Edgar Filing: EL PASO ELECTRIC CO /TX/

Since 1999
(a)

Authorized
Shares

Shares repurchased (b)

Cost, including commission (in thousands)

Total remaining shares available for repurchase at June 30, 2012

EE 2012.6.30 10Q

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, 2012



o	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 o

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 o

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.



Large accelerated filer	x	Accelerated filer	o

Non-accelerated filer	o	Smaller reporting company	o

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

As of July 31, 2012, there were 40,114,838 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, 2012 and December 31, 2011		1
Consolidated Statements of Operations – Three Months, Six Months and Twelve Months Ended June 30, 2012 and 2011		3
Consolidated Statements of Comprehensive Operations – Three Months, Six Months and Twelve Months Ended June 30, 2012 and 2011		5
Consolidated Statements of Cash Flows – Six Months Ended June 30, 2012 and 2011		6
Notes to Consolidated Financial Statements		7
Report of Independent Registered Public Accounting Firm		26
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40
Item 4.	Controls and Procedures	40
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	42
Item 1A.	Risk Factors	42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 6.	Exhibits	42

Table of Contents

PART I. FINANCIAL INFORMATION


Item 1.	Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS



	June 30, 2012			December 31, 2011
	(Unaudited)

ASSETS (In thousands)
Utility plant:
Electric plant in service	$	2,797,764		$	2,789,773
Less accumulated depreciation and amortization	(1,127,455		)	(1,121,653		)
Net plant in service	1,670,309			1,668,120
Construction work in progress	225,280			167,394
Nuclear fuel; includes fuel in process of $47,354 and $49,545, respectively	201,785			171,433
Less accumulated amortization	(71,378		)	(59,882		)
Net nuclear fuel	130,407			111,551
Net utility plant	2,025,996			1,947,065
Current assets:
Cash and cash equivalents	10,084			8,208
Accounts receivable, principally trade, net of allowance for doubtful accounts of $2,887 and $3,015, respectively	95,545			76,348
Accumulated deferred income taxes	19,076			13,752
Inventories, at cost	41,692			40,222
Income taxes receivable	2,214			2,269
Undercollection of fuel revenues	—			9,130
Prepayments and other	9,014			4,810
Total current assets	177,625			154,739
Deferred charges and other assets:
Decommissioning trust funds	178,279			167,963
Regulatory assets	101,554			101,027
Other	28,000			26,057
Total deferred charges and other assets	307,833			295,047
Total assets	$	2,511,454		$	2,396,851

See accompanying notes to consolidated financial statements.



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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS (Continued)



	June 30, 2012			December 31, 2011
	(Unaudited)
CAPITALIZATION AND LIABILITIES (In thousands except for share data)
Capitalization:
Common stock, stated value $1 per share, 100,000,000 shares authorized, 65,493,993 and 65,295,888 shares issued, and 112,165 and 156,185 restricted shares, respectively	$	65,606		$	65,452
Capital in excess of stated value	308,360			309,777
Retained earnings	902,578			887,174
Accumulated other comprehensive income (loss), net of tax	(69,707		)	(77,505		)
	1,206,837			1,184,898
Treasury stock, 25,492,919 shares at cost	(424,647		)	(424,647		)
Common stock equity	782,190			760,251
Long-term debt	816,524			816,497
Total capitalization	1,598,714			1,576,748
Current liabilities:
Current maturities of long-term debt	33,300			33,300
Short-term borrowings under the revolving credit facility	110,760			33,379
Accounts payable, principally trade	41,173			51,704
Taxes accrued	23,984			30,700
Interest accrued	12,127			12,123
Overcollection of fuel revenues	8,569			2,105
Other	22,696			21,921
Total current liabilities	252,609			185,232
Deferred credits and other liabilities:
Accumulated deferred income taxes	329,468			299,475
Accrued pension liability	122,097			129,627
Accrued postretirement benefit liability	104,007			100,455
Asset retirement obligation	58,290			56,140
Regulatory liabilities	21,290			21,049
Other	24,979			28,125
Total deferred credits and other liabilities	660,131			634,871
Commitments and contingencies
Total capitalization and liabilities	$	2,511,454		$	2,396,851

See accompanying notes to consolidated financial statements.



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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands except for share data)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
Operating revenues	$	228,252		$	242,605		$	396,830		$	418,717
Energy expenses:
Fuel	49,366			61,318			88,800			104,077
Purchased and interchanged power	14,522			16,297			27,081			34,771
	63,888			77,615			115,881			138,848
Operating revenues net of energy expenses	164,364			164,990			280,949			279,869
Other operating expenses:
Other operations	58,805			57,209			113,222			111,316
Maintenance	14,806			16,760			30,774			28,996
Depreciation and amortization	19,603			19,524			40,121			40,460
Taxes other than income taxes	14,638			13,376			28,278			26,503
	107,852			106,869			212,395			207,275
Operating income	56,512			58,121			68,554			72,594
Other income (deductions):
Allowance for equity funds used during construction	2,214			2,011			4,170			5,062
Investment and interest income, net	102			1,590			1,878			3,975
Miscellaneous non-operating income	131			1			201			271
Miscellaneous non-operating deductions	(421		)	(698		)	(903		)	(1,413		)
	2,026			2,904			5,346			7,895
Interest charges (credits):
Interest on long-term debt and revolving credit facility	13,605			13,526			27,168			27,024
Other interest	278			237			478			534
Capitalized interest	(1,299		)	(1,290		)	(2,668		)	(2,546		)
Allowance for borrowed funds used during construction	(1,310		)	(1,180		)	(2,463		)	(3,029		)
	11,274			11,293			22,515			21,983
Income before income taxes	47,264			49,732			51,385			58,506
Income tax expense	16,370			16,742			17,147			18,741
Net income	$	30,894		$	32,990		$	34,238		$	39,765

Basic earnings per share	$	0.77		$	0.78		$	0.85		$	0.94

Diluted earnings per share	$	0.77		$	0.78		$	0.85		$	0.94

Dividends declared per share of common stock	$	0.25		$	0.22		$	0.47		$	0.22
Weighted average number of shares outstanding	39,958,149			41,853,552			39,934,590			42,079,568
Weighted average number of shares and dilutive potential shares outstanding	40,040,776			42,076,659			40,020,143			42,298,716

See accompanying notes to consolidated financial statements.



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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands except for share data)



	Twelve Months Ended
	June 30,
	2012			2011
Operating revenues	$	896,126		$	880,403
Energy expenses:
Fuel	208,230			204,061
Purchased and interchanged power	67,459			78,288
	275,689			282,349
Operating revenues net of energy expenses	620,437			598,054
Other operating expenses:
Other operations	231,476			233,895
Maintenance	63,870			55,584
Depreciation and amortization	80,992			82,020
Taxes other than income taxes	57,336			56,079
	433,674			427,578
Operating income	186,763			170,476
Other income (deductions):
Allowance for equity funds used during construction	7,269			10,631
Investment and interest income, net	3,567			7,352
Miscellaneous non-operating income	815			1,486
Miscellaneous non-operating deductions	(2,677		)	(3,731		)
	8,974			15,738
Interest charges (credits):
Interest on long-term debt and revolving credit facility	54,259			53,408
Other interest	933			723
Capitalized interest	(5,299		)	(4,547		)
Allowance for borrowed funds used during construction	(4,282		)	(6,599		)
	45,611			42,985
Income before income taxes and extraordinary item	150,126			143,229
Income tax expense	52,114			46,103
Income before extraordinary item	98,012			97,126
Extraordinary gain related to Texas regulatory assets, net of tax	—			10,286
Net income	$	98,012		$	107,412

Basic earnings per share:
Income before extraordinary item	$	2.42		$	2.28
Extraordinary gain related to Texas regulatory assets, net of tax	—			0.24
Net income	$	2.42		$	2.52

Diluted earnings per share:
Income before extraordinary item	$	2.41		$	2.27
Extraordinary gain related to Texas regulatory assets, net of tax	—			0.24
Net income	$	2.41		$	2.51

Dividends declared per share of common stock	$	0.91		$	0.22
Weighted average number of shares outstanding	40,285,248			42,376,298
Weighted average number of shares and dilutive potential shares outstanding	40,455,626			42,595,011

See accompanying notes to consolidated financial statements.



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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS

(Unaudited)

(In thousands)



	Three Months Ended						Six Months Ended						Twelve Months Ended
	June 30,						June 30,						June 30,
	2012			2011			2012			2011			2012			2011
Net income	$	30,894		$	32,990		$	34,238		$	39,765		$	98,012		$	107,412
Other comprehensive income (loss):
Unrecognized pension and postretirement benefit costs:
Net loss arising during period	—			—			—			—			(77,678		)	(9,874		)
Prior service benefit	—			—			—			—			—			26,605
Reclassification adjustments included in net income for amortization of:
Prior service benefit	(1,437		)	(1,450		)	(2,880		)	(2,905		)	(5,787		)	(4,282		)
Net loss	2,860			1,778			5,985			3,253			9,237			4,940
Net unrealized gains (losses) on marketable securities:
Net holding gains (losses) arising during period	(2,341		)	416			5,817			2,589			4,798			13,232
Reclassification adjustments for net (gains) losses included in net income	1,447			2			1,234			(203		)	2,795			(490		)
Net losses on cash flow hedges:
Reclassification adjustment for interest expense included in net income	95			88			189			176			374			348
Total other comprehensive income (loss) before income taxes	624			834			10,345			2,910			(66,261		)	30,479
Income tax benefit (expense) related to items of other comprehensive income (loss):
Unrecognized pension and postretirement benefit costs	(541		)	(124		)	(1,096		)	(131		)	29,169			(6,306		)
Net unrealized gains (losses) on marketable securities	189			(157		)	(1,370		)	(517		)	(1,416		)	(2,588		)
Losses on cash flow hedges	(36		)	(33		)	(81		)	(66		)	(218		)	(128		)
Total income tax benefit (expense)	(388		)	(314		)	(2,547		)	(714		)	27,535			(9,022		)
Other comprehensive income (loss), net of tax	236			520			7,798			2,196			(38,726		)	21,457
Comprehensive income	$	31,130		$	33,510		$	42,036		$	41,961		$	59,286		$	128,869

See accompanying notes to consolidated financial statements.



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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)



	Six Months Ended
	June 30,
	2012			2011
Cash flows from operating activities:
Net income	$	34,238		$	39,765
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service	40,121			40,460
Amortization of nuclear fuel	21,807			17,958
Deferred income taxes, net	18,630			12,647
Allowance for equity funds used during construction	(4,170		)	(5,062		)
Other amortization and accretion	6,804			11,772
Other operating activities	937			(216		)
Change in:
Accounts receivable	(19,197		)	(35,772		)
Inventories	(1,087		)	(2,741		)
Net overcollection (undercollection) of fuel revenues	15,594			(25,827		)
Prepayments and other	(5,456		)	(5,713		)
Accounts payable	(4,748		)	4,934
Taxes accrued	(6,661		)	6,326
Interest accrued	4			9
Other current liabilities	775			(1,412		)
Deferred charges and credits	(5,695		)	(7,547		)
Net cash provided by operating activities	91,896			49,581
Cash flows from investing activities:
Cash additions to utility property, plant and equipment	(99,929		)	(86,950		)
Cash additions to nuclear fuel	(38,155		)	(24,140		)
Capitalized interest and AFUDC:
Utility property, plant and equipment	(6,633		)	(8,091		)
Nuclear fuel	(2,668		)	(2,546		)
Allowance for equity funds used during construction	4,170			5,062
Decommissioning trust funds:
Purchases, including funding of $2.3 and $4.3 million, respectively	(64,011		)	(42,641		)
Sales and maturities	59,513			36,406
Other investing activities	978			188
Net cash used for investing activities	(146,735		)	(122,712		)
Cash flows from financing activities:
Repurchases of common stock	—			(26,320		)
Dividends paid	(18,834		)	(9,248		)
Borrowings under the revolving credit facility:
Proceeds	121,964			65,770
Payments	(44,583		)	(30,832		)
Other financing activities	(1,832		)	(317		)
Net cash provided by (used for) financing activities	56,715			(947		)
Net increase (decrease) in cash and cash equivalents	1,876			(74,078		)
Cash and cash equivalents at beginning of period	8,208			79,184
Cash and cash equivalents at end of period	$	10,084		$	5,106

See accompanying notes to consolidated financial statements.



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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, 2011 (the “2011 Form 10-K”). Capitalized terms used in this report and not defined herein have the meaning ascribed for such terms in the 2011 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, 2012 and December 31, 2011; the results of its operations and comprehensive operations for the three, six and twelve months ended June 30, 2012 and 2011; and its cash flows for the six months ended June 30, 2012 and 2011. The results of operations and comprehensive operations for the three and six months ended June 30, 2012 and the cash flows for the six months ended June 30, 2012 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.

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

Revenues. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated based on monthly generation volumes and by applying an average revenue/kWh to the number of estimated kWhs delivered but not billed. Accounts receivable included accrued unbilled revenues of $29.1 million and $19.6 million at June 30, 2012 and December 31, 2011, respectively. The Company presents revenues net of sales taxes in its consolidated statements of operations.

Extraordinary Item. As a regulated electric utility, the Company prepares its financial statements in accordance with the FASB guidance for regulated operations. FASB guidance for regulated operations requires the Company to show certain items as assets or liabilities on its balance sheet when the regulator provides assurance that these items will be charged to and collected from its customers or refunded to its customers. In the final order for PUCT Docket No. 37690, the Company was allowed to include the previously expensed loss on reacquired debt associated with the refinancing of first mortgage bonds in 2005 in its calculation of the weighted cost of debt to be recovered from its customers. The Company recorded the impacts of the re-application of FASB guidance for regulated operations to its Texas jurisdiction in 2006 as an extraordinary item. In order to establish this regulatory asset, the Company recorded an extraordinary gain of $10.3 million, net of income tax expense of $5.8 million, pursuant to the final order received from the PUCT, in its statements of operations for the quarter ended September 30, 2010. The regulatory asset 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,
	2012		2011
Cash paid for:
Interest on long-term debt and borrowing under the revolving credit facility	$	25,106	$	24,256
Income taxes paid (refund), net	3,159		(3,101		)
Non-cash financing activities:
Grants of restricted shares of common stock	2,331		3,193
Issuance of performance shares	1,193		565
Acquisition of treasury stock for options exercised	—		500



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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 required 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 would have been 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 used the consecutive two-statement approach; however, this new guidance would have required additional disclosure on the Company's statement of operations and related notes. In December 2011, the FASB issued new guidance to defer the effective date for amendments to the presentation of reclassification of items out of accumulated other comprehensive income. Deferring the effective date will allow the FASB time to redeliberate whether to present on the face of the financial statements the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income for all periods presented. While the FASB is considering the operational concerns about the presentation requirements for reclassification adjustments and the needs of financial statement users for additional information about reclassification adjustments, the Company will continue to report reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect before the guidance issued in June 2011 until further guidance becomes available.

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 (sales for resale) transactions, transmission service and compliance with federally-mandated reliability standards. The decisions of the PUCT, NMPRC and the FERC are subject to judicial review.

Texas Regulatory Matters

2012 Texas Retail Rate Case. The Company filed a rate increase request with the PUCT, Docket No. 40094, the City of El Paso, and other Texas cities on February 1, 2012. The rate filing was made in response to a resolution adopted by the El Paso City Council (the "Council") requiring the Company to show cause why its base rates for customers in the El Paso city limits should not be reduced. The rate filing used a historical test year ended September 30, 2011. The filing at the PUCT also included a request to reconcile $356.5 million of fuel expense for the period July 1, 2009 through September 30, 2011. On November 15, 2011, the Council adopted a resolution which established current rates as temporary rates for the Company's customers residing within the city limits of El Paso.

On April 17, 2012, the Council approved the settlement of the Company's 2012 Texas retail rate case and fuel reconciliation in PUCT Docket No. 40094. The settlement reflects discussions with the PUCT, the City of El Paso and other intervenors in Docket No. 40094. The approval by the Council (i) resolves the local City of El Paso rate proceeding that commenced with the October 4, 2011 show cause order of the Council, (ii) implements new rates within the city limits of El Paso commencing with bills rendered on and after May 1, 2012, and (iii) rescinds and withdraws the temporary rate order that the Council issued on November 15, 2011.

For Texas service areas outside of the city limits of El Paso, the settlement was filed with the PUCT on April 19, 2012, and no intervenors opposed the settlement. On April 26, 2012, the administrative law judges issued an order (i) implementing the settlement rates as temporary rates effective May 1, 2012, and (ii) dismissing the case before the State Office of Administrative Hearings, sending the settlement to the PUCT for final approval. The PUCT issued a final order approving the settlement on May 23, 2012.

Under the terms of the settlement, among other things, the Company has agreed to:


•	A reduction in its current non-fuel base rates of $15 million annually, with the decrease being allocated primarily to Texas retail commercial and industrial customer classes. The rate decrease was effective as of May 1, 2012 and is the same rate decrease approved by the El Paso Council described above;


•	New tariffs that will include an Economic Development Rate Rider that provides discounts in the demand charge



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

and is intended to spur new business development in the Company's Texas service area;


•	Revised depreciation rates for the Company's gas-fired generating units and for transmission and distribution plant that will lower depreciation expense by $4.1 million annually;


•	Continuation of the 10.125% return on equity for the purpose of calculating the allowance for funds used during construction;


•	A two-year amortization of rate case expenses, none of which will be included in future regulatory proceedings; and


•	Palo Verde decommissioning funding of $3.6 million annually on a Texas jurisdictional basis, which will be subject to review and adjustment on a going-forward basis in future proceedings.

As part of the settlement, the Company agreed to withdraw its request to reconcile fuel costs for the period from July 1, 2009 through September 30, 2011. The Company will file a fuel reconciliation request covering the period beginning July 1, 2009 and ending no later than June 30, 2013 by December 31, 2013 or as part of its next rate case, if earlier.

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 in PUCT Docket No. 37690, to implement a formula to determine its fuel factor which adjusts natural gas and purchased power to reflect natural gas futures prices. 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:

Docket

No.

Date Filed

Date Approved

Recovery Period

Refund Period

Refund

Amount (In Thousands)

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

40622

August 3, 2012

Pending Approval

January 2011- June 2012

September 2012

6,600

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	August 30, 2011	9.4%	August 2011
40302	April 12, 2012	April 25, 2012	(18.5)%	May 2012



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Application of El Paso Electric Company to Amend its Certificate of Convenience and Necessity ("CCN") for Five Solar Powered Generation Projects. On December 9, 2011, the Company filed a petition seeking a CCN to construct five solar powered generation projects, totaling approximately 2.6 MW, at four locations within the City of El Paso and one location in the Town of Van Horn. This case was assigned PUCT Docket No. 39973. A hearing was conducted on June 20, 2012, and a final order is expected in the fourth quarter of 2012.

Generation CCN Filing. On May 2, 2012, the Company filed a petition with the PUCT requesting a CCN to construct a new generation facility to be located at a new plant site, the Montana Power Station, in far east El Paso. The new facility will initially consist of two 88 MW simple-cycle aeroderivative combustion turbines, which will be powered by natural gas. The first unit is scheduled to become operational in 2014. This case was assigned PUCT Docket No. 40301. On August 2, 2012, the administrative law judge established a September 2012 deadline for filing a settlement agreement or a request for hearing.

Energy Efficiency Cost Recovery Factor. On April 30, 2012, the Company filed an application to revise its Energy Efficiency Cost Recovery Factor ("EECRF") and to establish revised energy efficiency goals and cost caps, pursuant to Public Utility Regulatory Act ("PURA") Section 39.905 and PUC Substantive Rule 25.181. The expenditures, revised energy efficiency goals, cost caps proposed by the Company for 2013, a half year of amortization of the prior year deferred costs, and a refund of over-recovery of costs for 2011 result in a decrease in the currently effective EECRF. The State Office of Administrative Hearings established a procedural schedule designed to produce a final order in September 2012. The Company and all parties have agreed to a settlement in principle in this case and have notified the administrative law judge that they intend to file a settlement agreement on or before August 8, 2012.

Military Base Discount Recovery Factor. On July 16, 2012, the Company filed a petition to revise its Military Base Discount Recovery Factor ("MBDRF"), pursuant to PURA Section 36.354, which requires that each electric utility, in an area where customer choice is not available, provide discounted charges to military bases. The Company's rates provide for the 20% discount required by PURA for eligible customers, and assess a surcharge designed to recover the cost of the discount from all other Texas customers. The MBDRF is assessed on the base rate portion of customer bills, and the Company has proposed to increase the surcharge from 0.936% to 1.319%.

New Mexico Regulatory Matters

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 provide 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 briefs were filed on September 26, 2011. A final order was issued on November 22, 2011 in which the NMPRC did not adopt the unopposed stipulation, but modified the structure of the energy rider to reduce the return to two percent and made the mechanism temporary. The Company filed a Notice of Appeal with the Supreme Court of the State of New Mexico on January 20, 2012 on the grounds that the NMPRC's decision is arbitrary and without substantial evidence. However, in accordance with the final order issued on November 22, 2011, the efficient use of energy rider was implemented for New Mexico customers on February 1, 2012. The Supreme Court suspended the appeal pending further NMPRC final order in the Company's 2011 Application for rate rider.

Application for Approval of 2011 New and Modified Energy Efficiency Programs. On February 15, 2011, the Company filed an 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 January 25, 2012, a hearing examiner issued a recommended decision modifying the stipulation by approving the Energy Efficiency programs and budgets with the exception of the Commercial Lighting Program, approving the adder for 2011 but not for 2012 or 2013 and excluding the Military Research & Development Class from participation in the rate rider and reducing the Company's required saving goals accordingly. On February 2, 2012, the Company filed exceptions to the recommended decision and requested an interim order related to this matter. The NMPRC issued a final order approving the partial stipulation and rejecting the Company's exceptions on February 21, 2012. On March 5, 2012, the Company filed an unopposed motion to immediately implement the approved programs and to initiate further proceedings to allow the parties to supplement the record to support the stipulated adders for 2012 and 2013. On March 20, 2012 the NMPRC issued an order granting the unopposed motion. On April 4, 2012, the hearing examiner issued a procedural order requiring additional information supporting the stipulated adders and recovery of regulatory disincentives. The Company filed direct testimony on April 25, 2012 in response to the procedural order. A public hearing was held on July 5 and July 6, 2012. A final order is expected in the fourth quarter of 2012.



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Generation CCN Filing. On May 2, 2012, the Company filed a petition with the NMPRC requesting a CCN to construct a new generation facility to be located at a new plant site, the Montana Power Station, in far east El Paso. The new facility will initially consist of two 88 MW simple-cycle aeroderivative combustion turbines, which will be powered by natural gas. The first unit is scheduled to become operational in 2014. This case was assigned NMPRC Case No. 12-00137-UT. No party has intervened in the proceeding. The procedural schedule adopted by the NMPRC established August 10, 2012 for Staff testimony, and August 13, 2012 as the deadline for protest.

Revolving Credit Facility and Guarantee of Debt. On October 13, 2011, the Company received final approval from the NMPRC in Case No. 11-00349-UT to amend and restate the Company's $200 million revolving credit facility, which includes an option, subject to lender's approval, to expand the size to $300 million, and to incrementally issue up to $300 million of long-term debt as and when needed. Obtaining the ability to issue up to $300 million of new long-term debt, from time to time, provides the Company with the flexibility to access the debt capital markets when needed and when conditions are favorable.

On November 15, 2011, the Company and Rio Grande Resources Trust ("RGRT") amended and restated the $200 million unsecured RCF with JP Morgan Chase Bank, N.A., as administrative agent and issuing bank, and Union Bank, N.A., as syndication agent, and various lending banks party thereto. The amended and restated revolving credit facility ("RCF") reduces borrowing costs and extends the maturity from September 2014 to September 2016.

On March 29, 2012, the Company and The Bank of New York Mellon Trust Company, N.A., as trustee of the Rio Grande Resources Trust, entered into the Incremental Facility Assumption Agreement (the "Assumption Agreement") related to the RCF discussed above with JPMorgan Chase Bank, N.A., as administrative agent and issuing bank, Union Bank, N.A., as syndication agent, and various lending banks party thereto. The Assumption Agreement provides for the Company's exercise in full of the accordion feature provided for under the RCF, increasing the aggregate unsecured borrowing available from $200 million to $300 million. In addition, the Assumption Agreement reflects the addition of a new lender under the RCF. No other material modifications were made to the terms and conditions of the RCF.

2012 Annual Procurement Plan Pursuant to the Renewable Energy Act. On June 29, 2012, the Company filed its application for approval of its 2012 Annual Procurement Plan pursuant to the New Mexico Renewable Energy Act and NMPRC rule 17.9.572 New Mexico Adminstrative Code ("NMAC"). The plan sets out the Company's procurement of renewable resources and estimated costs for 2013 and 2014 to meet Renewable Portfolio Standards (“RPS”) and resource diversity requirements. Concurrently, the Company filed its Annual Renewable Energy portfolio report for 2011. The Company will meet 2013 and 2014 RPS requirements using previously approved resources. Hearings are scheduled for October and a final order is expected in the fourth quarter of 2012.

2012 Integrated Resource Plan (“IRP”). On July 16, 2012, the Company filed its IRP pursuant to the requirements of the NMPRC IRP Rule, 17.7.3 NMAC. This document discusses the Company's integrated resource planning process and develops an integrated resource portfolio to cost-effectively meet the energy needs of its customers for the next twenty years and specifically identifies the Company's resource needs and plans for resource additions during the next four years. The Company's 2012 IRP and Four-Year Action Plan build upon the initial IRP and four-year action plan, submitted to the Commission on July 16, 2009.

Pollution Control Bond Refunding. On April 12, 2012, the Company filed an application with the NMPRC requesting authority for long-term securities transactions necessary to refund and reissue certain Pollution Control Refunding Revenue Bonds (the "PCBs"). On May 31, 2012, the Company received final approval from the NMPRC in case No. 12-00108-UT, which granted the Company the authority to enter into the securities transactions necessary to refund and reissue the 4.00% 2002 Series A refunding bonds in a principal amount of $33.3 million and the 4.80% 2005 Series A refunding bonds in a principal amount of $59.2 million.

Federal Regulatory Matters

Transmission Dispute with Tucson Electric Power Company (“TEP”). On August 31, 2011, the FERC issued an order approving the settlement of a long standing transmission dispute between TEP and the Company that became effective November 1, 2011. The settlement reduces TEP’s transmission rights under the Transmission Agreement from 200 MW to 170 MW and TEP and the Company have entered into two new firm transmission agreements under which TEP is purchasing from the Company new transmission service at the Company's applicable tariff rates for a total of 40 MW. Those two new service agreements were entered into and became effective November 1, 2011. Also under the terms of the settlement, TEP made a lump-sum cash payment to the Company of approximately $5.4 million for the period February 1, 2006 through September 30, 2011, including interest income. This adjustment was recorded in the three months ended September 30, 2011. The Company shared with its Texas customers 25% of the transmission revenues earned before July 1, 2010, or approximately $0.7 million, through a credit to Texas fuel recoveries.



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Revolving Credit Facility and Guarantee of Debt. On October 13, 2011, the Company received final approval from the FERC in Docket No. ES11-43-000 to amend and restate the Company's $200 million RCF, which includes an option, subject to lender's approval, to expand the size to $300 million, and to incrementally issue up to $300 million of long-term debt as and when needed. Obtaining the ability to issue up to $300 million of new long-term debt provides the Company with the flexibility to access the debt capital markets when needed and when conditions are favorable. The Company has two years in which to issue this newly-authorized long-term debt. As noted above, on November 15, 2011, the RCF was amended and restated, and on March 29, 2012, the aggregate unsecured borrowing available under the RCF was increased to $300 million.

Pollution Control Bond Refunding. On April 13, 2012, the Company filed an application with the FERC requesting authority for long-term securities transactions necessary to refund and reissue certain PCBs. On May 30, 2012, the Company received final approval from the FERC in Docket No. ES12-34-0000, granting authority to enter into the securities transactions necessary to refund and reissue the 4.00% 2002 Series A refunding bonds in a principal amount of $33.3 million and the 4.80% 2005 Series A refunding bonds in a principal amount of $59.2 million.

D. Common Stock

Repurchase Program. No shares of common stocks were repurchased during the first six months of 2012. Details regarding the Company’s stock repurchase program are presented below:

_______________________


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


(b)	Shares repurchased does not include 86,735 treasury shares related to employee compensation arrangements outside of the Company's repurchase programs.

The Company may in the future make purchases of its common stock pursuant to its authorized programs in open market transactions at prevailing prices and may engage in private transactions where appropriate. The repurchased shares either will be available for issuance under employee benefit and stock incentive plans, or may be retired.

Dividend Policy. On July 25, 2012, the Board of Directors declared a quarterly cash dividend of $0.25 per share payable on September 28, 2012. On June 29, 2012, the Company paid $10.0 million in dividends to shareholders. The Company paid a total of $18.8 million and $36.8 million in cash dividends during the six and twelve months ended June 30, 2012, respectively. The Company paid a total of $9.2 million in cash dividends during the six and twelve months ended June 30, 2011.



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Basic and Diluted Earnings Per Share. The basic and diluted earnings per share are presented below (in thousands except for share data):
	Three Months Ended June 30,
	2012			2011
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	39,958,149			41,853,552
Dilutive effect of unvested performance awards	64,698			195,078
Dilutive effect of stock options	17,929			28,029
Diluted number of common shares outstanding	40,040,776			42,076,659
Basic net income per common share:
Net income	$	30,894		$	32,990
Income allocated to participating restricted stock	(83		)	(157		)
Net income available to common shareholders	$	30,811		$	32,833
Diluted net income per common share:
Net income	$	30,894		$	32,990
Income reallocated to participating restricted stock	(83		)	(157		)
Net income available to common shareholders	$	30,811		$	32,833
Basic net income per common share:
Distributed earnings	$	0.25		$	0.22
Undistributed earnings	0.52			0.56
Basic net income per common share	$	0.77		$	0.78
Diluted net income per common share:
Distributed earnings	$	0.25		$	0.22
Undistributed earnings	0.52			0.56
Diluted net income per common share	$	0.77		$	0.78



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	Six Months Ended June 30,
	2012			2011
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	39,934,590			42,079,568
Dilutive effect of unvested performance awards	65,450			182,252
Dilutive effect of stock options	20,103			36,896
Diluted number of common shares outstanding	40,020,143			42,298,716
Basic net income per common share:
Net income	$	34,238		$	39,765
Income allocated to participating restricted stock	(104		)	(179		)
Net income available to common shareholders	$	34,134		$	39,586
Diluted net income per common share:
Net income	$	34,238		$	39,765
Income reallocated to participating restricted stock	(104		)	(178		)
Net income available to common shareholders	$	34,134		$	39,587
Basic net income per common share:
Distributed earnings	$	0.47		$	0.22
Undistributed earnings	0.38			0.72
Basic net income per common share	$	0.85		$	0.94
Diluted net income per common share:
Distributed earnings	$	0.47		$	0.22
Undistributed earnings	0.38			0.72
Diluted net income per common share	$	0.85		$	0.94



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	Twelve Months Ended June 30,
	2012			2011
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	40,285,248			42,376,298
Dilutive effect of unvested performance awards	148,256			164,636
Dilutive effect of stock options	22,122			54,077
Diluted number of common shares outstanding	40,455,626			42,595,011
Basic net income per common share:
Net income	$	98,012		$	107,412
Income allocated to participating restricted stock	(379		)	(458		)
Net income available to common shareholders	$	97,633		$	106,954
Diluted net income per common share:
Net income	$	98,012		$	107,412
Income reallocated to participating restricted stock	(378		)	(456		)
Net income available to common shareholders	$	97,634		$	106,956
Basic net income per common share:
Distributed earnings	$	0.91		$	0.22
Undistributed earnings	1.51			2.30
Basic net income per common share	$	2.42		$	2.52
Diluted net income per common share:
Distributed earnings	$	0.91		$	0.22
Undistributed earnings	1.50			2.29
Diluted net income per common share	$	2.41		$	2.51



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		Six Months Ended		Twelve Months Ended
	June 30,		June 30,		June 30,
	2012	2011	2012	2011	2012	2011
Restricted stock awards	32,101	69,639	45,951	81,858	63,699	79,991
Performance shares (a)	51,133	—	47,092	—	23,546	—
Stock options	—	—	—	—	—	—

______________________


(a)	Performance shares excluded from the computation of diluted earnings per share, as no payouts would have been required based upon performance at the end of the corresponding period. This amount assumes a 100% performance level payout.

E. Long-Term Debt and Financing Obligations

Revolving Credit Facility. The Company maintains a revolving credit facility (“RCF”) for working capital and general corporate purposes and financing of nuclear fuel through the Rio Grande Resources Trust (the “RGRT”). RGRT is the trust through which the Company finances its portion of nuclear fuel for Palo Verde and is consolidated in the Company's financial statements. The RCF has a term ending September 2016. On March 29, 2012, the Company and the Bank of New York Mellon Trust Company, N.A., as trustee of the RGRT, entered into the Incremental Facility Assumption Agreement (the “Assumption Agreement”) related to the RCF with JP Morgan Chase Bank, N.A., as administrative agent and issuing bank, Union Bank, N.A., as syndication agent, and various lending banks party thereto. The Assumption Agreement provides for the Company's exercise in full of the accordion feature provided for under the RCF, increasing the aggregate unsecured borrowing available from $200 million to $300 million.

In addition, the Assumption Agreement reflects the addition of a new lender under the RCF. No other material modifications were made to the terms and conditions of the RCF. The total amount borrowed for nuclear fuel by RGRT was $144.8 million at June 30, 2012, of which $34.8 million had been borrowed under the RCF and $110 million was borrowed through senior notes. At



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December 31, 2011, the total amount borrowed for nuclear fuel by RGRT was $123.4 million of which $13.4 million was borrowed under the RCF and $110 million was borrowed through senior notes. Interest costs on borrowings to finance nuclear fuel are accumulated by RGRT and charged to the Company as fuel is consumed and recovered through fuel recovery charges. At June 30, 2012, $76.0 million was outstanding under the RCF for working capital or general corporate purposes. At December 31, 2011, $20.0 million was outstanding under the RCF for working capital or general corporate purposes.

Pollution Control Bonds (“PCBs”). The Company has four series of tax exempt unsecured PCBs in aggregate principal amount of $193.1 million. The 4.00% 2002 Series A with a principal amount of $33.3 million is shown as current maturities of long-term debt on the Company's June 30, 2012 and December 31, 2011 balance sheets. On August 1, 2012, the Company completed a refunding transaction where it purchased these PCBs. The Company may remarket these PCBs at a future date depending on financing needs and market conditions.

F. Income Taxes

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

For the three months ended June 30, 2012 and 2011, the Company’s consolidated effective tax rate was 34.6% and 33.7%, respectively. For the six months ended June 30, 2012 and 2011, the Company's consolidated effective tax rate was 33.4% and 32.0%, respectively. For the twelve months ended June 30, 2012 and 2011, the Company's consolidated effective tax rate was 34.7% and 32.6%, respectively. The Company's consolidated effective tax rate for the three, six and twelve months ended June 30, 2012 differs from the federal statutory tax rate of 35.0% primarily due to the allowance for equity funds used during construction and state income taxes.

FASB guidance prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. In the second quarter of 2012, a $2.8 million decrease was made to the previous reserve for capitalized assets. The decrease is primarily a result of facts and circumstances relating to an IRS safe harbor method regarding units of property of transmission and distribution assets. Further changes to the unrecognized tax position may be recognized as the IRS releases additional guidance as it pertains to generation assets and as the IRS audits of the 2009, 2010 and 2011 tax returns progress. A reconciliation of the June 30, 2012 and 2011 amount of unrecognized tax benefits is as follows (in thousands):



	2012			2011
Balance at January 1	$	9,500		$	7,300
Additions/(reductions) based on tax positions related to the current year	200			1,100
Additions for tax positions of prior years	—			—
Reductions for tax positions of prior years	(2,800		)	—
Balance at June 30	$	6,900		$	8,400



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G. Commitments, Contingencies and Uncertainties

For a full discussion of commitments and contingencies, see Note K of Notes to Consolidated Financial Statements in the 2011 Form 10-K. In addition, see Note C above and Notes C and E of Notes to Consolidated Financial Statements in the 2011 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, and to meet required renewable portfolio standards, the Company engages in firm power purchase arrangements which may vary in duration and amount based on evaluation of the Company’s resource needs, the economics of the transactions, and specific renewable portfolio requirements. For a full discussion of power purchase and sale contracts that the Company has entered into with various counterparties, see Note K of Notes to Consolidated Financial Statements in the 2011 Form 10-K. In addition to the contracts disclosed in the 2011 Form 10-K, in March 2012, the Company entered into a purchase contract with Southwestern Public Service Company for 65 MW during the months of June through August 2012.

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 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 liabilities. 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 ("PM"), 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. The U.S. Court of Appeals for the District of Columbia voided CAIR in 2008; however, the Company has complied with CAIR since 2009, and such rule is binding. The annual reconciliation to comply with CAIR is due by March 31 of the following year. The Company has purchased allowances and expensed the following costs to meet its annual requirements (in thousands):

Cross-State Air Pollution Rule. In July 2011, the EPA finalized the Cross-State Air Pollution Rule (“CSAPR”) which is intended to replace CAIR. CSAPR requires 28 states, including Texas, to further reduce power plant emissions of SO₂ and NOx. Under CSAPR, reductions in annual SO₂ and NOx emissions were required to begin January 1, 2012, with further reductions required beginning January 1, 2014. On December 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit issued its ruling to stay CSAPR, including the supplemental final rule, pending judicial review, which delays CSAPR's implementation date beyond January 1, 2012. The court is scheduled to hear the cases against the rule in 2012, with a decision later in 2012. As the outcome of the judicial review and any other legal or Congressional challenges are uncertain, the Company is unable to determine what impact CSAPR may ultimately have on its operations and consolidated financial results, but it could be material. Until the legal challenges to CSAPR are resolved, the Company's obligations under CAIR remains in effect.

National Ambient Air Quality Standards. Under the CAA, the EPA sets National Ambient Air Quality Standards ("NAAQS") for six criteria emissions considered harmful to public health and the environment, including PM, NOx, CO and SO₂. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the



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EPA at five-year intervals. In 2010, the EPA strengthened the NAAQS for both NOx and SO₂. The Company continues to evaluate what impact this could have on its operations. If the Company is required to install additional equipment to control emissions at its facilities, the revised NAAQS could have a material impact on its operations and consolidated financial results. In addition, as a result of EPA's review of the PM NAAQS, the agency proposed on June 14, 2012, to strengthen the annual health standard for fine particulate matter and set a new, separate fine particle standard to improve visibility. Also, the EPA had been in the process of revising the NAAQS for ozone, when, in September 2011, President Obama ordered the EPA to withdraw its proposal. Work, however, is underway to support EPA's planned reconsideration of the standards in 2013. The Company cannot at this time predict the impact of these possible new standards on its operations or consolidated financial results, but it could be material.

Utility MACT. The operation of coal-fired power plants, such as the Company's Four Corners plant, results in emissions of mercury and other air toxics. In December 2011, the EPA finalized Mercury and Air Toxics Standards (known as the "Utility MACT") for oil- and coal-fired power plants, which replaces the prior federal Clean Air Mercury Rule and requires significant reductions in emissions of mercury and other air toxics. Several challenges are being made to this rule, including a proposal to withdraw the rule, which was rejected by the Senate on June 20, 2012. These challenges notwithstanding, companies impacted by the new standards will have up to four (and in certain limited cases five) years to comply. Information to the Company from the Four Corners plant operator, APS, indicates that APS believes Units 4 and 5 will require no additional modifications to achieve compliance with the Utility MACT standards; however, further testing and evaluation are planned. If additional controls are needed, the cost of compliance 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 unlikely to recommence in the near future. Nonetheless, it is possible that federal legislation related to GHG emissions will be considered by Congress in the future. The EPA has begun using the CAA to limit carbon dioxide and other GHG emissions, and other measures are being imposed or offered by individual states, municipalities and regional agreements with the goal of reducing 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, and the first report containing 2010 emissions was submitted to the EPA prior to the September 30, 2011 due date. The Company also has inventoried and implemented procedures for electrical equipment containing sulfur hexafluoride ("SF6"), another GHG. The Company is tracking these GHG emissions pursuant to the 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 was originally due on March 31, 2012, but in November 2011, EPA delayed its submittal to September 28, 2012.

The 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 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 100,000 tons 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, the 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, and certain agreed upon extensions, on March 27, 2012, EPA released its proposed GHG New Source Performance Standard ("NSPS") for new and modified electric generating units. The Company is currently determining how this proposed rule may impact existing and future operations and has provided comments to EPA during the comment period ending on June 25, 2012, supporting EPA's proposed exemption for simple cycle combustion turbines. The impact of these rules on the Company is unknown at this time, but they could result in significant costs, limitations on operating hours, and/or changes in construction schedules for future generating units.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

In addition, almost half of the states, either individually and/or through multi-state regional initiatives, have begun to consider how to address GHG emissions and have developed, or are actively considering the development of emission inventories or regional GHG cap and trade programs.

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 the Company's 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 $0.5 million at June 30, 2012, 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.

The Company incurred the following expenditures during the three, six and twelve months ended June 30, 2012 and 2011 to comply with federal environmental statutes (in thousands):



	Three Months Ended				Six Months Ended				Twelve Months Ended
	June 30,				June 30,				June 30,
	2012		2011		2012		2011		2012		2011
Clean Air Act (1)	$	194	$	253	$	423	$	293	$	846	$	620
Clean Water Act	55		53		101		109		256		184

_________________

(1) Includes an accrual of $0.2 million, in the first quarter of 2012, related to Four Corners generating station discussed below.

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. The EPA has taken the position that many utilities have made certain physical or operational changes at their plants that should have triggered additional regulatory requirements under the New Source Review provisions of the CAA. APS responded to this request in 2009. 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. Since July 2011, the U.S. Department of Justice ("DOJ"), on behalf of the EPA, and APS have been engaged in substantive settlement negotiations. Most recently, by letter dated March 2, 2012, the DOJ submitted a revised settlement proposal. Settlement discussions have included provisions for a civil penalty and environmental mitigation projects. The Company has determined that payment of a penalty and payment for environmental mitigation projects is likely to occur and that the current range for the Company's loss contingency exposure is $0.2 million to $0.9 million. The Company has accrued $0.2 million related to this matter. The settlement discussions have emphasized that the environment mitigation projects that address alleged harm to the Navajo Nation be spent within 5 years years of the date a decree is entered.



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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The Company received notice that Earthjustice filed a lawsuit in the United States District Court for New Mexico on October 4, 2011 for alleged violations of the Prevention of Significant Deterioration provisions of the CAA related to Four Corners. Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the CAA's NSPS program. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required PSD permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. APS advised that it believes the claims in this matter are without merit and will vigorously defend against them. The Company is unable to predict the outcome of this litigation.

H. 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.

I. Employee Benefits

Retirement Plans

The net periodic benefit cost recognized for the three, six and twelve months ended June 30, 2012 and 2011 is made up of the components listed below as determined using the projected unit credit actuarial cost method (in thousands):



	Three Months Ended						Six Months Ended						Twelve Months Ended
	June 30,						June 30,						June 30,
	2012			2011			2012			2011			2012			2011
Components of net periodic benefit cost:
Service cost	$	2,189		$	1,682		$	4,414		$	3,425		$	7,839		$	6,457
Interest cost	3,400			3,499			6,778			6,994			13,771			13,808
Amendments	—			—			—			—			—			838
Expected return on plan assets	(3,611		)	(3,515		)	(7,221		)	(7,048		)	(14,268		)	(13,982		)
Amortization of:
Net loss	2,713			1,689			5,678			3,272			8,950			5,047
Prior service cost	31			31			58			58			115			115
Net periodic benefit cost	$	4,722		$	3,386		$	9,707		$	6,701		$	16,407		$	12,283

During the six months ended June 30, 2012, the Company contributed $11.5 million of its projected $19.8 million 2012 annual contribution to its retirement plans.



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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Other Postretirement Benefits

The net periodic benefit cost recognized for the three, six and twelve months ended June 30, 2012 and 2011 is made up of the components listed below (in thousands):



	Three Months Ended						Six Months Ended						Twelve Months Ended
	June 30,						June 30,						June 30,
	2012			2011			2012			2011			2012			2011
Components of net periodic benefit cost:
Service cost	$	1,119		$	756		$	2,189		$	1,494		$	3,683		$	3,273
Interest cost	1,410			1,399			2,825			2,689			5,515			6,021
Expected return on plan assets	(453		)	(454		)	(888		)	(912		)	(1,799		)	(1,676		)
Amortization of:
Prior service benefit	(1,468		)	(1,481		)	(2,938		)	(2,963		)	(5,902		)	(4,397		)
Net loss (gain)	147			89			307			(19		)	287			(107		)
Net periodic benefit cost	$	755		$	309		$	1,495		$	289		$	1,784		$	3,114

During the six months ended June 30, 2012, the Company contributed $0.6 million of its projected $2.5 million 2012 annual contribution to its postretirement plan.

J. 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 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, 2012				December 31, 2011
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Pollution Control Bonds	$	193,135	$	212,159	$	193,135	$	206,756
Senior Notes	546,689		679,250		546,662		700,371
RGRT Senior Notes (1)	110,000		120,190		110,000		116,985
RCF (1)	110,760		110,760		33,379		33,379
Total	$	960,584	$	1,122,359	$	883,176	$	1,057,491

_______________

(1)

Nuclear fuel financing as of June 30, 2012 and December 31, 2011 is funded through the $110 million RGRT Senior Notes and $34.8 million and $13.4 million, respectively under the RCF. As of June 30, 2012 and December 31, 2011, $76.0 million and $20.0 million, respectively, were outstanding under the RCF for working capital and general 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.



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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Marketable Securities. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair value which was $178.3 million and $168.0 million at June 30, 2012 and December 31, 2011, 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):



	June 30, 2012
	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	$	15	$	(1	)	$	1,048	$	(26	)	$	1,063	$	(27	)
U.S. Government Bonds	4,785		(41		)	1,175		(40		)	5,960		(81		)
Municipal Obligations	8,297		(71		)	4,938		(232		)	13,235		(303		)
Corporate Obligations	1,144		(8		)	912		(13		)	2,056		(21		)
Total Debt Securities	14,241		(121		)	8,073		(311		)	22,314		(432		)
Common Stock	5,487		(706		)	1,103		(211		)	6,590		(917		)
Total Temporarily Impaired Securities	$	19,728	$	(827	)	$	9,176	$	(522	)	$	28,904	$	(1,349	)

_________________


(1)	Includes approximately 67 securities.



	December 31, 2011
	Less than 12 Months					12 Months or Longer					Total
	Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses
Description of Securities (2):
Federal Agency Mortgage Backed Securities	$	515	$	(8	)	$	1,233	$	(23	)	$	1,748	$	(31	)
U.S. Government Bonds	100		(1		)	2,413		(38		)	2,513		(39		)
Municipal Obligations	2,275		(31		)	4,731		(144		)	7,006		(175		)
Corporate Obligations	3,525		(118		)	1,234		(43		)	4,759		(161		)
Total Debt Securities	6,415		(158		)	9,611		(248		)	16,026		(406		)
Common Stock	10,688		(2,065		)	1,740		(489		)	12,428		(2,554		)
Total Temporarily Impaired Securities	$	17,103	$	(2,223	)	$	11,351	$	(737	)	$	28,454	$	(2,960	)

_________________


(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.



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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, 2012				December 31, 2011
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
Description of Securities:
Federal Agency Mortgage Backed Securities	$	22,065	$	1,206	$	25,077	$	1,220
U.S. Government Bonds	9,129		754		10,263		972
Municipal Obligations	27,017		1,621		30,310		1,792
Corporate Obligations	10,679		705		7,641		459
Total Debt Securities	68,890		4,286		73,291		4,443
Common Stock	67,252		20,885		62,479		15,681
Equity Mutual Funds	9,073		393		—		—
Cash and Cash Equivalents	4,160		—		3,739		—
Total	$	149,375	$	25,564	$	139,509	$	20,124

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 years or more. The mortgage-backed securities have an estimated weighted average maturity which generally range from 3 years to 7 years years and reflects anticipated future prepayments. The contractual year for maturity of these available-for-sale securities as of June 30, 2012 is as follows (in thousands):



	Total		2012		2013 through 2016		2017 through 2021		2022 and Beyond
Municipal Debt Obligations	$	40,252	$	989	$	10,993	$	16,847	$	11,423
Corporate Debt Obligations	12,735		—		3,740		5,314		3,681
U.S. Government Bonds	15,089		—		4,261		8,034		2,794

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, 2012 and 2011, the Company recognized other than temporary impairment losses on its available-for-sale securities as follows (in thousands):



	Three Months Ended						Six Months Ended						Twelve Months Ended
	June 30,						June 30,						June 30,
	2012			2011			2012			2011			2012			2011
Gross unrealized holding losses included in pre-tax income	$	(166	)	$	(199	)	$	(166	)	$	(199	)	$	(2,083	)	$	(199	)



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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						Six Months Ended						Twelve Months Ended
	June 30,						June 30,						June 30,
	2012			2011			2012			2011			2012			2011
Proceeds from sales of available-for-sale securities	$	39,934		$	22,175		$	59,513		$	36,406		$	106,033		$	63,857
Gross realized gains included in pre-tax income	$	690		$	432		$	1,079		$	696		$	1,862		$	1,200
Gross realized losses included in pre-tax income	(1,971		)	(235		)	(2,147		)	(294		)	(2,574		)	(511		)
Gross unrealized losses included in pre-tax income	(166		)	(199		)	(166		)	(199		)	(2,083		)	(199		)
Net gains (losses) in pre-tax income	$	(1,447	)	$	(2	)	$	(1,234	)	$	203		$	(2,795	)	$	490
Net unrealized holding gains (losses) included in accumulated other comprehensive income	$	(2,341	)	$	416		$	5,817		$	2,589		$	4,798		$	13,232
Net (gains) losses reclassified out of accumulated other comprehensive income	1,447			2			1,234			(203		)	2,795			(490		)
Net gains (losses) in other comprehensive income	$	(894	)	$	418		$	7,051		$	2,386		$	7,593		$	12,742

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 are 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.


•	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.



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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The fair value of the Company’s decommissioning trust funds and investments in debt securities, at June 30, 2012 and December 31, 2011, 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, 2012		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	$	1,228	$	—	$	—	$	1,228
Available for sale:
U.S. Government Bonds	$	15,089	$	15,089	$	—	$	—
Federal Agency Mortgage Backed Securities	23,128		—		23,128		—
Municipal Bonds	40,252		—		40,252		—
Corporate Asset Backed Obligations	12,735		—		12,735		—
Subtotal Debt Securities	91,204		15,089		76,115		—
Common Stock	73,842		73,842		—		—
Equity Mutual Funds	9,073		9,073		—		—
Cash and Cash Equivalents	4,160		4,160		—		—
Total available for sale	$	178,279	$	102,164	$	76,115	$	—



Description of Securities	Fair Value as of December 31, 2011		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Trading Securities:
Investments in Debt Securities	$	1,120	$	—	$	—	$	1,120
Available for sale:
U.S. Government Bonds	$	12,776	$	12,776	$	—	$	—
Federal Agency Mortgage Backed Securities	26,825		—		26,825		—
Municipal Bonds	37,316		—		37,316		—
Corporate Asset Backed Obligations	12,400		—		12,400		—
Subtotal Debt Securities	89,317		12,776		76,541		—
Common Stock	74,907		74,907		—		—
Cash and Cash Equivalents	3,739		3,739		—		—
Total available for sale	$	167,963	$	91,422	$	76,541	$	—

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, 2012 and June 30, 2011.

During the fourth quarter of 2011, the Company sold an investment in a debt security for $2.0 million that was categorized as a Level 3 investment. The Company realized in the consolidated statement of operations as investment and interest income a gain on the sale of the debt security of $0.4 million during the twelve month period ending June 30, 2012. There were no other purchases, sales, issuances, or settlements related to the assets in the Level 3 fair value measurement category during the three, six and twelve month periods ending June 30, 2012 and 2011.



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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, 2012, the related consolidated statements of operations and comprehensive operations for the three-month, six-month and twelve-month periods ended June 30, 2012 and 2011, and the related consolidated statements of cash flows for the six-month periods ended June 30, 2012 and 2011. 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, 2011, 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 24, 2012, 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, 2011, 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 3, 2012



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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 2011 Annual Report on Form 10-K.

FORWARD-LOOKING STATEMENTS

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


•	capital expenditures,


•	earnings,


•	liquidity and capital resources,


•	ratemaking/regulatory matters,


•	litigation,


•	accounting matters,


•	possible corporate restructurings, acquisitions and dispositions,


•	compliance with debt and other restrictive covenants,


•	interest rates and dividends,


•	environmental matters,


•	nuclear operations, and


•	the overall economy of our service area.

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


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


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


•	reductions in output at generation plants operated by us,


•	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 recovery mechanisms and other regulatory matters including the ability to recover fuel costs on a timely basis,


•	changes in environmental laws and regulations and the enforcement or interpretation thereof, 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 post-retirement 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.



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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 the 2011 Annual Report on 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 2011 Annual Report on 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, 2012 and 2011. Income before extraordinary item for the three, six and twelve month periods ended June 30, 2012 and 2011 is shown below:



	Three Months Ended				Six Months Ended				Twelve Months Ended
	June 30,				June 30,				June 30,
	2012		2011		2012		2011		2012		2011
Income before extraordinary item (in thousands)	$	30,894	$	32,990	$	34,238	$	39,765	$	98,012	$	97,126
Basic earnings per share before extraordinary item	0.77		0.78		0.85		0.94		2.42		2.28

The following table and accompanying explanations show the primary factors affecting the after-tax change in income before extraordinary item between the 2012 and 2011 periods presented (in thousands):



	Three Months Ended			Six Months Ended			Twelve Months Ended
June 30, 2011 income before extraordinary item	$	32,990		$	39,765		$	97,126
Change in (net of tax):
Decreased Palo Verde operations and maintenance expense (a)	1,409			729			1,976
Increased transmission wheeling revenues (b)	374			570			2,954
Increased (decreased) allowance for funds used during construction (c)	285			(1,248		)	(4,821		)
Increased retail non-fuel base revenues (d)	2			1,341			11,223
Decreased deregulated Palo Verde Unit 3 revenues (e)	(1,260		)	(2,109		)	(1,975		)
Decreased investment and interest income (f)	(1,183		)	(1,565		)	(2,943		)
Increased pensions and benefits expense (g)	(812		)	(1,553		)	(1,305		)
Increased operating and maintenance expense at fossil fuel generating plants (h)	(469		)	(2,107		)	(5,096		)
Other	(442		)	415			873
June 30, 2012 income before extraordinary item	$	30,894		$	34,238		$	98,012

______________

(a)

Palo Verde non-fuel operations and maintenance expense for the three months ended June 30, 2012, compared to the same period last year, decreased primarily due to the timing of the Unit 3 spring refueling outage which began on March 17, 2012 and was completed on April 17, 2012. In 2011, the Unit 2 spring refueling outage began on April 2, 2011 and was completed on May 6, 2011. Palo Verde non-fuel operations and maintenance expense for the six and twelve months ended June 30, 2012 compared to the same period last year decreased primarily due to decreased maintenance costs as the result of reduced costs for scheduled refueling outages.


(b)	Transmission revenues increased for the twelve months ended June 30, 2012, compared to the same period last year, due to a settlement agreement with Tucson Electric Power Company involving a transmission dispute that resulted in a one-time adjustment to income of $3.9 million, pre-tax.



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(c)	Allowance for funds used during construction ("AFUDC") decreased in the six and twelve months ended June 30, 2012 compared to the same periods last year primarily due to lower balances of construction work in progress subject to AFUDC reflecting the completion and placing in service the Newman Unit 5 Phase II generating plant addition.

(d)

Retail non-fuel base revenues increased for the three, six and twelve months ended June 30, 2012, compared to the same periods in 2011, primarily due to a 2.4%, 2.8% and 3.1% increase, respectively, in kWh sales to retail customers reflecting 1.5% growth in the average number of retail customers served in all periods. These increases were partially offset by reduced non-fuel base rates for Texas customers which became effective May 1, 2012. Retail non-fuel base revenues exclude fuel recovered through New Mexico base rates. For a complete discussion of non-fuel rate base revenues, see page 30.

(e)

Revenues from retail sales of deregulated Palo Verde Unit 3 power decreased for the three and six months ended June 30, 2012, compared to the same periods last year, due to lower proxy market prices due to the decline in natural gas prices and a 21% and 17% decrease in generation at Palo Verde Unit 3, respectively, due to a refueling outage beginning on March 17, 2012 which was completed on April 17, 2012. Revenues from retail sales of deregulated Palo Verde Unit 3 power decreased for the twelve months ended June 30, 2012 compared to the same period last year due to lower proxy market prices and increased costs of nuclear fuel.


(f)	Investment and interest income decreased for the three, six, and twelve months ended June 30, 2012, compared to the same periods in 2011, primarily due to increased net unrealized and realized losses on equity investments in our decommissioning trust.


(g)	Pensions and benefits expense increased for the three, six, and twelve months ended June 30, 2012, compared to the same periods in 2011, reflecting the impact of lower discount rates used to determine pension and other postretirement benefit liabilities and expense.

(h)

Operations and maintenance expense increased at our fossil fuel generating plants in both the six and twelve months ended June 30, 2012, when compared to the same periods last year, primarily due to the timing of planned maintenance. In the six months ended June 30, 2012, we performed scheduled major maintenance at Rio Grande Unit 8 and at Newman Unit 1. In the twelve months ended June 30, 2012, major maintenance was performed at Newman Unit 4 and at the Four Corners generating plant.



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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.

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.

No retail customer accounted for more than 4% of our non-fuel base revenues during such periods. 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 current rate structure in New Mexico and Texas reflects higher base rates during the peak summer season of May through October and lower 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 months ended June 30, 2012, the weather in our local service territory was similar to the weather during the same period last year. Cooling degree days increased 1% when compared to the same period in 2011 and 29% above the 30-year average. For the six months ended June 30, 2012, cooling degree days were relatively unchanged when compared to the same period in 2011 and 31% above the 30-year average. For the six month period, heating degree days were 7% below the same period last year and 11% below the 30-year average. For the twelve months ended June 30, 2012, cooling degree days were 7% above the same period last year and 30% above the 30-year average. For the twelve month period heating degree days were 10% above the same period last year and 5% below the 30-year average. Heating and cooling degree days can be used to evaluate the effect of weather on energy use. For each degree that 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 30-year average.



	Three Months Ended			Six Months Ended			Twelve Months Ended
	June 30,		30-Year	June 30,		30-Year	June 30,		30-Year
	2012	2011	Average	2012	2011	Average	2012	2011	Average*
Heating degree days	50	40	91	1,209	1,305	1,364	2,306	2,100	2,426
Cooling degree days	1,178	1,169	914	1,215	1,210	927	3,140	2,944	2,410

______________

* Calendar year basis.

Customer growth is a key driver of the growth of retail sales. The average number of retail customers grew 1.5% for the three, six, and twelve months ended June 30, 2012 when compared to the same periods last year. See the tables presented on pages 32 , 33 and 34 which provide detail on the average number of retail customers and the related revenues and kWh sales.

Retail non-fuel base revenues. Our rate structure effective July 1, 2010 through April 30, 2012 in Texas was based on the final order in PUCT Docket No. 37690 which approved a settlement that called for an annual increase of $17.15 million in non-fuel base rates. On April 17, 2012, the City Council (the “Council”) of El Paso, Texas approved the settlement of our 2012 Texas retail rate case and fuel reconciliation in PUCT Docket No. 40094 and on April 26, 2012, the administrative law judge issued an order implementing the settlement rates as temporary rates effective May 1, 2012. The PUCT approved the settlement on May 18, 2012. Under the terms of the settlement, among other things, we agreed to a reduction in our current non-fuel base rates of $15 million annually, with the decrease being allocated primarily to Texas retail commercial and industrial customer classes.

Retail non-fuel base revenues remained relatively flat for the three months ended June 30, 2012, when compared to the same period last year. We experienced a 2.4% increase in kWh sales to retail customers reflecting 1.5% growth in the average number of customers served. Cooling degree days were similar in the second quarters of 2012 and 2011 and as a result had a minimal impact on sales growth. However, cooling degree days in both periods were at least 28% above the 30-year average. KWh sales to residential customers increased 5.6% and non-fuel base revenues from residential customers increased 4.2%. KWh sales to other public authorities increased 6.5% and non-fuel revenues from other public authorities increased 7.0%. Non-fuel base revenues from sales to small commercial and industrial customers and large commercial and industrial customers decreased 4.1% and 15.6%, respectively, in the second quarter primarily due to a reduction in non-fuel base rates in Texas which became effective



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May 1, 2012, increased use of lower interruptible rates and decreased consumption by several large commercial and industrial customers. KWh sales to large commercial and industrial customers decreased 6.9% for the three month period.

Retail non-fuel base revenues increased by $2.1 million, or 0.8%, for the six months ended June 30, 2012, when compared to the same period last year, primarily due to a 2.8% increase in kWh sales to retail customers reflecting 1.5% growth in the average number of customers served. KWh sales to residential customers increased 4.2% and non-fuel base revenues from residential customers increased 3.4%. KWh sales to other public authorities increased 4.7% and non-fuel revenues from other public authorities increased 4.0%. Non-fuel base revenues from sales to small commercial and industrial customers and large commercial and industrial customers decreased 1.9% and 6.4%, respectively, due to a reduction in non-fuel base rates in Texas which became effective May 1, 2012 and increased use of lower interruptible rates. KWh sales to large commercial and industrial customers decreased 0.8% for the six month period.

Retail non-fuel base revenues for the twelve months ended June 30, 2012 increased by $17.8 million or 3.2%, compared to the same period in 2011, primarily due to a 3.1% 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, 2012, cooling degree days were 7% above the same period in 2011 and 30% above the 30-year average. KWh sales to residential customers and other public authorities increased 5.3% and 3.4%, respectively, during the twelve months ended June 30, 2012, compared to the same period last year. KWh sales to small commercial and industrial customers increased 2.1%.

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, 2012, we over-recovered our fuel costs by $3.7 million and $15.6 million, respectively, compared to a fuel under-recovery of $12.7 million and $13.7 million in the same periods in 2011. A refund of $12 million was made to our Texas customers in April 2011. In the twelve months ended June 30, 2012, we over-recovered our fuel costs by $15.4 million compared to fuel over-recoveries of $9.6 million in the same period last year. Refunds of $35.0 million were returned to our Texas customers in the twelve months ended June 30, 2011. At June 30, 2012, we had a net fuel over-recovery balance of $8.6 million, including $6.7 million in Texas, $1.8 million in New Mexico, and $0.1 million in FERC. A filing to refund over-recovered fuel costs in Texas was made in early August 2012.

Off-system sales. 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 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.

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.

Off-system sales revenues increased $3.7 million, or 22.0% for the three months ended June 30, 2012, when compared to the same period last year, as a result of higher average market prices for power and a 7.8% increase in MWh sales. Retained margins from off-system sales increased $1.2 million for the three months ended June 30, 2012, compared to the same period last year, primarily due to the negative impact of power purchases required for system reliability when wildfires in June 2011 threatened key transmission lines in eastern Arizona and western New Mexico. Off-system sales revenues decreased $0.9 million, or 2.4% for the six months ended June 30, 2012, when compared to the same period last year, as a result of lower average market prices for power and a 0.5% decline in MWh sales. However, retained margins from off-system sales increased $1.4 million for the six months ended June 30, 2012, compared to the same period last year, due to the negative impacts of power purchases required for system reliability during extremely cold weather in February 2011 and the wildfires in June 2011 mentioned above. Off-system sales revenues decreased $9.8 million, or 11.3% for the twelve months ended June 30, 2012, when compared to the same period last year, as a result of a 7.5% decline in MWh sales and a decrease in the average market price for power. However, retained margins from off-system sales increased approximately $1.2 million for the twelve months ended June 30, 2012, compared to the corresponding period in 2011, primarily due to the negative impacts of power purchases required for system reliability during extremely cold weather in February 2011 and the wildfires in June 2011 mentioned above.



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Comparisons of kWh sales and operating revenues are shown below (in thousands):
							Increase (Decrease)
Quarter Ended June 30:	2012			2011			Amount			Percent
kWh sales:
Retail:
Residential	672,693			637,257			35,436			5.6	%
Commercial and industrial, small	641,452			634,081			7,371			1.2
Commercial and industrial, large	287,802			308,978			(21,176		)	(6.9	)
Sales to public authorities	439,957			413,258			26,699			6.5
Total retail sales	2,041,904			1,993,574			48,330			2.4
Wholesale:
Sales for resale	20,690			19,346			1,344			6.9
Off-system sales	720,810			668,420			52,390			7.8
Total wholesale sales	741,500			687,766			53,734			7.8
Total kWh sales	2,783,404			2,681,340			102,064			3.8
Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	61,388		$	58,934		$	2,454		4.2	%
Commercial and industrial, small	54,719			57,060			(2,341		)	(4.1	)
Commercial and industrial, large	10,382			12,305			(1,923		)	(15.6	)
Sales to public authorities	27,811			25,998			1,813			7.0
Total retail non-fuel base revenues	154,300			154,297			3			—
Wholesale:
Sales for resale	776			785			(9		)	(1.1	)
Total non-fuel base revenues	155,076			155,082			(6		)	—
Fuel revenues:
Recovered from customers during the period	30,969			33,672			(2,703		)	(8.0	)	(1)
Under (over) collection of fuel	(3,659		)	12,700			(16,359		)	—
New Mexico fuel in base rates	17,743			17,156			587			3.4
Total fuel revenues	45,053			63,528			(18,475		)	(29.1	)	(2)
Off-system sales:
Fuel cost	16,506			17,256			(750		)	(4.3	)
Shared margins	3,455			248			3,207			—
Retained margins	419			(793		)	1,212			—
Total off-system sales	20,380			16,711			3,669			22.0
Other	7,743			7,284			459			6.3		(3)
Total operating revenues	$	228,252		$	242,605		$	(14,353	)	(5.9	)
Average number of retail customers:
Residential	340,827			335,808			5,019			1.5	%
Commercial and industrial, small	38,081			37,096			985			2.7
Commercial and industrial, large	50			50			—			—
Sales to public authorities	4,621			4,849			(228		)	(4.7	)
Total	383,579			377,803			5,776			1.5


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


(2)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $1.9 million and $3.9 million, respectively.


(3)	Represents revenues with no related kWh sales.



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							Increase (Decrease)
Six Months Ended June 30:	2012			2011			Amount			Percent
kWh sales:
Retail:
Residential	1,228,262			1,178,539			49,723			4.2	%
Commercial and industrial, small	1,132,689			1,112,602			20,087			1.8
Commercial and industrial, large	534,160			538,210			(4,050		)	(0.8	)
Sales to public authorities	783,468			748,227			35,241			4.7
Total retail sales	3,678,579			3,577,578			101,001			2.8
Wholesale:
Sales for resale	32,497			30,999			1,498			4.8
Off-system sales	1,429,489			1,436,040			(6,551		)	(0.5	)
Total wholesale sales	1,461,986			1,467,039			(5,053		)	(0.3	)
Total kWh sales	5,140,565			5,044,617			95,948			1.9
Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	107,413		$	103,911		$	3,502		3.4	%
Commercial and industrial, small	88,520			90,274			(1,754		)	(1.9	)
Commercial and industrial, large	19,753			21,106			(1,353		)	(6.4	)
Sales to public authorities	44,751			43,018			1,733			4.0
Total retail non-fuel base revenues	260,437			258,309			2,128			0.8
Wholesale:
Sales for resale	1,174			1,335			(161		)	(12.1	)
Total non-fuel base revenues	261,611			259,644			1,967			0.8
Fuel revenues:
Recovered from customers during the period	63,503			59,535			3,968			6.7		(1)
Under (over) collection of fuel	(15,590		)	13,738			(29,328		)	—
New Mexico fuel in base rates	34,707			33,525			1,182			3.5
Total fuel revenues	82,620			106,798			(24,178		)	(22.6	)	(2)
Off-system sales:
Fuel cost	31,972			37,519			(5,547		)	(14.8	)
Shared margins	4,643			1,412			3,231			—
Retained margins	559			(854		)	1,413			—
Total off-system sales	37,174			38,077			(903		)	(2.4	)
Other	15,425			14,198			1,227			8.6		(3)
Total operating revenues	$	396,830		$	418,717		$	(21,887	)	(5.2	)
Average number of retail customers:
Residential	340,149			335,320			4,829			1.4	%
Commercial and industrial, small	38,044			37,081			963			2.6
Commercial and industrial, large	50			50			—			—
Sales to public authorities	4,587			4,693			(106		)	(2.3	)
Total	382,830			377,144			5,686			1.5


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


(2)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $4.5 million and $7.9 million, respectively.


(3)	Represents revenues with no related kWh sales.



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							Increase (Decrease)
Twelve Months Ended June 30:	2012			2011			Amount			Percent
kWh sales:
Retail:
Residential	2,683,113			2,547,997			135,116			5.3	%
Commercial and industrial, small	2,372,305			2,322,809			49,496			2.1
Commercial and industrial, large	1,091,990			1,099,915			(7,925		)	(0.7	)
Sales to public authorities	1,614,806			1,561,289			53,517			3.4
Total retail sales	7,762,214			7,532,010			230,204			3.1
Wholesale:
Sales for resale	64,154			58,121			6,033			10.4
Off-system sales	2,681,080			2,899,564			(218,484		)	(7.5	)
Total wholesale sales	2,745,234			2,957,685			(212,451		)	(7.2	)
Total kWh sales	10,507,448			10,489,695			17,753			0.2
Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	237,588		$	226,538		$	11,050		4.9	%
Commercial and industrial, small	194,339			192,227			2,112			1.1
Commercial and industrial, large	44,054			44,129			(75		)	(0.2	)
Sales to public authorities	96,103			91,376			4,727			5.2
Total retail non-fuel base revenues	572,084			554,270			17,814			3.2
Wholesale:
Sales for resale	1,961			2,404			(443		)	(18.4	)
Total non-fuel base revenues	574,045			556,674			17,371			3.1
Fuel revenues:
Recovered from customers during the period	149,098			146,842			2,256			1.5		(1)
Under (over) collection of fuel	(15,411		)	(9,578		)	(5,833		)	60.9
New Mexico fuel in base rates	74,636			71,819			2,817			3.9
Total fuel revenues	208,323			209,083			(760		)	(0.4	)	(2)
Off-system sales:
Fuel cost	69,189			81,512			(12,323		)	(15.1	)
Shared margins	7,114			5,805			1,309			22.5
Retained margins	853			(336		)	1,189			—
Total off-system sales	77,156			86,981			(9,825		)	(11.3	)
Other	36,602			27,665			8,937			32.3		(3)
Total operating revenues	$	896,126		$	880,403		$	15,723		1.8
Average number of retail customers:
Residential	338,634			334,350			4,284			1.3	%
Commercial and industrial, small	38,134			36,754			1,380			3.8
Commercial and industrial, large	50			49			1			2.0
Sales to public authorities	4,573			4,631			(58		)	(1.3	)
Total	381,391			375,784			5,607			1.5


(1)	Excludes $35.0 million of refunds 2011 related to Texas deferred fuel revenues from prior periods.


(2)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $11.4 million and $14.6 million, respectively.


(3)	Represents revenues with no related kWh sales. Includes a one-time $3.9 million settlement of a transmission dispute with Tucson Electric Power Company recorded in the third quarter of 2011.



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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 35% of our available net generating capacity and approximately 50%, 56% and 54% of our Company-generated energy for the three, six, and twelve months ended June 30, 2012, respectively. Fluctuations in the price of natural gas have had a significant impact on our cost of energy.

Energy expenses decreased $13.7 million or 17.7% for the three months ended June 30, 2012, when compared to 2011, primarily due to (i) decreased natural gas costs of $14.5 million due to a 43.1% decrease in the average price of natural gas partially offset by a 32.1% increase in MWhs generated with natural gas, and a $3.5 million adjustment recorded in the second quarter of 2011 related to Newman Unit 5 pre-commercial testing, and (ii) decreased costs of purchased power of $1.8 million due to a 15.1% decrease in the MWhs purchased partially offset by a 4.9% increase in the average market price for power. These decreases were partially offset by increased nuclear fuel costs of $2.8 million due to an 18.1% increase in the cost of nuclear fuel consumed and a 7.4% increase in MWhs generated with nuclear fuel. The table below details the sources and costs of energy for the three months ended June 30, 2012 and 2011.



	Three Months Ended June 30,
	2012					2011
Fuel Type	Cost		MWh	Cost per MWh		Cost		MWh	Cost per MWh
	(in thousands)					(in thousands)
Natural gas (a)	$	33,353	1,131,670	$	29.47	$	47,839	856,448	$	51.79
Coal	2,788		128,214	21.74		3,053		145,008	21.05
Nuclear	13,225		1,269,096	10.42		10,426		1,182,054	8.82
Total	49,366		2,528,980	19.52		61,318		2,183,510	26.49
Purchased power	14,522		423,752	34.27		16,297		499,040	32.66
Total energy	$	63,888	2,952,732	21.64		$	77,615	2,682,550	27.63

______________


(a)	Natural gas costs have been adjusted for energy expenses capitalized related to Newman Unit 5 phase II pre-commercial testing recorded in 2011.

Our energy expenses decreased $23.0 million or 16.5% for the six months ended June 30, 2012, when compared to 2011. The decrease was primarily due to decreased natural gas costs of $17.1 million primarily due to a 35.8% decrease in the average cost of natural gas. The decrease in natural gas costs was partially offset by a 14.9% increase in MWhs generated with natural gas and capitalizing $3.2 million of natural gas costs related to Newman Unit 5 pre-commercial testing in 2011. The decrease in energy expenses was also due to (i) a $7.7 million or 22.1% decrease in purchased power costs due to a 15.5% decrease in MWhs purchased and a 7.8% decrease in the average market price for power, and (ii) decreased coal costs of $1.9 million due to a $2.3 million adjustment recorded in 2011 for the amortization of final coal reclamation costs in accordance with the final order in PUCT Docket No. 38361. These decreases were partially offset by increased nuclear fuel costs of $3.8 million, or 17.7% primarily due to a 15.9% increase in the price of nuclear fuel and a 1.5% increase in MWh generated by nuclear fuel. The subsequent table details the sources and costs of energy for the six month periods ended June 30, 2012 and 2011.



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	Six Months Ended June 30,
	2012					2011
Fuel Type	Cost		MWh	Cost per MWh		Cost		MWh	Cost per MWh
	(in thousands)					(in thousands)
Natural gas (a)	$	57,034	1,694,109	$	33.67	$	74,182	1,473,782	$	52.48
Coal (b)	6,488		321,697	20.17		8,416		311,979	19.49
Nuclear	25,278		2,550,276	9.91		21,479		2,511,861	8.55
Total	88,800		4,566,082	19.45		104,077		4,297,622	24.41
Purchased power	27,081		896,504	30.21		34,771		1,060,968	32.77
Total energy	$	115,881	5,462,586	21.21		$	138,848	5,358,590	26.07

______________


(a)	Natural gas costs have been adjusted for energy expenses capitalized related to Newman Unit 5 phase II pre-commercial testing recorded in 2011.


(b)	Coal costs include $2.3 million adjustment for final coal reclamation amortization in accordance with PUCT Docket No. 38361 recorded in 2011.

Our energy expenses decreased $6.7 million or 2.4% for the twelve months ended June 30, 2012, when compared to 2011, primarily due to (i) decreased purchased power costs of $10.8 million due to a 16.2% decrease in the MWhs purchased partially offset by a 2.9% increase in the average cost of purchased power, (ii) decreased natural gas costs of $3.9 million due to a 18.6% decrease in the average price of natural gas partially offset by a 17.2% increase in MWhs generated with natural gas and capitalizing $3.2 million of natural gas costs related to Newman Unit 5 pre-commercial testing in 2011, and (iii) decreased coal costs of $0.3 million due to a $2.3 million adjustment recorded in 2011 for the amortization of final coal reclamation costs in accordance with the final order in PUCT Docket No. 38361 partially offset by a 20.8% increase in the average cost of coal burned. These decreases were partially offset by increased nuclear fuel costs of $8.4 million primarily due to a 13.9% increase in the average cost of nuclear fuel and a $3.3 million DOE refund recorded in the fourth quarter of 2010 with no comparable activity in the current period. The table below details the sources and costs of energy for the twelve months ended June 30, 2012 and 2011.



	Twelve Months Ended June 30,
	2012					2011
Fuel Type	Cost		MWh	Cost per MWh		Cost		MWh	Cost per MWh
	(in thousands)					(in thousands)
Natural gas (a)	$	147,112	3,567,116	$	41.24	$	151,052	3,044,515	$	50.65
Coal (b)	13,345		657,650	20.29		13,658		674,181	16.80
Nuclear (c)	47,773		4,980,470	9.59		39,351		5,064,893	8.42
Total	208,230		9,205,236	22.62		204,061		8,783,589	23.70
Purchased power	67,459		1,948,132	34.63		78,288		2,326,094	33.66
Total energy	$	275,689	11,153,368	24.72		$	282,349	11,109,683	25.79

______________


(a)	Natural gas costs have been adjusted for energy expenses capitalized related to Newman Unit 5 phase II pre-commercial testing recorded in 2011.


(b)	Coal costs include $2.3 million adjustment for final coal reclamation amortization in accordance with PUCT Docket No. 38361 recorded in 2011.


(c)	Includes a DOE refund of $3.3 million for spent fuel storage costs recorded in the fourth quarter of 2010.

Other operations expense

Other operations expense increased $1.6 million, or 2.8% for the three months ended June 30, 2012, compared to the same period last year, primarily due to increased administrative and general expense of $1.3 million due to increased employee pension and benefits costs as a result of changes in actuarial assumptions used to calculate expenses for our pension and other postretirement benefits ("OPEB") plans. Other operations expense increased $1.9 million, or 1.7% for the six months ended June 30, 2012, compared to the same period last year, primarily due to increased administrative and general expense of $2.3 million due to increased employee pension and benefits costs as a result of changes in actuarial assumptions used to calculate expenses



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for our pension and OPEB plans partially offset by a $0.9 million decrease in the asset retirement obligation ("ARO") accretion expense. The ARO accretion expense decreased as a result of the Palo Verde license extension approved by the NRC in April 2011.

Other operations expense decreased $2.4 million, or 1.0% for the twelve months ended June 30, 2012, compared to the same period last year. The decrease is primarily due to (i) a $2.9 million decrease in the ARO accretion expense reflecting the Palo Verde license extension approved by the NRC in April 2011, (ii) decreased administrative and general expense primarily due to decreased outside services partially offset by increased employee pension and benefits costs as a result of changes in actuarial assumptions used to calculate expenses for our pension and OPEB plans, and (iii) decreased operations expense at Palo Verde. These decreases were partially offset by increased transmission operations expense of $1.0 million primarily due to increased wheeling expense.

Maintenance expense

Maintenance expense decreased $2.0 million, or 11.7%, for the three months ended June 30, 2012 compared to the same period last year, primarily due to the timing of the Palo Verde Unit 3 2012 spring refueling outage. The Palo Verde Unit 3 spring refueling outage began on March 17, 2012 and was completed by April 17, 2012. The 2011 Palo Verde Unit 2 spring refueling outage began on April 2, 2011 and was completed May 6, 2011. Maintenance expense increased $1.8 million, or 6.1%, for the six months ended June 30, 2012 due to the timing of planned maintenance at our gas-fired generating plants partially offset by decreased maintenance expense related to the 2012 spring refueling outage at Palo Verde. The 2012 spring refueling outage was performed at a reduced cost when compared to the 2011 spring refueling outage. Maintenance expense increased $8.3 million, or 14.9% for the twelve months ended June 30, 2012 compared to the same period last year primarily due to the timing of planned maintenance and freeze protection upgrades at our gas-fired generating plants partially offset by decreased maintenance expense related to spring refueling outages at Palo Verde as previously mentioned.

Depreciation and amortization expense

Depreciation and amortization expense increased $0.1 million for the three months ended June 30, 2012 due to increased depreciable plant balances offset by reduced depreciation rates for our gas-fired generation plant and our transmission and distribution plant. The recently approved Texas rate settlement allowed for the reduced depreciation rates associated with the gas-fired generating units and for transmission and distribution plant effective May 1, 2012. Depreciation and amortization expense decreased $0.3 million and $1.0 million, or 0.8% and 1.3%, for the six and twelve months ended June 30, 2012 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 including the completion of Phase II of Newman Unit 5 in April 2011.

Taxes other than income taxes

Taxes other than income taxes increased $1.3 million, $1.8 million and $1.3 million, or 9.4%, 6.7% and 2.2% for the three, six and twelve months ended June 30, 2012, compared to the same periods last year, primarily due an increase in billed revenues, taxable property and property tax rates.

Other income (deductions)

Other income (deductions) decreased $0.9 million for the three months ended June 30, 2012, compared to the same period last year, primarily due to realized losses on equity investments in our decommissioning trust of $1.4 million partially offset by increased allowance for equity funds used during construction (“AEFUDC”) resulting from higher balances of construction work in progress. Other income (deductions) decreased $2.5 million and $6.8 million for the six and twelve months ended June 30, 2012, compared to same periods last year, due to net unrealized and realized losses on equity investments in our decommissioning trust of $1.4 million and $3.3 million, and decreased AEFUDC as a result of lower balances of construction work in progress reflecting the completion of Newman Unit 5 in April 2011.

Interest charges (credits)

Interest charges (credits) remained unchanged for the three months ended June 30, 2012 when compared to the same period last year. Interest charges (credits) increased $0.5 million and $2.6 million, or 2.4% and 6.1%, for the six and twelve months ended June 30, 2012, compared to the same periods last year, primarily due to decreased allowance for borrowed funds used during construction ("ABFUDC") as a result of lower balances of construction work in progress in the 2012 periods reflecting the completion of Newman Unit 5 in April 2011.



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Income tax expense

Income tax expense decreased by $0.4 million, or 2.2%, in the three months ended June 30, 2012 compared to the same period last year, primarily due to lower pre-tax income and a decrease in the interest reserve related to FIN 48 items offset by an increase in state income taxes and other permanent items. Income tax expense decreased by $1.6 million, or 8.5% in the six months ended June 30, 2012 compared to the same period last year, primarily due to a decrease in pre-tax income offset by an increase in permanent items. Income tax expense, before extraordinary item, increased by $6.0 million, or 13.0%, in the twelve months ended June 30, 2012 compared to 2011 primarily due to increased pre-tax income, decreased non-taxable AEFUDC and decreased permanent items.

Extraordinary Item

As a regulated electric utility, we prepare our financial statements in accordance with the FASB guidance for regulated operations. FASB guidance for regulated operations requires us to show certain items as assets or liabilities on our balance sheet when the regulator provides assurance that these items will be charged to and collected from our customers or refunded to our customers. In the final order for PUCT Docket No. 37690, we were allowed to include the previously expensed loss on reacquired debt associated with the refinancing of first mortgage bonds in 2005 in our calculation of the weighted cost of debt to be recovered from our customers. We recorded the impacts of the re-application of FASB guidance for regulated operations to our Texas jurisdiction in 2006 as an extraordinary item. In order to establish this regulatory asset, we recorded an extraordinary gain of $10.3 million, net of income tax expense of $5.8 million, in our statements of operations for the quarter ended September 30, 2010. This item was recorded as a regulatory asset at September 30, 2010 pursuant to the final order received from the PUCT and will be amortized over the remaining life of our 6% Senior Notes due in 2035.

New Accounting Standards

In 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 required 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 would have been 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, we used the consecutive two-statement approach; however, this new guidance would have required additional disclosure on our statement of operations and related notes. In December 2011, the FASB issued new guidance to defer the effective date for amendments to the presentation of reclassification of items out of accumulated other comprehensive income. Deferring the effective date will allow the FASB time to redeliberate whether to present on the face of the financial statements the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income for all periods presented. While the FASB is considering the operational concerns about the presentation requirements for reclassification adjustments and the needs of financial statement users for additional information about reclassification adjustments, we will continue to report reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect before the guidance issued in June 2011 until further guidance becomes available.

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.



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Liquidity and Capital Resources

We continue to maintain a strong balance of common stock equity in our capital structure which supports our bond ratings, allowing us to obtain financing from the capital markets at a reasonable cost. At June 30, 2012, our capital structure, including common stock, long-term debt and current maturities of long-term debt, and short-term borrowings under the revolving credit facility, consisted of 44.9% common stock equity and 55.1% debt. At June 30, 2012, we had on hand $10.1 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.

On April 17, 2012, the Council approved the settlement of our 2012 Texas retail rate case in PUCT Docket No. 40094. For Texas service areas outside of the city limits of El Paso, the settlement was filed with the PUCT, and the PUCT approved the settlement, on May 18, 2012. In the settlement, we agreed to a reduction in our non-fuel base rates of $15 million annually, with the decrease being allocated primarily to Texas commercial and industrial customer classes. The rate decrease was effective May 1, 2012, and we anticipate approximately $8.6 million in reduced base revenues for the remaining six months of 2012 as a result of these lower rates. As part of the settlement we have agreed to withdraw our request to reconcile fuel costs for the period from July 1, 2009 through September 30, 2011.

On April 12, 2012, we filed with the PUCT a request to reduce our fixed fuel factor charged to Texas retail customers. The fixed fuel factor is based upon a formula that reflects current costs of fuel for changes in prices for natural gas and the revision reflects recent declines in prices for natural gas. The expected impact of the reduction in the fuel factor will be a reduction in annual fuel revenues of approximately $30 million. On April 25, 2012, the administrative law judge issued an order approving a new fuel factor effective May 1, 2012.

Capital Requirements. During the six months ended June 30, 2012, our capital requirements primarily consisted of expenditures for the construction and purchase of electric utility plant, purchases of nuclear fuel, and payment of 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. We are constructing Rio Grande Unit 9, an aeroderivative gas turbine unit with a net dependable generating capacity of 87 MW that should reach commercial operation by May 2013, at an estimated cost of approximately $83.9 million. As of June 30, 2012, we had expended $59.8 million on Rio Grande Unit 9, including $22.6 million during 2012. These amounts included AFUDC. Estimated cash construction expenditures for all capital projects for 2012 are approximately $232 million, excluding AFUDC, and we expect cash from operations and short-term borrowings from our revolving credit facility to continue to be a primary source of funds for these capital expenditures. In addition, we may issue long-term debt in the form of senior notes in late 2012 or early 2013 to repay short-term borrowings and for future construction of electric plant. See Part I, Item 1, “Business - Construction Program” in our 2011 Form 10-K. Cash capital expenditures for new electric plant were $99.9 million in the six months ended June 30, 2012 compared to $87.0 million in the six months ended June 30, 2011. Capital requirements for purchases of nuclear fuel were $38.2 million for the six months ended June 30, 2012 compared to $24.1 million for the six months ended June 30, 2011.

On June 29, 2012, we paid $10.0 million of quarterly dividends to shareholders. We have paid a total of $18.8 million in cash dividends during the six months ended June 30, 2012. At the current dividend rate, we would expect to pay cash dividends of approximately $38.9 million during 2012. In addition, while we do not currently anticipate repurchasing shares in 2012, 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 25.4 million shares of common stock at an aggregate cost of $423.6 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. No shares of common stock were repurchased during the six months ended June 30, 2012. As of June 30, 2012, a total of 393,816 shares remain eligible for purchase.

We will continue to maintain a prudent level of liquidity as well as take market conditions for debt and equity securities into account. With the initiation of a dividend in early 2011, we are moving toward primarily utilizing the dividend to maintain a balanced capital structure, supplemented by share repurchases when appropriate. Our liquidity needs can fluctuate quickly based on fuel prices and other factors and we are continuing to make investments in new electric plant and other assets in order to reliably serve our customers. In light of these factors, we expect it will be a number of years before we achieve a dividend payout equivalent to industry average.

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 and net operating loss carryforwards, tax payments are expected to be minimal in 2012.



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We continually evaluate our funding requirements related to our retirement plans, other postretirement benefit plans, and decommissioning trust funds. We contributed $11.5 million of the projected $19.8 million 2012 annual contribution to our retirement plans during the six months ended June 30, 2012. In the six months ended June 30, 2012, we contributed $0.6 million of the projected $2.5 million 2012 annual contribution to our OPEB plan, and $2.3 million of the projected $4.6 million 2012 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. 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 at least four months after our last revision except in the month of December based upon our approved formula which allows us to adjust fuel rates to reflect changes in costs of natural gas.

During the six months ended June 30, 2012, we had increased cash from operations when compared to the same period in 2011 due primarily to the increased collection of deferred fuel revenues in 2012. During the six months ended June 30, 2012, we had an over-recovery of fuel costs, net of refunds, of $15.6 million, compared to an under-recovery, net of refunds, of $25.8 million during the six months ended June 30, 2011. At June 30, 2012, we had a net fuel over-recovery balance of $8.6 million, including $6.7 million in Texas, $1.8 million in New Mexico, and $0.1 million in FERC. A filing to refund over-recovered fuel costs in Texas was made in early August 2012.

We maintain a revolving credit facility (“RCF”) for working capital and general corporate purposes 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 RCF has a term ending in September 2016. On March 29, 2012, the Company increased the aggregate unsecured borrowing available under the RCF from $200 million to $300 million. The terms of the agreement provide that amounts we borrow under the RCF may be used for working capital and general corporate purposes. The total amount borrowed for nuclear fuel by RGRT was $144.8 million at June 30, 2012, of which $34.8 million had been borrowed under the RCF and $110 million was borrowed through senior notes. At June 30, 2011, the total amounts borrowed for nuclear fuel by RGRT was $123.6 million of which $13.6 million was borrowed under the revolving credit facility and $110 million was borrowed through senior notes. 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. At June 30, 2012, $76.0 million was outstanding under the RCF for working capital or general corporate purposes and at June 30, 2011 $26.0 million was outstanding under the RCF for working capital or general corporate purposes.

We currently have one series of tax exempt unsecured pollution control bonds (“PCBs”) in aggregate principal amount of $33.3 million which is shown as current maturities of long-term debt on the Company's June 30, 2012 and December 31, 2011 balance sheets. On August 1, 2012, we completed a refunding transaction where we purchased these PCBs. We also anticipate purchasing our 4.80% 2005 Series A refunding PCBs in a principal amount of $59.2 million in the third quarter of 2012. We may remarket both series of PCBs at a future date depending on financing needs and market conditions.

We believe we have adequate liquidity through our current cash balances, cash from operations, and our revolving credit facility to meet all of our anticipated cash requirements through 2012. In addition, we may issue long-term debt in the form of senior notes in late 2012 or early 2013 to repay short-term borrowings and for future construction of electric plant.

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 2011 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, 2012, there have been no material changes in the market risks we face or the fair values of assets and liabilities disclosed in Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” in our 2011 Annual Report Form 10-K.


Item 4.	Controls and Procedures

Evaluation of disclosure controls and procedures. Under the supervision and with the participation of our management,



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including our chief executive officer and our chief financial officer, we conducted an evaluation pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934 of our disclosure controls and procedures as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934. Based on that evaluation, our chief executive officer and our chief financial officer concluded that, as of June 30, 2012, 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, 2012, that materially affected, or that were reasonably likely to materially affect, our internal control over financial reporting.



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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 2011 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, 2012	—	$	—	—	393,816
May 1 to May 31, 2012	—	—		—	393,816
June 1 to June 30, 2012	—	—		—	393,816


Item 6.	Exhibits

See Index to Exhibits incorporated herein by reference.



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SIGNATURES

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




	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 3, 2012



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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			Separation Agreement between the Company and Richard G. Fleager, dated April 2, 2012.

10.05			Employment Agreement between the Company and Thomas V. Shockley, dated June 1, 2012.
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, four agreements, dated as of July 1, 2012, substantially identical in all material respects to this Exhibit, have been entered into with Catherine A. Allen; Kenneth R. Heitz; Patricia Z. Holland-Branch; and Stephen N. Wertheimer; directors of the Company.

	In lieu of non-employee director cash compensation, ten agreements, dated as of May 31, 2012, 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; Eric B. Siegel; Stephen N. Wertheimer; and Charles A. Yamarone; directors of the Company.



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