other operating expenses:
Other operations		57,209			51,544			111,316			101,642
Maintenance		16,760			15,735			28,996			30,235
Depreciation and amortization		19,524			20,167			40,460			39,451
Taxes other than income taxes		13,376			13,170			26,503			24,913

		106,869			100,616			207,275			196,241

Operating income		58,121			40,477			72,594			71,080

Other income (deductions):
Allowance for equity funds used during construction		2,011			2,707			5,062			5,247
Investment and interest income, net		1,590			840			3,975			1,938
Miscellaneous non-operating income		1			151			271			153
Miscellaneous non-operating deductions		(698	)		(529	)		(1,413	)		(888	)

		2,904			3,169			7,895			6,450

Interest charges (credits):
Interest on long-term debt and revolving credit facility		13,526			12,241			27,024			24,442
Other interest		237			25			534			65
Capitalized interest		(1,290	)		(258	)		(2,546	)		(486	)
Allowance for borrowed funds used during construction		(1,180	)		(1,534	)		(3,029	)		(3,101	)

		11,293			10,474			21,983			20,920

Income before income taxes		49,732			33,172			58,506			56,610
Income tax expense		16,742			11,665			18,741			23,654

Net income	$	32,990		$	21,507		$	39,765		$	32,956

Basic earnings per share	$	0.78		$	0.49		$	0.94		$	0.75

Diluted earnings per share	$	0.78		$	0.49		$	0.94		$	0.75

Dividends declared per share of common stock	$	0.22		$	0.00		$	0.22		$	0.00

Weighted average number of shares outstanding		41,853,552			43,460,458			42,079,568			43,598,933

Weighted average number of shares and dilutive potential shares outstanding		42,076,659			43,557,788			42,298,716			43,710,026

See accompanying notes to consolidated financial statements.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands except for share data)


	Twelve Months Ended June 30,
	2011			2010
Operating revenues	$	880,403		$	849,476

Energy expenses:
Fuel		204,061			199,506
Purchased and interchanged power		78,288			99,309

		282,349			298,815

Operating revenues net of energy expenses		598,054			550,661

Other operating expenses:
Other operations		233,895			217,545
Maintenance		55,584			60,066
Depreciation and amortization		82,020			78,012
Taxes other than income taxes		56,079			49,883

		427,578			405,506

Operating income		170,476			145,155

Other income (deductions):
Allowance for equity funds used during construction		10,631			9,346
Investment and interest income, net		7,352			7,387
Miscellaneous non-operating income		1,486			499
Miscellaneous non-operating deductions		(3,731	)		(2,330	)

		15,738			14,902

Interest charges (credits):
Interest on long-term debt and revolving credit facility		53,408			48,834
Other interest		723			209
Capitalized interest		(4,547	)		(933	)
Allowance for borrowed funds used during construction		(6,599	)		(5,757	)

		42,985			42,353

Income before income taxes and extraordinary item		143,229			117,704
Income tax expense		46,103			42,855

Income before extraordinary item		97,126			74,849
Extraordinary gain related to Texas regulatory assets, net of tax		10,286			0


Net income	$	107,412		$	74,849


Basic earnings per share:
Income before extraordinary item	$	2.28		$	1.70
Extraordinary gain related to Texas regulatory assets, net of tax		0.24			0.00


Net income	$	2.52		$	1.70


Diluted earnings per share:
Income before extraordinary item	$	2.27		$	1.69
Extraordinary gain related to Texas regulatory assets, net of tax		0.24			0.00


Net income	$	2.51		$	1.69


Dividends declared per share of common stock	$	0.22		$	0.00


Weighted average number of shares outstanding		42,376,298			43,943,503


Weighted average number of shares and dilutive potential shares outstanding		42,595,011			44,059,201

See accompanying notes to consolidated financial statements.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS

(Unaudited)

(In thousands)


	Three Months Ended June 30,						Six Months Ended June 30,						Twelve Months Ended June 30,
	2011			2010			2011			2010			2011			2010
Net income	$	32,990		$	21,507		$	39,765		$	32,956		$	107,412		$	74,849
Other comprehensive income (loss):
Unrecognized pension and postretirement benefit costs:
Net loss arising during period		0			0			0			0			(9,874	)		(48,580	)
Prior service benefit		0			0			0			0			26,605			0
Reclassification adjustments included in net income for amortization of:
Prior service benefit		(1,450	)		(677	)		(2,905	)		(1,377	)		(4,282	)		(2,754	)
Net loss		1,778			787			3,253			1,687			4,940			2,500
Net unrealized gains (losses) on marketable securities:
Net holding gains (losses) arising during period		416			(6,401	)		2,589			(3,978	)		13,232			6,480
Reclassification adjustments for net (gains) losses included in net income		2			378			(203	)		409			(490	)		(2,644	)
Net losses on cash flow hedges:
Reclassification adjustment for interest expense included in net income		88			83			176			166			348			327

Total other comprehensive income (loss) before income taxes		834			(5,830	)		2,910			(3,093	)		30,479			(44,671	)

Income tax benefit (expense) related to items of other comprehensive income (loss):
Unrecognized pension and postretirement benefit costs		(124	)		(39	)		(131	)		(112	)		(6,306	)		16,640
Net unrealized gains (losses) on marketable securities		(157	)		1,205			(517	)		714			(2,588	)		(767	)
Losses on cash flow hedges		(33	)		(30	)		(66	)		(60	)		(128	)		(118	)

Total income tax benefit (expense)		(314	)		1,136			(714	)		542			(9,022	)		15,755


Other comprehensive income (loss), net of tax		520			(4,694	)		2,196			(2,551	)		21,457			(28,916	)

Comprehensive income	$	33,510		$	16,813		$	41,961		$	30,405		$	128,869		$	45,933

See accompanying notes to consolidated financial statements.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)


	Six Months Ended June 30,
	2011			2010
Cash flows from operating activities:
Net income	$	39,765		$	32,956
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service		40,460			39,451
Amortization of nuclear fuel		17,958			13,758
Deferred income taxes, net		12,647			14,206
Allowance for equity funds used during construction		(5,062	)		(5,247	)
Other amortization and accretion		11,772			7,260
Other operating activities		(216	)		44
Change in:
Accounts receivable		(35,772	)		(26,175	)
Inventories		(2,741	)		1,148
Net overcollection (undercollection) of fuel revenues		(25,827	)		420
Prepayments and other		(5,713	)		(2,266	)
Accounts payable		4,934			(15,880	)
Taxes accrued		6,326			3,220
Interest accrued		9			(7	)
Other current liabilities		(1,412	)		(655	)
Deferred charges and credits		(7,547	)		(2,708	)

Net cash provided by operating activities		49,581			59,525

Cash flows from investing activities:
Cash additions to utility property, plant and equipment		(86,950	)		(90,603	)
Cash additions to nuclear fuel		(24,140	)		(26,981	)
Capitalized interest and AFUDC:
Utility property, plant and equipment		(8,091	)		(8,348	)
Nuclear fuel		(2,546	)		(486	)
Allowance for equity funds used during construction		5,062			5,247
Decommissioning trust funds:
Purchases, including funding of $4.3 and $4.1 million, respectively		(42,641	)		(39,809	)
Sales and maturities		36,406			34,205
Other investing activities		188			(867	)

Net cash used for investing activities		(122,712	)		(127,642	)

Cash flows from financing activities:
Repurchases of common stock		(26,320	)		(9,988	)
Dividends paid		(9,248	)		0
Borrowings under the revolving credit facility:
Proceeds		65,770			25,092
Payments		(30,832	)		(9,264	)
Other financing activities		(317	)		(103	)

Net cash provided by (used for) financing activities		(947	)		5,737

Net decrease in cash and cash equivalents		(74,078	)		(62,380	)
Cash and cash equivalents at beginning of period		79,184			91,790

Cash and cash equivalents at end of period	$	5,106		$	29,410

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 June 30, 2011 and December 31, 2010; the results of its operations and comprehensive operations for the three, six and twelve months ended June 30, 2011 and 2010; and its cash flows for the six months ended June 30, 2011 and 2010. The results of operations and comprehensive operations for the three and six months ended June 30, 2011 and the cash flows for the six months ended June 30, 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 to 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. The Company presents revenues net of sales taxes in its consolidated statements of operations.

Accrued unbilled revenues included in accounts receivable are presented below (in thousands):


	June 30, 2011		December 31, 2010
Accrued unbilled revenues	$	30,573	$	16,644

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

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, in its statements of operations for the quarter ended September 30, 2010 as noted below (in thousands):


Extraordinary gain, net of income tax expense	$	10,286
Income tax expense related to extraordinary gain		5,769

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.

Supplemental Cash Flow Disclosures (in thousands)


	Six Months Ended June 30,
	2011			2010
Cash paid for:
Interest on long-term debt and borrowing under the revolving credit facility	$	24,199		$	23,825
Income taxes paid (refund)		(3,101	)		5,291
Non-cash financing activities:
Grants of restricted shares of common stock		3,193			1,823
Issuance of performance shares		565			662
Acquisition of treasury stock for options
exercised		500			0

B. New Accounting Standards

In June 2011, the FASB issued new guidance to improve the comparability, consistency, and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. The new guidance requires an entity to present the total of comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both presentations, an entity is required to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement(s) where the components of net income and the components of other comprehensive income are presented. Historically, the Company has used the consecutive two-statement approach; however, this new guidance will require additional disclosure on the Company’s statement of operations and related notes. The new guidance is required to be applied retrospectively and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, six and twelve months ended June 30, 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 did not impact the Company’s consolidated financial statements.

C. 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 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. The new rate structure 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 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. 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 provided 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

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 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.

The Company has filed the following petitions with the PUCT to refund recent fuel cost over-recoveries, due primarily to fluctuations in natural gas markets and consumption levels. The table summarizes the docket number assigned by the PUCT, the dates the Company filed the petitions and the dates a final order was issued by the PUCT approving the refunds to customers. The fuel cost over-recovery periods represent the months in which the over-recoveries took place and the refund periods represent the billing month(s) in which customers received the refund amounts shown, including interest (in thousands):

Docket

No.

Date Filed

Date Approved

Recovery Period

Refund Period

Refund
Amount

37788

December 17, 2009

February 11, 2010

September – November 2009

February 2010

11,800

38253

May 12, 2010

July 15, 2010

December 2009 – March 2010

July – August 2010

11,100

38802

October 20, 2010

December 16, 2010

April – September 2010

December 2010

12,800

39159

February 18, 2011

May 3, 2011

October – December 2010

April 2011

11,800

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

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(Unaudited)

The Company has filed the following petitions with the PUCT to revise its fixed fuel factor pursuant to the fuel factor formula authorized in PUCT Docket No. 37690:


Docket No.	Date Filed	Date Approved	Increase/(Decrease) in Fuel Factor	Effective Billing Month
38895	November 23, 2010	January 6, 2011	(14.7%)	January 2011
39599	July 15, 2011	July 26, 2011 (1)	9.4%	August 2011

(1)	ALJ approved on an interim basis.

Application for Approval to Revise Energy Efficiency Cost Recovery Factor for 2012. On May 2, 2011, 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. 39376. A unanimous settlement resolving all issues was filed with the PUCT on July 15, 2011. The settlement allows the Company to recover $8.3 million and supports the Company’s request to revise its demand and energy goals and EECRF cost caps as well as the Company’s request to increase its 2012 EECRF, effective beginning with the first billing cycle of its January 2012 billing month. The Company expects the PUCT to issue an order approving the settlement at its August 19, 2011 open meeting.

Petition for Approval to Revise Military Base Discount Recovery Factor. On July 14, 2011, the Company filed with the PUCT a petition requesting approval to revise its Military Base Discount Recovery Factor (“MBDRF”) tariff to account for under-recovery of discount charges during 2010 and for 2011 discounts. The total requested in the filing is $4.3 million and the case was assigned Tariff Control No. 39590.

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 conducted discovery in the investigation. On February 14, 2011, the Company also filed a report on this weather event. On May 13, 2011, the PUCT Staff issued a report stating that, as of then, it had not identified violations of the Texas electric utility regulatory statute or PUCT rules by the Company. The report also stated that the PUCT Staff would continue to monitor the extreme cold weather event results

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

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(Unaudited)

and subsequent forthcoming information as the Company and other regulatory agencies complete their ongoing investigations.

On February 15, 2011, the City Council of El Paso adopted a motion that, upon completion of hearings and investigations concerning the extreme cold weather event, requires the Mayor to call for Special City Council meetings or public hearings, on utility issues related to the weather event.

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 new rate structure 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. 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.

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 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 in the third quarter of 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 final order on this case approving the CCN was issued on June 23, 2011.

Application for Approval of 2011 Energy Efficiency Plan. On February 15, 2011, the Company filed its Application for Approval of New and Modified Energy Efficiency Programs for 2011 with the NMPRC. On June 22, 2011, parties to this case entered into a partial stipulation, agreeing on all issues, except for a military base free-ridership issue. On June 24, 2011, the New Mexico Attorney General filed a statement in opposition to the proposed partial stipulation. On July 8, 2011, the Company filed its

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

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(Unaudited)

testimony in support of the partial stipulation. A hearing in this case was held on July 27-28, 2011 and a recommended decision from the hearing examiner is expected in the fourth quarter of 2011.

2011 Renewable Procurement Plan Pursuant to the Renewable Energy Act. On July 1, 2011, the Company filed its Application for Approval of its 2011 Renewable Procurement Plan with the NMPRC, which was assigned NMPRC Case No. 11-00263-UT. The filing identified renewable resources intended to meet the Company’s Renewable Portfolio Standard (“RPS”) requirements in 2012 and 2013. The renewable resources in the 2011 Renewable Procurement Plan which were previously approved by the NMPRC will allow the Company to meet the full RPS requirement of 10 percent of the Company’s jurisdictional retail energy sales for 2012 and 2013. The Company’s 2011 Plan also addresses the diversity targets in 2012 and 2013 required by NMPRC Rule 572 and demonstrates that the Company will meet those targets. The plan also demonstrates that the Company will meet its solar diversity target in 2012 and comply with the terms of a previously-approved variance for 2011.

Investigation into Rates for Church Customers. On July 12, 2011, the NMPRC initiated an investigation into the rates the Company charges its church customers which were approved in Case No. 09-00171-UT. The investigation, Case No. 11-00276, was ordered to determine whether the Company’s rates to its church customers are unjust and unreasonable and should be revised. The Company filed a response on August 1, 2011. The case is pending.

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

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

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(Unaudited)

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 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 was filed with the FERC on June 24, 2011 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 $5.2 million in transmission revenues for the period February 1, 2006 through June 30, 2011, including 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 also add approximately $0.4 million to its transmission revenues for the remainder 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

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

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(Unaudited)

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.

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 the FERC has not taken any additional action on the matter.

D. 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 Units 1, 2 and 3 will now expire in 2045, 2046 and 2047, respectively. For the three months ended June 30, 2011, the extension of the operating licenses had the effect of reducing depreciation and amortization expense by approximately $2.6 million and reducing the accretion expense on the Palo Verde asset retirement obligation by approximately $0.7 million.

Decommissioning. Decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers retained by APS. On March 30, 2011, the Palo Verde Participants approved the 2010 Palo Verde decommissioning study (the “2010 Study”). The 2010 Study reflects the increase in the license life from 40 years to 60 years. The 2010 Study estimated that the Company must fund approximately $357.4 million (stated in 2010 dollars) to cover its share of decommissioning costs which was an increase in decommissioning costs from the 2007 Palo Verde decommissioning study (the “2007 Study”). The net effect of these changes will result in lower asset retirement obligations and lower expenses in the future. See Note E for additional discussion. Although the 2010 Study was based on the latest available information, there can be no assurance that decommissioning cost estimates will not increase in the future or that regulatory requirements will not change. In addition, until a new low-level radioactive waste repository opens and operates for a number of years, estimates of the cost to dispose of low-level radioactive waste are subject to significant uncertainty.

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 northeastern 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

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

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(Unaudited)

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 Nuclear Generating Station, is actively engaged with NEI and INPO in these efforts. Additionally, the NRC is performing it own independent review of the events at Fukishima Daiichi. On March 23, 2011, the NRC Commissioners voted to launch a review of U.S. nuclear power plant safety. The NRC established an agency Task Force to conduct both near and long-term analyses of the lessons learned from the Fukishima Daiichi nuclear accident in Japan. The report of the Near-Term Task Force was released on July 12, 2011. The Task Force conducted a systematic and methodical review of NRC processes and regulations to make policy recommendations in light of the accident at Fukishima Daiichi Nuclear Power Plant. The Task Force made certain recommendations and concluded that a sequence of events like the Fukishima accident is unlikely to occur in the United States and some appropriate mitigation measures have been implemented reducing the likelihood of core damage and radiological releases. The Task Force further concluded that continued licensing activities do not pose an imminent risk to public health and safety.

E. Accounting for Asset Retirement Obligations

The Company complies with FASB guidance for asset retirement obligations (“ARO”). FASB guidance requires the Company to revise its previously recorded ARO for any changes in estimated cash flows including changes in estimated probabilities related to timing of settlements. In the second quarter, the Company implemented the recently approved 2010 Palo Verde decommissioning study, and as a result, revised its ARO related to Palo Verde to (i) increase estimated cash flows from the 2007 Study to the 2010 Study, and (ii) change estimated probabilities due to Palo Verde license extension (see Note D). The assumptions used to calculate the original ARO liability and the revised ARO liability are as follows:


	Escalation Rate			Credit-Risk Adjusted Discount Rate
Original ARO liability		3.6	%		9.5	%
Incremental ARO liability		3.6	%		6.2	%

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

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A roll forward of the Company’s ARO liability is presented below and revisions to estimates include both the increase to estimated cash flows and the change in estimated probabilities due to Palo Verde license extension.


	2011			2010
	(in thousands)
ARO liability at beginning of year	$	92,911		$	85,358
Revisions to estimates		(27,076	)		0
Accretion expense		3,532			3,917
Liabilities settled		(72	)		(303	)

ARO liability at June 30	$	69,295		$	88,972

F. Common Stock

Repurchase Program. Details regarding the Company’s stock repurchase program are presented below:


	Since 1999 (a)		Three Months Ended June 30, 2011		Six Months Ended June 30, 2011		Authorized Shares
Shares repurchased		23,534,478		323,838		910,749
Cost, including commission (in thousands)	$	363,459	$	9,645	$	26,320
2010 Plan balance at December 31, 2010								676,271
2011 Plan repurchase shares authorized (b)								2,500,000
Total remaining shares available for repurchase at June 30, 2011								2,265,522

(a)	Represents repurchased shares and cost since inception of the stock repurchase program in 1999.

(b)	On March 21, 2011, the Board of Directors authorized an additional repurchase of the Company’s common stock (the “2011 Plan”).

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 July 28, 2011 the Board of Directors declared a quarterly cash dividend of $0.22 per share payable on September 30, 2011 to shareholders of record on September 15, 2011. On June 30, 2011 the Company paid $9.3 million in dividends to shareholders.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

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(Unaudited)

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


	Three Months Ended June 30,
	2011			2010
Weighted average number of common shares outstanding:
Basic number of common shares outstanding		41,853,552			43,460,458
Dilutive effect of unvested performance awards		195,078			40,740
Dilutive effect of stock options		28,029			56,590

Diluted number of common shares outstanding		42,076,659			43,557,788

Basic net income per common share:
Net income	$	32,990		$	21,507
Income allocated to participating restricted stock		(157	)		(91	)

Net income available to common shareholders	$	32,833		$	21,416

Diluted net income per common share:
Net income	$	32,990		$	21,507
Income reallocated to participating restricted stock		(157	)		(90	)

Net income available to common shareholders	$	32,833		$	21,417

Basic net income per common share:
Distributed earnings	$	0.22		$	0.00
Undistributed earnings		0.56			0.49

Basic net income per common share	$	0.78		$	0.49

Diluted net income per common share:
Distributed earnings	$	0.22		$	0.00
Undistributed earnings		0.56			0.49

Diluted net income per common share	$	0.78		$	0.49


	Six Months Ended June 30,
	2011			2010
Weighted average number of common shares outstanding:
Basic number of common shares outstanding		42,079,568			43,598,933
Dilutive effect of unvested performance awards		182,252			56,542
Dilutive effect of stock options		36,896			54,551

Diluted number of common shares outstanding		42,298,716			43,710,026

Basic net income per common share:
Net income	$	39,765		$	32,956
Income allocated to participating restricted stock		(179	)		(132	)

Net income available to common shareholders	$	39,586		$	32,824

Diluted net income per common share:
Net income	$	39,765		$	32,956
Income reallocated to participating restricted stock		(178	)		(132	)

Net income available to common shareholders	$	39,587		$	32,824

Basic net income per common share:
Distributed earnings	$	0.22		$	0.00
Undistributed earnings		0.72			0.75

Basic net income per common share	$	0.94		$	0.75

Diluted net income per common share:
Distributed earnings	$	0.22		$	0.00
Undistributed earnings		0.72			0.75

Diluted net income per common share	$	0.94		$	0.75

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

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(Unaudited)


	Twelve Months Ended June 30,
	2011			2010
Weighted average number of common shares outstanding:
Basic number of common shares outstanding		42,376,298			43,943,503
Dilutive effect of unvested performance awards		164,636			56,146
Dilutive effect of stock options		54,077			59,552

Diluted number of common shares outstanding		42,595,011			44,059,201

Basic net income per common share:
Net income	$	107,412		$	74,849
Income allocated to participating restricted stock		(458	)		(287	)

Net income available to common shareholders	$	106,954		$	74,562

Diluted net income per common share:
Net income	$	107,412		$	74,849
Income reallocated to participating restricted stock		(456	)		(286	)

Net income available to common shareholders	$	106,956		$	74,563

Basic net income per common share:
Distributed earnings	$	0.22		$	0.00
Undistributed earnings		2.30			1.70

Basic net income per common share	$	2.52		$	1.70

Diluted net income per common share:
Distributed earnings	$	0.22		$	0.00
Undistributed earnings		2.29			1.69

Diluted net income per common share	$	2.51		$	1.69

The amount of restricted stock awards, performance shares and stock options excluded from the calculation of the diluted number of common shares outstanding because their effect was antidilutive is presented below:


	Three Months Ended June 30,				Six Months Ended June 30,				Twelve Months Ended June 30,
	2011		2010		2011		2010		2011		2010
Restricted stock awards		69,639		64,840		81,858		72,415		79,991		71,653
Performance shares (a)		0		96,900		0		48,450		0		65,763
Stock options		0		0		0		0		0		0

(a)	Performance shares were excluded from the computation of diluted earnings per share as no payouts would be required based upon performance at the end of each corresponding period. These amounts assume a 100% performance level payout.

G. 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. The Company is currently under audit in the federal jurisdiction for 2009 and in Texas for 2007. A deficiency notice relating to the Company’s 1998 through 2003 income tax returns in

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

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Arizona contests a pollution control credit, a research and development credit, and the sales and property apportionment factors. The Company is contesting these adjustments.

On March 23, 2010, the Patient Protection and Affordable Care Act (“PPACA”) was signed into law. A major provision of the law is that, beginning in 2013, the income tax deductions for 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 and recorded a non-cash charge to income tax expense of approximately $4.8 million in the first quarter of 2010.

The Company’s consolidated effective tax rates are represented in the tables below.


	Effective Tax Rates
	Three Months Ended June 30,						Six Months Ended June 30,						Twelve Months Ended June 30,
	2011			2010			2011			2010			2011			2010
Federal statutory tax rate		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%
Consolidated effective tax rate		33.7	%		35.2	%		32.0	%		41.8	%		32.6	%		36.4	%
Without PPACA		33.7	%		35.2	%		32.0	%		32.6	%		32.6	%		32.0	%

The Company’s consolidated effective tax rate for the three, six and twelve months ended June 30, 2011 and the three months ended June 30, 2010, differs from the federal statutory tax rate primarily due to the allowance for equity funds used during construction and state income taxes. The Company’s effective tax rates for the six and twelve months ended June 30, 2010, without the effect of the enactment of the PPACA differ from the federal statutory tax rate primarily due to state income taxes, the allowance for equity funds used during construction, the tax rate on earnings on qualified decommissioning trust investments, and various permanent tax differences.

H. 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 C 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.

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. In addition to the contracts disclosed in the

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

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(Unaudited)

2010 10-K, in April 2011, the amount of energy purchased from Freeport-McMoran Copper and Gold Energy Services LLC was increased to 125 MW through December 2013, in accordance with the power purchase and sale agreement.

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/Cross-State Air Pollution Rule. On July 6, 2011, the EPA finalized the Clean Air Transport Rule (“CATR”), renaming it the Cross-State Air Pollution Rule (“CSAPR”). The rule replaces CAIR and intends to address air quality issues in downwind states, specifically eastern, central and southern parts of the United States. CSAPR will require 27 states, including Texas, to issue regulations and develop a scheme by which power plants in their respective jurisdictions will further reduce SO₂ and NOx. The CSAPR does not apply to the Company’s facilities in New Mexico. The rule becomes effective on January 1, 2012, but it is unclear when and how the states would issue implementing regulations. The Company is evaluating the rule to determine potential impacts; however, due to uncertainties with the state implementation, the ultimate impact of this rule on the Company’s operations cannot currently be determined, but it could be material.

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

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

the new ozone standards, the ultimate impact on the Company’s facilities cannot be determined. The impact of these regulations and associated costs, however, 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 by Congress in the future. The EPA has also proposed using the CAA to limit carbon dioxide and other GHG emissions.

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 and modified boilers and for existing facilities in September 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.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 June 30, 2011, related to compliance with federal and state environmental standards. However, unforeseen expenses associated with environmental compliance or remediation may occur and could have a material adverse effect on the future operations and financial condition of the Company.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The Company incurred the following expenditures during the three, six and twelve months ended June 30, 2011 and 2010 to comply with federal environmental statutes (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,				Twelve Months Ended June 30,
	2011		2010		2011		2010		2011		2010
Clean Air Act	$	253	$	71	$	293	$	288	$	620	$	505
Clean Water Act		53		69		109		103		184		569

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 an agreement with the EPA and a former property owner to resolve this matter and on June 30, 2011 the Company entered 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 June 30, 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.

I. 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.

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

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

J. Employee Benefits

Retirement Plans

The net periodic benefit cost recognized for the three, six and twelve months ended June 30, 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 June 30,						Six Months Ended June 30,						Twelve Months Ended June 30,
	2011			2010			2011			2010			2011			2010
Components of net periodic benefit cost:
Service cost	$	1,682		$	1,532		$	3,425		$	3,032		$	6,457		$	5,799
Interest cost		3,499			3,390			6,994			6,815			13,808			13,406
Amendments		0			0			0			0			838			0
Expected return on plan assets		(3,515	)		(3,433	)		(7,048	)		(6,933	)		(13,982	)		(14,652	)
Amortization of:
Net loss		1,689			874			3,272			1,774			5,047			2,587
Prior service cost		31			33			58			58			115			115

Net periodic benefit cost	$	3,386		$	2,396		$	6,701		$	4,746		$	12,283		$	7,255

During the six months ended June 30, 2011, the Company contributed $12.9 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, six and twelve months ended June 30, 2011 and 2010 is made up of the components listed below (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,						Twelve Months Ended June 30,
	2011			2010			2011			2010			2011			2010
Components of net periodic benefit cost:
Service cost	$	756		$	854		$	1,494		$	1,779		$	3,273		$	3,476
Interest cost		1,399			1,607			2,689			3,332			6,021			6,578
Expected return on plan assets		(454	)		(390	)		(912	)		(765	)		(1,676	)		(1,514	)
Amortization of:
Prior service benefit		(1,481	)		(710	)		(2,963	)		(1,435	)		(4,397	)		(2,869	)
Net (gain) loss		89			(87	)		(19	)		(87	)		(107	)		(87	)

Net periodic benefit cost	$	309		$	1,274		$	289		$	2,824		$	3,114		$	5,584

During the six months ended June 30, 2011, the Company contributed $2.2 million to fund its entire annual contribution to its postretirement plan for 2011.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

K. 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, short-term borrowings under the revolving credit facility (the “RCF”), 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 Short-Term Borrowings Under the RCF. The fair values of the Company’s long-term debt and short-term borrowings under the RCF are based on estimated market prices for similar issues and are presented below (in thousands):


	June 30, 2011				December 31, 2010
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Pollution Control Bonds	$	193,135	$	197,570	$	193,135	$	192,924
Senior Notes		546,636		591,490		546,610		574,700
RGRT Senior Notes (1)		110,000		113,239		110,000		110,371
RCF (1)		39,642		39,642		4,704		4,704

Total	$	889,413	$	941,941	$	854,449	$	882,699

(1)

Nuclear fuel financing as of June 30, 2011 is funded through the $110 million RGRT Senior Notes and $13.6 million under the RCF. The Company also had $26.0 million outstanding under the RCF for working capital or general and corporate purposes. The interest rate on the Company’s borrowings under the RCF is reset throughout the quarter reflecting 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 $162.7 million and $153.9 million at June 30, 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 time that individual securities have been in a continuous unrealized loss position (in thousands):

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


	June 30, 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	$	3,283	$	(48	)	$	0	$	0		$	3,283	$	(48	)
U.S. Government Bonds		8,675		(107	)		402		(1	)		9,077		(108	)
Municipal Obligations		6,532		(92	)		4,228		(190	)		10,760		(282	)
Corporate Obligations		2,915		(68	)		93		(3	)		3,008		(71	)

Total debt securities		21,405		(315	)		4,723		(194	)		26,128		(509	)
Common stock		5,380		(1,033	)		3,471		(665	)		8,851		(1,698	)

Total temporarily impaired securities	$	26,785	$	(1,348	)	$	8,194	$	(859	)	$	34,979	$	(2,207	)

(1)	Includes approximately 82 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 recorded 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):


	June 30, 2011				December 31, 2010
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
Description of Securities:
Federal Agency Mortgage Backed Securities	$	17,625	$	915	$	18,472	$	793
U.S. Government Bonds		14,010		266		10,450		183
Municipal Obligations		20,182		898		15,633		592
Corporate Obligations		7,546		363		7,223		362

Total debt securities		59,363		2,442		51,778		1,930

Common stock		63,448		16,386		56,770		14,142
Cash and Cash Equivalents		4,912		0		3,007		0

Total	$	127,723	$	18,828	$	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 of these available-for-sale securities as of June 30, 2011 is as follows (in thousands):


	Total		2011		2012 through 2015		2016 through 2020		2021 and Beyond
Municipal Debt Obligations	$	30,942	$	1,507	$	10,107	$	12,632	$	6,696
Corporate Debt Obligations		10,554		0		4,064		3,674		2,816
U.S. Government Bonds		23,088		0		9,695		9,648		3,745

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, six and twelve months ended June 30, 2011 and 2010, the Company recognized other than temporary impairment losses on its available-for-sale securities as follows (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,						Twelve Months Ended June 30,
	2011			2010			2011			2010			2011			2010
Gross unrealized holding losses included in pre-tax income	$	(199	)	$	(263	)	$	(199	)	$	(263	)	$	(199	)	$	(705	)

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 June 30,						Six Months Ended June 30,						Twelve Months Ended June 30,
	2011			2010			2011			2010			2011			2010
Proceeds from sales of available-for-sale securities	$	22,175		$	14,701		$	36,406		$	34,205		$	63,857		$	93,328

Gross realized gains included in pre-tax income	$	432		$	129		$	696		$	526		$	1,200		$	3,851
Gross realized losses included in pre-tax income		(235	)		(244	)		(294	)		(672	)		(511	)		(502	)
Gross unrealized losses included in pre-tax income		(199	)		(263	)		(199	)		(263	)		(199	)		(705	)

Net gains (losses) in pre-tax income	$	(2	)	$	(378	)	$	203		$	(409	)	$	490		$	2,644

Net unrealized holding gains (losses) included in accumulated other comprehensive income	$	416		$	(6,401	)	$	2,589		$	(3,978	)	$	13,232		$	6,480
Net gains (losses) reclassified out of accumulated other comprehensive income		2			378			(203	)		409			(490	)		(2,644	)

Net gains (losses) in other comprehensive income	$	418		$	(6,023	)	$	2,386		$	(3,569	)	$	12,742		$	3,836

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 which is included in deferred charges and other assets on the consolidated balance sheets. 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 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 June 30, 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 June 30, 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	$	2,923	$	0	$	0	$	2,923


Available for sale:
U.S. Government Bonds	$	23,087	$	23,087	$	0	$	0
Federal Agency Mortgage Backed Securities		20,908		0		20,908		0
Municipal Bonds		30,942		0		30,942		0
Corporate Asset Backed Obligations		10,554		0		10,554		0

Subtotal Debt Securities		85,491		23,087		62,404		0

Common Stock		72,299		72,299		0		0
Cash and Cash Equivalents		4,912		4,912		0		0

Total available for sale	$	162,702	$	100,298	$	62,404	$	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, six and twelve month periods ending June 30, 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, six and twelve month periods ending June 30, 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 June 30, 2011, the related consolidated statements of operations and comprehensive operations for the three-month, six-month and twelve-month periods ended June 30, 2011 and 2010, and the related consolidated statements of cash flows for the six-month periods ended June 30, 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

August 5, 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 including, 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 recent 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 headings “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, six and twelve month periods ended June 30, 2011 and 2010. Income for the three, six and twelve month periods ended June 30, 2011 and 2010 is shown below:


	Three Months Ended				Six Months Ended				Twelve Months Ended
	June 30,				June 30,				June 30,
	2011		2010		2011		2010		2011		2010
Net income before extraordinary item (in thousands)	$	32,990	$	21,507	$	39,765	$	32,956	$	97,126	$	74,849
Basic earnings per share before extraordinary item		0.78		0.49		0.94		0.75		2.28		1.70

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			Six Months			Twelve Months
	Ended			Ended			Ended
June 30, 2010 income before extraordinary item	$	21,507		$	32,956		$	74,849
Change in (net of tax):
Increased retail non-fuel base revenues (a)		15,190			11,315			35,357
Decreased (increased) depreciation and amortization (b)		405			(636	)		(2,525	)
Increased operating and maintenance expense at coal and gas-fired generating plants (c)		(1,684	)		(744	)		(1,684	)
Decreased off-system sales margins retained (d)		(995	)		(3,795	)		(6,558	)
Increased outside services expense (e)		(746	)		(1,675	)		(2,507	)
Decreased deregulated Palo Verde Unit 3 revenues (f)		(223	)		(942	)		(1,191	)
Increased taxes other than income taxes (g)		(130	)		(1,002	)		(3,904	)
Increased customer account and service expense (h)		(16	)		(712	)		(2,062	)
Elimination of Medicare Part D tax benefit (i)		0			4,787			4,787
Other		(318	)		213			2,564

June 30, 2011 income before extraordinary item	$	32,990		$	39,765		$	97,126

(a)

Non-fuel retail base revenues increased for the three, six, and twelve months ended June 30, 2011 when compared to the same periods in 2010 as the result of increased kWh sales reflecting increased customer growth, favorable weather conditions, increased non-fuel base rates, and the seasonality of our rate structure. For a complete discussion of non-fuel rate base revenues see page 37.

(b)

Depreciation and amortization expense decreased for the three months ended June 30, 2011 compared to the same period last year due to the NRC granting extensions in the operating licenses for all three units at Palo Verde on April 21, 2011. Depreciation and amortization expense increased for the twelve months ended June 30, 2011 compared to the same period last year due to increased depreciable plant balances partially offset by the effects of the Palo Verde license extensions.

(c)

Operating and maintenance expense at coal and gas-fired generating plants increased for the three and six months ended June 30, 2011 compared to the same periods last year due to increased maintenance. Operating and maintenance expense at coal and gas-fired generating plants increased for the twelve months ended June 30, 2011 compared to the same period last year due to increased operations expense.

(d)	Off-system sales margins retained decreased in all periods due to lower average market prices for power and increased sharing of off-system sales margins with customers. The decreases were partially offset by increased MWh sales in all three periods.

(e)	Outside services expense increased in all three periods due to regulatory inquiries into the disruption in service during severe winter weather in February 2011 and additional outside services related to new software systems to improve productivity.

(f)

Revenues from retail sales of deregulated Palo Verde Unit 3 decreased for the three periods due to the increased costs of nuclear fuel. The decrease for the six and twelve months ended June 30, 2011 when compared to the same periods last year was also due to decreased generation at Palo Verde Unit 3.

(g)	Taxes other than income taxes increased for all three periods due to increased estimated property taxes. Taxes other than income taxes increased for the six and twelve months ended June 30, 2011 compared to the same periods last year due to increased revenue-related taxes in Texas.

(h)	Customer accounts and service expense increased for the six and twelve months ended June 30, 2011 compared to the same periods last year primarily due to increased uncollectible customer accounts and the transition to a new customer billing system.

(i)	Income tax expense was incurred in March 2010 to recognize a change in the 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 the 2011 periods.

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 our 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 such fuel costs.

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


	Three Months Ended						Six Months Ended						Twelve Months Ended
	June 30,						June 30,						June 30,
	2011			2010			2011			2010			2011			2010
Residential		38	%		39	%		40	%		39	%		41	%		40	%
Commercial and industrial, small		37			36			35			36			35			36
Commercial and industrial, large		8			9			8			9			8			8
Sales to public authorities		17			16			17			16			16			16

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

No retail customer accounted for more than 3% of our 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 three, six, and twelve months ended June 30, 2011, retail non-fuel base revenues were positively impacted by hotter summer weather when compared

to the same periods in 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						Six Months Ended						Twelve Months Ended
	June 30,				10-Year Average		June 30,				10-Year Average		June 30,				10-Year Average*
	2011		2010		10-Year Average		2011		2010		10-Year Average		2011		2010		10-Year Average*
Heating degree days		40		82		66		1,305		1,478		1,290		2,100		2,510		2,280
Cooling degree days		1,169		995		1,005		1,210		1,004		1,026		2,944		2,722		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% for both the three and six months ended June 30, 2011, and 1.5% for the twelve months ended June 30, 2011 when compared to the same periods last year. See the tables presented on pages 40, 41 and 42 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 increased by $24.1 million or 18.5% for the three months ended June 31, 2011 when compared to the same period last year primarily due to (i) new seasonal non-fuel base rates in Texas, and (ii) a 6.2% increase in kWh sales to retail customers reflecting hotter summer weather and 1.4% growth in the average number of customers served. During the three months ended June 30, 2011, cooling degree days were over 16% above the same period in 2010 and the 10-year average. KWh sales to residential customers and small commercial and industrial customers increased 9.3% and 5.5% in the second quarter. Sales to other public authorities increased due to increased sales to military bases at higher non-fuel base rates.

For the six months ended June 30, 2011, retail non-fuel base revenues increased by $18.0 million or 7.5% compared to the same period in 2010 primarily due to (i) new seasonal non-fuel base rates in Texas, and (ii) a 2.8% increase in kWh sales to retail customers reflecting hotter summer weather and 1.4% growth in the average number of customers served. During the six months ended June 30, 2011, cooling degree days were 21% above the same period in 2010 and 18% above the 10-year average. KWh sales to residential customers and small commercial and industrial customers increased 3.4% and 2.5% during the six months ended June 30, 2011 compared to the same period last year. The increases in kWh sales in the second quarter were offset by the decreased kWh sales we experienced in the first quarter and were generally at the higher summer rates contributing to the revenue increase. Sales to other public authorities increased due to increased sales to military bases at higher non-fuel base rates.

Retail non-fuel base revenues for the twelve months ended June 30, 2011 increased by $56.1 million or 11.3% compared to the same period in 2010 primarily due to (i) higher rates in Texas effective July 1, 2010 and in New Mexico effective January 1, 2010, and (ii) a 3.2% increase in kWh sales to retail customers reflecting hotter summer weather and 1.5% growth in the average number of customers served. During the twelve months ended June 30, 2011, cooling degree days were 8% above

the same period in 2010 and 15% above the 10-year average. KWh sales to residential customers and small commercial and industrial customers increased 4.3% and 2.0% during the twelve months ended June 30, 2011 compared to the same period last year. Sales to other public authorities increased due to increased sales to military bases at higher non-fuel base rates. KWh sales to large commercial and industrial customers increased 2.6% 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. We can seek to revise our fixed fuel factor based upon an 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 three and six months ended June 30, 2011, we under-recovered our fuel costs for all three jurisdictions by $12.7 million and $13.7 million, respectively, compared to a fuel over-recovery of $6.4 million and $12.1 million in the same periods in 2010. In January 2011, we implemented a reduced fixed fuel factor in Texas, and in April 2011, we refunded $12.0 million of fuel over-recoveries for the period October 2010 through December 2010 to our Texas customers. In February 2010, we refunded $11.8 million of fuel over-recoveries to our 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 months ended June 30, 2011, we over-recovered our fuel costs by $9.6 million compared to fuel over-recoveries of $42.1 million in the same period last year. Refunds of $35.0 million and $28.5 million were returned to our Texas customers in the twelve months ended June 30, 2011 and 2010, respectively. At June 30, 2011, we had a net fuel under-recovery balance of $6.9 million, including $6.8 million in Texas and $0.1 million from our FERC customer. At June 30, 2010, we had a net fuel over-recovery balance of $18.4 million, including a $17.9 million over-recovery in Texas, a $0.6 million over-recovery in New Mexico, and $0.1 million under-recovery from our FERC customer.

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 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 and when wildfires in June 2011 threatened key transmission lines in eastern Arizona and western New Mexico. The cost of this power was

reserved pending a request for recovery. Retained margins from off-system sales, including the reliability purchases, decreased approximately $1.6 million, $6.0 million, and $10.4 million for the three, six, and twelve months ended June 30, 2011 compared to the corresponding periods in 2010. Off-system sales margins also decreased due to the increased sharing of off-system sales margins with customers and lower average market prices for power.

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


							Increase (Decrease)
Quarter Ended June 30:	2011			2010			Amount			Percent
kWh sales:
Retail:
Residential		637,257			583,096			54,161			9.3	%
Commercial and industrial, small		634,081			601,048			33,033			5.5
Commercial and industrial, large		308,978			289,095			19,883			6.9
Sales to public authorities		413,258			403,770			9,488			2.3

Total retail sales		1,993,574			1,877,009			116,565			6.2

Wholesale:
Sales for resale		19,346			17,335			2,011			11.6
Off-system sales		668,420			511,470			156,950			30.7

Total wholesale sales		687,766			528,805			158,961			30.1

Total kWh sales		2,681,340			2,405,814			275,526			11.5

Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	58,934		$	50,153		$	8,781			17.5	%
Commercial and industrial, small		57,060			47,238			9,822			20.8
Commercial and industrial, large		12,305			11,608			697			6.0
Sales to public authorities		25,998			21,186			4,812			22.7

Total retail non-fuel base revenues		154,297			130,185			24,112			18.5

Wholesale:
Sales for resale		785			567			218			38.4

Total non-fuel base revenues		155,082			130,752			24,330			18.6

Fuel revenues:
Recovered from customers during the period		33,672			45,248			(11,576	)		(25.6	)(1)
Under (over) collection of fuel		12,700			(6,402	)		19,102			N/A
New Mexico fuel in base rates (2)		17,156			17,753			(597	)		(3.4	)

Total fuel revenues		63,528			56,599			6,929			12.2
Off-system sales:
Fuel cost		17,256			16,661			595			3.6
Shared margins		248			262			(14	)		(5.3	)
Retained margins		(793	)		787			(1,580	)		N/A

Total off-system sales		16,711			17,710			(999	)		(5.6	)
Other		7,284			6,336			948			15.0	(3)

Total operating revenues	$	242,605		$	211,397		$	31,208			14.8

Average number of retail customers:
Residential		335,808			330,976			4,832			1.5	%
Commercial and industrial, small		37,096			36,740			356			1.0
Commercial and industrial, large		50			49			1			2.0
Sales to public authorities		4,849			4,701			148			3.1

Total		377,803			372,466			5,337			1.4

(1)	Excludes $12.0 million of refunds in 2011 related to Texas deferred fuel revenues in prior periods.

(2)	Includes $3.9 million and $4.3 million, respectively, charged to New Mexico customers for power supplied to New Mexico customers from Palo Verde Unit 3 using a proxy price.

(3)	Represents revenues with no related kWh sales.


							Increase (Decrease)
Six Months Ended June 30:	2011			2010			Amount			Percent
kWh sales:
Retail:
Residential		1,178,539			1,139,376			39,163			3.4	%
Commercial and industrial, small		1,112,602			1,085,330			27,272			2.5
Commercial and industrial, large		538,210			525,708			12,502			2.4
Sales to public authorities		748,227			729,327			18,900			2.6

Total retail sales		3,577,578			3,479,741			97,837			2.8

Wholesale:
Sales for resale		30,999			26,515			4,484			16.9
Off-system sales		1,436,040			1,359,208			76,832			5.7

Total wholesale sales		1,467,039			1,385,723			81,316			5.9

Total kWh sales		5,044,617			4,865,464			179,153			3.7

Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	103,911		$	94,988		$	8,923			9.4	%
Commercial and industrial, small		90,274			86,437			3,837			4.4
Commercial and industrial, large		21,106			20,821			285			1.4
Sales to public authorities		43,018			38,102			4,916			12.9

Total retail non-fuel base revenues		258,309			240,348			17,961			7.5

Wholesale:
Sales for resale		1,335			874			461			52.7

Total non-fuel base revenues		259,644			241,222			18,422			7.6

Fuel revenues:
Recovered from customers during the period		59,535			83,281			(23,746	)		(28.5	)(1)
Under (over) collection of fuel		13,738			(12,092	)		25,830			N/A
New Mexico fuel in base rates (2)		33,525			33,582			(57	)		(0.2	)

Total fuel revenues		106,798			104,771			2,027			1.9
Off-system sales:
Fuel cost		37,519			49,523			(12,004	)		(24.2	)
Shared margins		1,412			1,721			(309	)		(18.0	)
Retained margins		(854	)		5,169			(6,023	)		N/A

Total off-system sales		38,077			56,413			(18,336	)		(32.5	)
Other		14,198			13,159			1,039			7.9	(3)

Total operating revenues	$	418,717		$	415,565		$	3,152			0.8

Average number of retail customers:
Residential		335,320			330,356			4,964			1.5	%
Commercial and industrial, small		37,081			36,644			437			1.2
Commercial and industrial, large		50			48			2			4.2
Sales to public authorities		4,693			4,833			(140	)		(2.9	)

Total		377,144			371,881			5,263			1.4

(1)	Excludes $12.0 million and $11.8 million of refunds in 2011 and 2010, respectively, related to Texas deferred fuel revenues in prior periods.

(2)	Includes $7.9 million and $9.3 million, respectively, charged to New Mexico customers for power supplied to New Mexico customers from Palo Verde Unit 3 using a proxy price.

(3)	Represents revenues with no related kWh sales.


							Increase (Decrease)
Twelve Months Ended June 30:	2011			2010			Amount			Percent
kWh sales:
Retail:
Residential		2,547,997			2,442,393			105,604			4.3	%
Commercial and industrial, small		2,322,809			2,277,764			45,045			2.0
Commercial and industrial, large		1,099,915			1,071,719			28,196			2.6
Sales to public authorities		1,561,289			1,504,398			56,891			3.8

Total retail sales		7,532,010			7,296,274			235,736			3.2

Wholesale:
Sales for resale		58,121			54,488			3,633			6.7
Off-system sales		2,899,564			2,662,711			236,853			8.9

Total wholesale sales		2,957,685			2,717,199			240,486			8.9

Total kWh sales		10,489,695			10,013,473			476,222			4.8

Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	226,538		$	202,522		$	24,016			11.9	%
Commercial and industrial, small		192,227			178,213			14,014			7.9
Commercial and industrial, large		44,129			39,057			5,072			13.0
Sales to public authorities		91,376			78,354			13,022			16.6

Total retail non-fuel base revenues		554,270			498,146			56,124			11.3

Wholesale:
Sales for resale		2,404			2,029			375			18.5

Total non-fuel base revenues		556,674			500,175			56,499			11.3

Fuel revenues:
Recovered from customers during the period		146,842			181,454			(34,612	)		(19.1	)(1)
Under (over) collection of fuel		(9,578	)		(42,059	)		32,481			N/A
New Mexico fuel in base rates (2)		71,819			70,804			1,015			1.4

Total fuel revenues		209,083			210,199			(1,116	)		(0.5	)
Off-system sales:
Fuel cost		81,512			97,971			(16,459	)		(16.8	)
Shared margins		5,805			3,352			2,453			73.2
Retained margins		(336	)		10,073			(10,409	)		N/A

Total off-system sales		86,981			111,396			(24,415	)		(21.9	)
Other		27,665			27,706			(41	)		(0.1	)(3)

Total operating revenues	$	880,403		$	849,476		$	30,927			3.6

Average number of retail customers:
Residential		334,350			328,908			5,442			1.7	%
Commercial and industrial, small		36,754			36,442			312			0.9
Commercial and industrial, large		49			48			1			2.1
Sales to public authorities		4,631			4,890			(259	)		(5.3	)

Total		375,784			370,288			5,496			1.5

(1)	Excludes $35.0 million and $28.5 million of refunds in 2011 and 2010, respectively, related to Texas deferred fuel revenues in prior periods.

(2)	Includes $14.6 million and $16.5 million, respectively, charged to New Mexico customers for power supplied to New Mexico customers from Palo Verde Unit 3 using a proxy price.

(3)	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 54%, 58% and 58% of our Company-generated energy for the three, six and twelve months ended June 30, 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 increased $7.3 million or 10.4% for the three months ended June 30, 2011 when compared to 2010 primarily due to (i) increased natural gas costs of $9.1 million as a result of an 8.5% increase in the average cost of natural gas, a 5.4% increase in MWhs generated with natural gas, and a $3.5 million adjustment related to Newman Unit 5 pre-commercial testing, and (ii) increased nuclear fuel costs of $1.8 million as result of a 12% increase in the price of nuclear fuel and an 8% increase in MWhs generated with nuclear fuel. This increase was partially offset by decreased purchased power of $3.3 million due to a 9% decrease in both the market prices for power and the MWhs purchased. The table below details the sources and costs of energy for the three months ended June 30, 2011 and 2010.


	Three Months Ended June 30,
	2011						2010
Fuel Type	Cost		MWh		Cost per MWh		Cost		MWh		Cost per MWh
	(in thousands)						(in thousands)
Natural gas	$	47,839		856,448	$	54.88	$	38,781		766,575	$	50.59
Coal		3,053		145,008		21.05		3,335		167,625		19.90
Nuclear		10,426		1,182,054		8.82		8,636		1,091,969		7.91

Total		61,318		2,183,510		28.08		50,752		2,026,169		25.05
Purchased power		16,297		499,040		32.66		19,552		545,720		35.83

Total energy	$	77,615		2,682,550		28.93	$	70,304		2,571,889		27.34

Our energy expenses decreased $9.4 million or 6.3% for the six months ended June 30, 2011 when compared to 2010 primarily due to (i) decreased purchased power costs of $13.6 million as a result of a 22% decrease in the market prices for power and an 8% decrease in the MWhs purchased, and (ii) decreased natural gas costs of $2.5 million as a result of capitalizing $3.2 million of natural gas costs related to 193,460 MWhs for Newman Unit 5 pre-commercial testing. These decreases were partially offset by (i) increased nuclear fuel costs of $4.1 million due to a 17% increase in the average cost of nuclear fuel and a 6% increase in the MWhs generated with nuclear fuel, and (ii) increased coal costs of $2.6 million due to a $2.3 million adjustment for the amortization of final coal reclamation costs in accordance with the final order in PUCT Docket No. 38361. The table below details the sources and costs of energy for the six months ended June 30, 2011 and 2010.


	Six Months Ended June 30,
	2011						2010
Fuel Type	Cost		MWh		Cost per MWh		Cost		MWh		Cost per MWh
	(in thousands)						(in thousands)
Natural gas	$	74,182		1,473,782	$	55.22	$	76,698		1,319,377	$	58.13
Coal		8,416		311,979		26.98		5,769		288,034		20.03
Nuclear		21,479		2,511,861		8.55		17,378		2,372,281		7.33

Total		104,077		4,297,622		24.22		99,845		3,979,692		25.09
Purchased power		34,771		1,060,968		32.77		48,399		1,155,743		41.88

Total energy	$	138,848		5,358,590		25.91	$	148,244		5,135,435		28.87

Our energy expenses decreased $16.5 million or 5.5% for the twelve months ended June 30, 2011 when compared to 2010 primarily due to (i) decreased purchased power costs of $21.0 million as a result of a 5% decrease in the MWhs purchased and a 17% decrease in the market prices for power, and (ii) decreased natural gas costs of $4.6 million as a result of capitalizing $3.2 million of natural gas costs related to 197,606 MWhs for Newman Unit 5 pre-commercial testing. These decreases were partially offset by (i) increased nuclear fuel costs of $7.2 million due to a 15% increase in the average cost of nuclear fuel and a 6% increase in the MWhs generated with nuclear fuel, and (ii) increased coal costs of $1.9 million due to a $2.0 million adjustment for the amortization of final coal reclamation costs in accordance with the final order in PUCT Docket No. 38361. The table below details the sources and costs of energy for the twelve months ended June 30, 2011 and 2010.


	Twelve Months Ended June 30,
	2011						2010
Fuel Type	Cost		MWh		Cost per MWh		Cost		MWh		Cost per MWh
	(in thousands)						(in thousands)
Natural gas	$	151,052		3,044,515	$	51.83	$	155,650		2,691,538	$	57.83
Coal		13,658		674,181		20.26		11,728		646,936		18.13
Nuclear		39,351		5,064,893		7.77		32,128		4,774,928		6.73

Total		204,061		8,783,589		23.23		199,506		8,113,402		24.59
Purchased power		78,288		2,326,094		33.66		99,309		2,459,230		40.38

Total energy	$	282,349		11,109,683		25.41	$	298,815		10,572,632		28.26

Other operations expense

Other operations expense increased $5.7 million, or 11.0%, for the three months ended June 30, 2011 compared to the same period last year primarily due to (i) increased administrative and general expense of $2.3 million relating to increased outside services and increased regulatory expense for amortization of rate case expenses, (ii) an increase of $1.4 million in transmission and distribution expense relating to increased costs associated with NERC compliance and increased wheeling expense, and (iii) an increase in Palo Verde operations expense of $0.9 million.

Other operations expense increased $9.7 million, or 9.5%, for the six months ended June 30, 2011 compared to the same period last year primarily due to (i) increased administrative and general expense of $3.9 million relating to increased outside services and increased regulatory expense for amortization of rate case expenses, (ii) an increase in Palo Verde operations expense of $2.1 million, and (iii) an increase of $1.6 million in transmission and distribution expense relating to increased costs associated with NERC compliance and increased wheeling expense.

Other operations expense increased $16.4 million, or 7.5%, for the twelve months ended June 30, 2011 compared to the same period last year primarily due to (i) increased administrative and general expense of $10.0 million resulting from increased outside services, increased regulatory expense for amortization of rate case expenses, and increased pension and benefits expense reflecting changes in actuarial assumptions used to calculate expense for our pension plans, (ii) increased customer accounts and service expense of $3.3 million primarily related to increased uncollectible customer accounts and costs incurred during the transition to a new customer billing system, (iii) increased Palo Verde operations expense of $1.2 million, and (iv) an increase of $2.0 million in operations expense at our coal and gas-fired plants.

Maintenance expense

Maintenance expense increased $1.0 million, or 6.5%, for the three months ended June 30, 2011 compared to the same period last year primarily due to increased maintenance expense at our coal and gas-fired generating plants largely as a result of weather-related damage during severe winter weather in February 2011. Maintenance expense decreased $1.2 million and $4.5 million, or 4.1% and 7.5%, for the six and twelve months ended June 30, 2011 compared to the same periods last year primarily due to decreased Palo Verde maintenance expenses.

Depreciation and amortization expense

Depreciation and amortization expense decreased $0.6 million or 3.2% for the three months ended June 30, 2011 compared to the same periods last year primarily due to a reduction in depreciation rates related to the Palo Verde plant resulting from the approval of a license extension for Palo Verde by the NRC in April 2011, partially offset by increases in depreciable plant balances and higher non-nuclear depreciation rates. Depreciation and amortization expense increased $1.0 million and $4.0 million, or 2.6% and 5.1%, for the six and twelve months ended June 30, 2011 compared to the same periods last year primarily due to increases in depreciable plant balances and higher non-nuclear depreciation rates, partially offset by the reduction in depreciation rates stemming from the NRC license extension for Palo Verde.

Taxes other than income taxes

Taxes other than income taxes for the three months ended June 30, 2011, were comparable to the same period last year. Taxes other than income taxes increased $1.6 million, or 6.4%, for the six months ended June 30, 2011, compared to the same period last year due to increased property taxes resulting from an increase in taxable property and estimated property tax rates and higher revenue-related taxes in Texas resulting from the increase in billed revenues, and an increase in the franchise tax rate for the City of El Paso in August 2010, which were partially offset by a decrease in payroll taxes. Taxes other than income taxes increased $6.2 million, or 12.4%, for the twelve months ended June 30, 2011 compared to the same period last year due to (i) higher revenue-related taxes in Texas resulting from the increase in billed revenues and an increase in the franchise tax rate for the City of El Paso in August 2010, and (ii) increased property taxes resulting from an increase in taxable property and estimated property tax rates.

Other income (deductions)

Other income (deductions) decreased $0.3 million for the three months ended June 30, 2011 compared to the same period last year due to decreased allowance for equity funds used during construction (“AEFUDC”) as a result of lower balances of construction work in progress partially offset by increased investment and interest income. Other income (deductions) increased $1.4 million for the six months ended June 30, 2011 compared to the same period last year due to reduced realized losses in our Palo Verde decommissioning trust fund and increased investment and interest income. Other income (deductions) increased $0.8 million for the twelve months ended June 30, 2011 compared to the same period last year due to increased AEFUDC as a result of higher balances of construction work in progress.

Interest charges (credits)

Interest charges (credits) increased $0.8 million, or 7.8% for the three months ended June 30, 2011 compared to the same period last year primarily due to decreased allowance for borrowed funds used during construction as a result of lower balances of construction work in progress and increased commitment fees on our new revolving credit facility entered into in September 2010. Interest charges (credits) increased $1.1 million and $0.6 million for the six and twelve months ended June 30, 2011 compared to the same periods last year primarily due to increased commitment fees on our new revolving credit facility entered into in September 2010 and an increase in amortization of loss on reacquired debt as allowed in the PUCT Docket No. 37690 which became effective July 1, 2010. See extraordinary item discussion below.

Income tax expense

Income tax expense increased $5.1 million, or 43.5% in the three months ended June 30, 2011 compared to the same period last year, primarily due to increased pre-tax income. Income tax expense decreased by $4.9 million, or 20.8% in the six months ended June 30, 2011 compared to the same period last year. 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, increased tax expense reflects increased pre-tax income offset by non-taxable AEFUDC. Income tax expense, before extraordinary item, increased by $3.2 million, or 7.6% in the twelve months ended June 30, 2011 compared to 2010 primarily due to increased pre-tax income, partially offset by the PPACA adjustment discussed above.

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

approach; however, this new guidance will require additional disclosure on our statement of operations and related notes. The new guidance is required to be applied retrospectively and is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011.

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, six and twelve months ended June 30, 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 minimal 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 June 30, 2011, our capital structure, including common stock, long-term debt, and short-term borrowings under the revolving credit facility, consisted of 47.9% common stock equity and 52.1% debt. At June 30, 2011, we had on hand $5.1 million in cash and cash equivalents.

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, operating expenses including fuel costs, maintenance costs, dividends and taxes.

Capital Requirements. During the six months ended June 30, 2011, our capital requirements primarily consisted of expenditures for the construction and purchase of electric utility plant, purchases of nuclear fuel, the repurchase of common stock, and common stock dividends. 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. The first phase of Newman Unit 5 was completed in May 2009, and the second phase was completed in April 2011. As of June 30, 2011, we had expended $234.3 million, including AFUDC, on Newman Unit 5, including $24.5 million during 2011. Estimated construction expenditures for all capital projects for 2011 are estimated at approximately $195 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. Cash capital expenditures for new electric plant were $87.0 million in the six months ended June 30, 2011 compared to $90.6 million in the six months ended June 30, 2010.

On July 28, 2011, our Board of Directors declared a quarterly dividend of $0.22 per share, payable on September 30, 2011 to shareholders of record on September 15, 2011. On June 30, 2011, we paid $9.3 million of dividends to shareholders. We expect to pay cash dividends totaling approximately $27 million during 2011. In addition, we may repurchase common stock in the future. Since 1999, we have returned cash to stockholders through a stock repurchase program pursuant to which we have bought approximately 23.5 million shares of common stock at an aggregate cost of $363.5 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. 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”). During the first six months of 2011, we repurchased 910,749 shares of common stock in the open market at an aggregate cost of $26.3 million including 323,838 shares repurchased in the second quarter at an aggregate cost of $9.6 million. As of June 30, 2011, 2,265,522 shares remain available for repurchase under our 2011 Plan. We expect to continue to repurchase shares in the open market from time to time.

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 $12.9 million of the projected $13.9 million 2011 annual contribution to our retirement plans during the six months ended June 30, 2011. In the six months ended June 30, 2011, we contributed $2.2 million to fund our OPEB plan for the entire year of 2011, and $4.3 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 six months ended June 30, 2011, we had decreased cash from operations when compared to the same period in 2010 due primarily to the timing of collection of fuel revenues to recover actual fuel expense. During the six months ended June 30, 2011, we had an under-recovery of fuel costs, net of refunds, of $25.8 million as compared to an over-recovery, net of refunds, of $0.4 million during the six months ended June 30, 2010. At June 30, 2011, we had a net fuel under-recovery balance of $6.9 million, including $6.8 million in Texas and $0.1 million for our FERC customer.

Cash from operations has 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.

We maintain a $200 million revolving credit facility for the 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 our financial statements. The revolving credit facility has a term ending in September 2014, and we 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 June 30, 2011 was $123.6 million of which $13.6 million was borrowed under the revolving credit facility and $110 million was borrowed through senior notes. Amounts borrowed under the revolving credit facility for nuclear fuel was $122.8 million as of June 30, 2010, including accrued interest and fees. Interest costs on borrowings to finance nuclear fuel are accumulated by RGRT and charged to us as fuel is consumed and recovered from customers through fuel recovery charges. We had $26.0 million outstanding under the revolving credit facility at June 30, 2011 for working capital and general corporate purposes.

We expect to have sufficient liquidity to finance construction expenditures and other capital requirements for the next twelve months through cash balances, cash from operations and our revolving credit facility. In addition, we may seek to issue long-term debt in the capital markets to refinance short-term borrowings and fund 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 June 30, 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 and Exchange Act of 1934. Based on that evaluation, our chief executive officer and our chief financial officer concluded that, as of June 30, 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 June 30, 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 C and H 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
April 1 to April 30, 2011		0	$	0.00		0		2,589,360
May 1 to May 31, 2011		31,248		29.98		31,248		2,558,112
June 1 to June 30, 2011		292,590		29.76		292,590		2,265,522

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: August 5, 2011

EL PASO ELECTRIC COMPANY

INDEX TO EXHIBITS


Exhibit Number		Exhibit

	†10.03	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)

	10.04	Letter Agreement, dated as of April 29, 2011, to the Power Purchase and Sale Agreement referred to in Exhibit 10.42 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.DEF	XBRL Taxonomy Extension Definition 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, three agreements, dated as of July 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.

In lieu of non-employee director cash compensation, eleven agreements, dated as of May 26, 2011, substantially identical in all material respects to this Exhibit, were entered into with Catherine A. Allen; J. Robert Brown; James W. Cicconi; James W. Harris; Kenneth R. Heitz; Patricia Z. Holland-Branch; Michael K. Parks; Thomas V. Shockley, III; Eric B. Siegel; Stephen N. Wertheimer; and Charles A. Yamarone; directors of the Company.