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 September 30, 2012

EE 2012.9.30 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 September 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 October 31, 2012, there were 40,117,155 shares of the Company’s no par value common stock outstanding.

Table of Contents

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

INDEX TO FORM 10-Q



		Page No.
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
Consolidated Balance Sheets – September 30, 2012 and December 31, 2011		1
Consolidated Statements of Operations – Three Months, Nine Months and Twelve Months Ended September 30, 2012 and 2011		3
Consolidated Statements of Comprehensive Operations – Three Months, Nine Months and Twelve Months Ended September 30, 2012 and 2011		5
Consolidated Statements of Cash Flows – Nine Months Ended September 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	41
Item 4.	Controls and Procedures	42
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43
Item 6.	Exhibits	43



	(i)

Table of Contents

PART I. FINANCIAL INFORMATION


Item 1.	Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS



	September 30, 2012			December 31, 2011
	(Unaudited)

ASSETS (In thousands)
Utility plant:
Electric plant in service	$	2,821,451		$	2,789,773
Less accumulated depreciation and amortization	(1,144,265		)	(1,121,653		)
Net plant in service	1,677,186			1,668,120
Construction work in progress	245,416			167,394
Nuclear fuel; includes fuel in process of $51,472 and $49,545, respectively	205,902			171,433
Less accumulated amortization	(82,109		)	(59,882		)
Net nuclear fuel	123,793			111,551
Net utility plant	2,046,395			1,947,065
Current assets:
Cash and cash equivalents	8,664			8,208
Accounts receivable, principally trade, net of allowance for doubtful accounts of $3,110 and $3,015, respectively	98,455			76,348
Accumulated deferred income taxes	17,959			13,752
Inventories, at cost	43,500			40,222
Income taxes receivable	861			2,269
Undercollection of fuel revenues	—			9,130
Prepayments and other	6,406			4,810
Total current assets	175,845			154,739
Deferred charges and other assets:
Decommissioning trust funds	186,724			167,963
Regulatory assets	103,446			101,027
Other	30,508			26,057
Total deferred charges and other assets	320,678			295,047
Total assets	$	2,542,918		$	2,396,851

See accompanying notes to consolidated financial statements.



	1

Table of Contents

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS (Continued)



	September 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, 65,505,583 and 65,295,888 shares issued, and 103,709 and 156,185 restricted shares, respectively	$	65,609		$	65,452
Capital in excess of stated value	309,007			309,777
Retained earnings	944,340			887,174
Accumulated other comprehensive loss, net of tax	(64,035		)	(77,505		)
	1,254,921			1,184,898
Treasury stock, 25,492,919 shares at cost	(424,647		)	(424,647		)
Common stock equity	830,274			760,251
Long-term debt	849,838			816,497
Total capitalization	1,680,112			1,576,748
Current liabilities:
Current maturities of long-term debt	—			33,300
Short-term borrowings under the revolving credit facility	61,542			33,379
Accounts payable, principally trade	38,247			51,704
Taxes accrued	29,829			30,700
Interest accrued	12,592			12,123
Overcollection of fuel revenues	6,969			2,105
Other	25,120			21,921
Total current liabilities	174,299			185,232
Deferred credits and other liabilities:
Accumulated deferred income taxes	358,286			299,475
Accrued pension liability	119,138			129,627
Accrued postretirement benefit liability	104,842			100,455
Asset retirement obligation	59,572			56,140
Regulatory liabilities	21,830			21,049
Other	24,839			28,125
Total deferred credits and other liabilities	688,507			634,871
Commitments and contingencies
Total capitalization and liabilities	$	2,542,918		$	2,396,851

See accompanying notes to consolidated financial statements.



	2

Table of Contents

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands except for share data)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Operating revenues	$	267,249		$	307,633		$	664,079		$	726,350
Energy expenses:
Fuel	56,332			73,034			145,132			177,111
Purchased and interchanged power	16,223			25,845			43,304			60,616
	72,555			98,879			188,436			237,727
Operating revenues net of energy expenses	194,694			208,754			475,643			488,623
Other operating expenses:
Other operations	60,906			56,832			174,128			168,148
Maintenance	12,831			12,764			43,605			41,760
Depreciation and amortization	19,208			20,315			59,329			60,775
Taxes other than income taxes	15,353			16,628			43,631			43,131
	108,298			106,539			320,693			313,814
Operating income	86,396			102,215			154,950			174,809
Other income (deductions):
Allowance for equity funds used during construction	2,419			1,379			6,589			6,441
Investment and interest income, net	1,833			618			3,711			4,593
Miscellaneous non-operating income	1,182			113			1,383			384
Miscellaneous non-operating deductions	(591		)	(648		)	(1,494		)	(2,061		)
	4,843			1,462			10,189			9,357
Interest charges (credits):
Interest on long-term debt and revolving credit facility	13,659			13,571			40,827			40,595
Other interest	387			243			865			777
Capitalized interest	(1,324		)	(1,318		)	(3,992		)	(3,864		)
Allowance for borrowed funds used during construction	(1,431		)	(808		)	(3,894		)	(3,837		)
	11,291			11,688			33,806			33,671
Income before income taxes	79,948			91,989			131,333			150,495
Income tax expense	28,159			33,668			45,306			52,409
Net income	$	51,789		$	58,321		$	86,027		$	98,086

Basic earnings per share	$	1.29		$	1.41		$	2.15		$	2.33

Diluted earnings per share	$	1.29		$	1.40		$	2.14		$	2.32

Dividends declared per share of common stock	$	0.25		$	0.22		$	0.72		$	0.44
Weighted average number of shares outstanding	40,009,866			41,307,632			39,959,866			41,819,428
Weighted average number of shares and dilutive potential shares outstanding	40,091,625			41,564,973			40,044,154			42,051,307

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
	September 30,
	2012			2011
Operating revenues	$	855,742		$	907,694
Energy expenses:
Fuel	191,528			216,801
Purchased and interchanged power	57,837			75,904
	249,365			292,705
Operating revenues net of energy expenses	606,377			614,989
Other operating expenses:
Other operations	235,550			230,803
Maintenance	63,937			57,361
Depreciation and amortization	79,885			81,650
Taxes other than income taxes	56,061			56,582
	435,433			426,396
Operating income	170,944			188,593
Other income (deductions):
Allowance for equity funds used during construction	8,309			9,612
Investment and interest income, net	4,782			6,619
Miscellaneous non-operating income	1,884			1,351
Miscellaneous non-operating deductions	(2,620		)	(3,990		)
	12,355			13,592
Interest charges (credits):
Interest on long-term debt and revolving credit facility	54,347			54,043
Other interest	1,077			918
Capitalized interest	(5,305		)	(5,069		)
Allowance for borrowed funds used during construction	(4,905		)	(5,857		)
	45,214			44,035
Income before income taxes	138,085			158,150
Income tax expense	46,605			52,599
Net income	$	91,480		$	105,551

Basic earnings per share	$	2.28		$	2.50

Diluted earnings per share	$	2.27		$	2.49

Dividends declared per share of common stock	$	0.94		$	0.44
Weighted average number of shares outstanding	39,959,034			41,969,628
Weighted average number of shares and dilutive potential shares outstanding	40,085,516			42,207,012

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						Nine Months Ended						Twelve Months Ended
	September 30,						September 30,						September 30,
	2012			2011			2012			2011			2012			2011
Net income	$	51,789		$	58,321		$	86,027		$	98,086		$	91,480		$	105,551
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	(1,441		)	(1,453		)	(4,321		)	(4,358		)	(5,775		)	(5,047		)
Net loss	2,993			1,625			8,978			4,878			10,605			5,722
Net unrealized gains (losses) on marketable securities:
Net holding gains (losses) arising during period	6,169			(7,503		)	11,986			(4,914		)	18,470			(1,290		)
Reclassification adjustments for net (gains) losses included in net income	(318		)	1,284			916			1,081			1,193			601
Net losses on cash flow hedges:
Reclassification adjustment for interest expense included in net income	97			93			286			269			378			355
Total other comprehensive income (loss) before income taxes	7,500			(5,954		)	17,845			(3,044		)	(52,807		)	17,072
Income tax benefit (expense) related to items of other comprehensive income (loss):
Unrecognized pension and postretirement benefit costs	(591		)	(65		)	(1,687		)	(196		)	28,643			(6,314		)
Net unrealized gains (losses) on marketable securities	(1,201		)	1,171			(2,571		)	654			(3,788		)	26
Losses on cash flow hedges	(36		)	(35		)	(117		)	(101		)	(219		)	(132		)
Total income tax benefit (expense)	(1,828		)	1,071			(4,375		)	357			24,636			(6,420		)
Other comprehensive income (loss), net of tax	5,672			(4,883		)	13,470			(2,687		)	(28,171		)	10,652
Comprehensive income	$	57,461		$	53,438		$	99,497		$	95,399		$	63,309		$	116,203

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)



	Nine Months Ended
	September 30,
	2012			2011
Cash flows from operating activities:
Net income	$	86,027		$	98,086
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service	59,329			60,775
Amortization of nuclear fuel	33,278			28,004
Deferred income taxes, net	43,818			46,338
Allowance for equity funds used during construction	(6,589		)	(6,441		)
Other amortization and accretion	10,904			15,771
Gain on sale of assets	(1,346		)	(110		)
Other operating activities	782			1,214
Change in:
Accounts receivable	(22,107		)	(43,710		)
Inventories	(2,400		)	(3,367		)
Net overcollection (undercollection) of fuel revenues	13,994			(29,608		)
Prepayments and other	(3,443		)	(4,718		)
Accounts payable	(6,757		)	9,500
Taxes accrued	537			13,265
Interest accrued	469			1,078
Other current liabilities	3,199			(1,279		)
Deferred charges and credits	(7,896		)	(5,923		)
Net cash provided by operating activities	201,799			178,875
Cash flows from investing activities:
Cash additions to utility property, plant and equipment	(144,576		)	(129,651		)
Cash additions to nuclear fuel	(41,747		)	(33,925		)
Capitalized interest and AFUDC:
Utility property, plant and equipment	(10,483		)	(10,278		)
Nuclear fuel	(3,992		)	(3,864		)
Allowance for equity funds used during construction	6,589			6,441
Decommissioning trust funds:
Purchases, including funding of $3.4 and $6.4 million, respectively	(80,870		)	(77,314		)
Sales and maturities	74,095			67,841
Proceeds from sale of assets	1,757			129
Other investing activities	1,524			507
Net cash used for investing activities	(197,703		)	(180,114		)
Cash flows from financing activities:
Repurchases of common stock	—			(64,783		)
Dividends paid	(28,861		)	(18,415		)
Borrowings under the revolving credit facility:
Proceeds	204,373			88,723
Payments	(176,210		)	(75,634		)
Pollution control bonds:
Proceeds	92,535			—
Payments	(92,535		)	—
Other financing activities	(2,942		)	(92		)
Net cash used for financing activities	(3,640		)	(70,201		)
Net increase (decrease) in cash and cash equivalents	456			(71,440		)
Cash and cash equivalents at beginning of period	8,208			79,184
Cash and cash equivalents at end of period	$	8,664		$	7,744

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 September 30, 2012 and December 31, 2011; the results of its operations and comprehensive operations for the three, nine and twelve months ended September 30, 2012 and 2011; and its cash flows for the nine months ended September 30, 2012 and 2011. The results of operations and comprehensive operations for the three and nine months ended September 30, 2012 and the cash flows for the nine months ended September 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 $21.2 million and $19.6 million at September 30, 2012 and December 31, 2011, respectively. The Company presents revenues net of sales taxes in its consolidated statements of operations.



Supplemental Cash Flow Disclosures (in thousands)
	Nine Months Ended
	September 30,
	2012		2011
Cash paid for:
Interest on long-term debt and borrowing under the revolving credit facility	$	35,922	$	34,234
Income taxes paid (refunded), net	3,834		(3,031		)
Non-cash financing activities:
Grants of restricted shares of common stock	2,384		3,231
Issuance of performance shares	1,193		628
Acquisition of treasury stock for options exercised	—		500
Unsettled repurchases of common stock	—		12,491



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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. After reconsideration of its presentation requirements for reclassification, the FASB issued in August 2012, an exposure draft related to the presentation of items reclassified out of accumulated other comprehensive income. The exposure draft proposes that entities present separately in the notes tabular information about items that are reclassified out of each component of accumulated other comprehensive income and, for those items reclassified in their entirety into net income, the net income line item affected by the reclassification. The comment deadline was October 15, 2012. 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 the then 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.



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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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


•	A reduction in its 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 include an Economic Development Rate Rider that provides discounts in the demand charge 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 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. In 2010, 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 Authorized (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

September 28, 2012

January 2011- June 2012

September 2012

6,600



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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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

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. The administrative law judge issued a proposal for decision on September 28, 2012 that recommended approval of the CCN. Oral argument was heard at the PUCT's October 25, 2012 open meeting, and the PUCT is expected to consider the case again by the end 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 October 25, 2012, the Company filed an unopposed stipulation and settlement that resolves all matters in this proceeding. The State Office of Administrative Hearings returned the case to the PUCT for its consideration of the stipulation. It is anticipated that the PUCT will consider the case by the end of 2012.

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-recovered costs for 2011 result in a decrease in the currently effective EECRF. The PUCT entered an order adopting a Stipulation and Settlement Agreement on September 20, 2012 and the new factors will go into effect with January 2013 billings.

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. On October 5, 2012, the Company filed a Stipulation and Settlement, with the City of El Paso and Staff, which provides for the surcharge to be increased from 0.936% to 1.055% beginning with December 2012 billing. The revised MBDRF is designed to recover estimated discounts, with the recovery of past under-recoveries spread over two years. A final order in this case is expected to be issued by the end of 2012.

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 review by the NMPRC 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



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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, 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. On September 13, 2012, the Hearing Examiner issued a decision recommending modification of the Partial Stipulation to disallow the stipulated adders for recovery of regulatory disincentives for 2012 and 2013. The Company and an intervenor filed exceptions to the recommended decision on September 26, 2012. 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 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 NMPRC Staff filed testimony recommending approval of the application. A hearing was held on August 30, 2012 and a final order is expected in November 2012.

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 ("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, 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 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 Administrative 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 plans to meet 2013 and 2014 total RPS and diversity requirements with a combination of previously approved resources and new procurement. New procurement, in the form of biogas contracts, is required in order to meet diversity requirements for biogas/biomass. The NMPRC Staff and one intervenor, Coalition for Clean Affordable Energy, filed testimony on September 11, 2012, and the Company filed rebuttal testimony on October 2, 2012. The NMPRC Staff contends that the cost of the Company's proposed new biogas contracts is excessive and that the Company should not be authorized to make such purchases because they cause the total cost of the Company's plan to exceed the Reasonable Cost Threshold ("RCT") as calculated by the NMPRC Staff. The Company's calculation of the RCT supports these resources. Hearings were held in October 2012 on the Renewable Procurement Plan. While the Company would be able to satisfy total RPS requirements without the procurement in question, if the NMPRC Staff's position is upheld and the contracts are not authorized, the Company would require a waiver from its diversity requirement.



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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. No party opposed the filed IRP and the NMPRC issued a final order approving the IRP on August 28, 2012.

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.

On August 28, 2012, the Company completed a refunding transaction related to its 2005 Series A refunding PCBs totaling $59.2 million in which new PCBs totaling $59.2 million were issued at a fixed rate of 4.50%. The bonds are unsecured and will mature in 2042. On August 28, 2012, the Company also completed a remarketing transaction related to its 2002 Series A refunding PCBs totaling $33.3 million in which new PCBs totaling $33.3 million were issued at a fixed rate of 1.875%. The bonds were unsecured and mature in 2032 although they are required to be remarketed in 2017.

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 of approximately $0.6 million. 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.

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.



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D. Common Stock

Repurchase Program. No shares of common stocks were repurchased during the first nine 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 October 23, 2012, the Board of Directors declared a quarterly cash dividend of $0.25 per share payable on December 28, 2012 to shareholders of record on December 13, 2012. The Company paid $10.0 million and $9.2 million in cash dividends during the three months ended September 30, 2012 and September 30, 2011, respectively. The Company paid a total of $28.9 million and $37.7 million in cash dividends during the nine and twelve months ended September 30, 2012, respectively. The Company paid a total of $18.4 million in cash dividends during the nine and twelve months ended September 30, 2011.



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 September 30,
	2012			2011
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	40,009,866			41,307,632
Dilutive effect of unvested performance awards	71,849			231,230
Dilutive effect of stock options	9,910			26,111
Diluted number of common shares outstanding	40,091,625			41,564,973
Basic net income per common share:
Net income	$	51,789		$	58,321
Income allocated to participating restricted stock	(134		)	(275		)
Net income available to common shareholders	$	51,655		$	58,046
Diluted net income per common share:
Net income	$	51,789		$	58,321
Income reallocated to participating restricted stock	(134		)	(273		)
Net income available to common shareholders	$	51,655		$	58,048
Basic net income per common share:
Distributed earnings	$	0.25		$	0.22
Undistributed earnings	1.04			1.19
Basic net income per common share	$	1.29		$	1.41
Diluted net income per common share:
Distributed earnings	$	0.25		$	0.22
Undistributed earnings	1.04			1.18
Diluted net income per common share	$	1.29		$	1.40



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	Nine Months Ended September 30,
	2012			2011
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	39,959,866			41,819,428
Dilutive effect of unvested performance awards	67,583			198,578
Dilutive effect of stock options	16,705			33,301
Diluted number of common shares outstanding	40,044,154			42,051,307
Basic net income per common share:
Net income	$	86,027		$	98,086
Income allocated to participating restricted stock	(257		)	(447		)
Net income available to common shareholders	$	85,770		$	97,639
Diluted net income per common share:
Net income	$	86,027		$	98,086
Income reallocated to participating restricted stock	(257		)	(445		)
Net income available to common shareholders	$	85,770		$	97,641
Basic net income per common share:
Distributed earnings	$	0.72		$	0.44
Undistributed earnings	1.43			1.89
Basic net income per common share	$	2.15		$	2.33
Diluted net income per common share:
Distributed earnings	$	0.72		$	0.44
Undistributed earnings	1.42			1.88
Diluted net income per common share	$	2.14		$	2.32




	Twelve Months Ended September 30,
	2012			2011
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	39,959,034			41,969,628
Dilutive effect of unvested performance awards	108,411			192,994
Dilutive effect of stock options	18,071			44,390
Diluted number of common shares outstanding	40,085,516			42,207,012
Basic net income per common share:
Net income	$	91,480		$	105,551
Income allocated to participating restricted stock	(304		)	(461		)
Net income available to common shareholders	$	91,176		$	105,090
Diluted net income per common share:
Net income	$	91,480		$	105,551
Income reallocated to participating restricted stock	(304		)	(459		)
Net income available to common shareholders	$	91,176		$	105,092
Basic net income per common share:
Distributed earnings	$	0.94		$	0.44
Undistributed earnings	1.34			2.06
Basic net income per common share	$	2.28		$	2.50
Diluted net income per common share:
Distributed earnings	$	0.94		$	0.44
Undistributed earnings	1.33			2.05
Diluted net income per common share	$	2.27		$	2.49



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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		Nine Months Ended		Twelve Months Ended
	September 30,		September 30,		September 30,
	2012	2011	2012	2011	2012	2011
Restricted stock awards	46,632	90,358	46,178	84,691	52,768	83,091
Performance shares (a)	51,133	—	48,439	—	36,329	—
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 in 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 $139.5 million at September 30, 2012, of which $29.5 million had been borrowed under the RCF and $110 million was borrowed through senior notes. At 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 September 30, 2012, $32.0 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. The Company has four series of tax exempt unsecured PCBs in aggregate principal amount of $193.1 million. On August 1, 2012, the Company completed a refunding transaction where it purchased the 4.00% 2002 Series A PCBs with an aggregate principal amount of $33.3 million. On August 28, 2012, the Company completed a remarketing transaction and these PCBs will now (i) bear interest at an annual rate of 1.875%, (ii) mature on June 1, 2032, (iii) are unsecured obligations, and (iv) are not supported by any credit enhancement facility. These PCBs are subject to mandatory tender for purchase on September 1, 2017 at a purchase price equal to 100% of the principal amount plus accrued interest. The effective annual interest rate to the mandatory tender date is estimated to be 2.25% after considering related issuance costs.

On August 28, 2012, the Company also completed a refunding transaction related to the 4.80% 2005 Series A PCBs with an aggregate principal amount of $59.2 million. These PCBs will now (i) bear interest at an annual rate of 4.50%, (ii) will mature on August 1, 2042, (iii) are unsecured obligations, and (iv) are not supported by any credit enhancement facility. The effective annual interest rate is estimated to be 4.62% after considering related issuance costs.

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 2008 and in the state jurisdictions for years prior to 1998. The Company is currently under audit in the federal jurisdiction for tax years 2009 through 2012 and in Texas for 2007. A deficiency notice relating to the Company’s 1998 through 2003 and 2006 and 2007 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.



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For the three months ended September 30, 2012 and 2011, the Company’s consolidated effective tax rate was 35.2% and 36.6%, respectively. For the nine months ended September 30, 2012 and 2011, the Company's consolidated effective tax rate was 34.5% and 34.8%, respectively. For the twelve months ended September 30, 2012 and 2011, the Company's consolidated effective tax rate was 33.8% and 33.3%, respectively. The Company's consolidated effective tax rate for the three, nine and twelve months ended September 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 nine months ended September 30, 2012, a $1.8 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 September 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	400			1,800
Additions for tax positions of prior years	—			—
Reductions for tax positions of prior years	(1,800		)	—
Balance at September 30	$	8,100		$	9,100



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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 a ruling to stay the implementation of CSAPR. On August 21, 2012, a three-judge panel of the D.C. Circuit Court of Appeals vacated the CSAPR altogether. On October 5, 2012, the EPA filed a petition in the D.C. Circuit Court of Appeals seeking a rehearing by the entire court of the decision from the panel. EPA could also appeal the final decision to the U.S. Supreme Court; the Supreme Court could then hear the case and affirm, reverse, or modify the D.C. Circuit's holding. How, when, or whether that appeal might be accomplished remains uncertain. The Company is unable to determine what impact this ruling may ultimately have on its operations and consolidated financial results, but it could be material. Until any additional CSAPR legal issues are resolved, and/or until EPA re-writes a rule to replace CAIR, the Company's obligations under CAIR remain in effect.



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(Unaudited)

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, carbon monoxide ("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 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. 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 Company met its 2012 obligations under this rule by submitting its first mandatory SF6 emissions report by the September 28, 2012, due date.

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



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(Unaudited)

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. Several challenges are being made to this rule, including an August 2, 2012, letter request to EPA for withdrawal of the rule by a group of U.S. Senators. The potential 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.

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 September 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, nine and twelve months ended September 30, 2012 and 2011 to comply with federal environmental statutes (in thousands):



	Three Months Ended				Nine Months Ended				Twelve Months Ended
	September 30,				September 30,				September 30,
	2012		2011		2012		2011		2012		2011
Clean Air Act (1)	$	86	$	164	$	509	$	457	$	768	$	696
Clean Water Act	89		63		190		172		282		196

_________________

(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. APS, on behalf of all co-owners, responded to that request. 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. 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 in an effort to resolve the pending matters without the need for formal action. In March 2012, APS received a settlement communications letter from the DOJ along with a draft consent decree. The draft decree contains language stating that nothing in the decree may be construed as an admission of liability related to any of the alleged violations. The allegations



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(Unaudited)

being addressed through settlement negotiations are that APS failed to obtain the necessary permits and install the controls necessary under the CAA to reduce SO₂, NOx, and PM, and that Defendants failed to obtain an operating permit under Title V of the CAA that reflects applicable requirements imposed by law. The draft decree contained specific provisions for the reduction and control of NOx_,SO₂and PM. The proposed decree also contained provisions for a civil penalty, and expenditures on environmental mitigation projects with an emphasis on projects that address alleged harm to the Navajo Nation. Since the draft decree was tendered, the parties have negotiated towards the resolution of the matter. On October 5, 2012, APS sent the DOJ a counter proposal reflecting that APS has reached agreement with the DOJ on most terms and conditions, with the exception of the amount of the civil penalty and the environmental mitigation project; the parties remain at an impasse on these important issues. Specifically, the DOJ has offered little to no movement down from the high end of the amounts being discussed. 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 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. On April 2, 2012, APS and the other Four Corners participants filed motions to dismiss with the court. Earthjustice filed their response briefs on May 16, 2012. APS filed reply briefs on June 22, 2012. Utility Air Regulatory Group filed an amicus brief, and plaintiffs were allowed until July 23, 2012 to respond to that amicus brief. A ruling on the motions to dismiss is pending. 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, nine and twelve months ended September 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						Nine Months Ended						Twelve Months Ended
	September 30,						September 30,						September 30,
	2012			2011			2012			2011			2012			2011
Components of net periodic benefit cost:
Service cost	$	2,207		$	1,712		$	6,621		$	5,137		$	8,334		$	6,653
Interest cost	3,389			3,497			10,167			10,491			13,663			13,898
Amendments	—			—			—			—			—			838
Expected return on plan assets	(3,611		)	(3,523		)	(10,832		)	(10,571		)	(14,356		)	(14,038		)
Amortization of:
Net loss	2,839			1,636			8,517			4,908			10,153			5,796
Prior service cost	29			29			87			87			115			115
Net periodic benefit cost	$	4,853		$	3,351		$	14,560		$	10,052		$	17,909		$	13,262

During the nine months ended September 30, 2012, the Company contributed $16.4 million of its projected $19.8 million 2012 annual contribution to its retirement plans.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Other Postretirement Benefits

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



	Three Months Ended						Nine Months Ended						Twelve Months Ended
	September 30,						September 30,						September 30,
	2012			2011			2012			2011			2012			2011
Components of net periodic benefit cost:
Service cost	$	1,095		$	747		$	3,284		$	2,241		$	4,031		$	3,131
Interest cost	1,413			1,345			4,238			4,034			5,583			5,700
Expected return on plan assets	(397		)	(455		)	(1,285		)	(1,367		)	(1,741		)	(1,749		)
Amortization of:
Prior service benefit	(1,470		)	(1,482		)	(4,408		)	(4,445		)	(5,890		)	(5,162		)
Net loss (gain)	154			(11		)	461			(30		)	452			(74		)
Net periodic benefit cost	$	795		$	144		$	2,290		$	433		$	2,435		$	1,846

During the nine months ended September 30, 2012, the Company contributed $1.8 million of its projected $3.7 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):



	September 30, 2012				December 31, 2011
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Pollution Control Bonds	$	193,135	$	215,372	$	193,135	$	206,756
Senior Notes	546,703		687,315		546,662		700,371
RGRT Senior Notes (1)	110,000		121,190		110,000		116,985
RCF (1)	61,542		61,542		33,379		33,379
Total	$	911,380	$	1,085,419	$	883,176	$	1,057,491

_______________

(1)

Nuclear fuel financing as of September 30, 2012 and December 31, 2011 is funded through the $110 million RGRT Senior Notes and $29.5 million and $13.4 million, respectively under the RCF. As of September 30, 2012 and December 31, 2011, $32.0 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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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 $186.7 million and $168.0 million at September 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):



	September 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	$	100	$	(1	)	$	664	$	(14	)	$	764	$	(15	)
U.S. Government Bonds	5,771		(57		)	1,889		(52		)	7,660		(109		)
Municipal Obligations	1,412		(26		)	5,282		(225		)	6,694		(251		)
Corporate Obligations	472		(7		)	—		—			472		(7		)
Total Debt Securities	7,755		(91		)	7,835		(291		)	15,590		(382		)
Common Stock	2,263		(233		)	1,532		(349		)	3,795		(582		)
Total Temporarily Impaired Securities	$	10,018	$	(324	)	$	9,367	$	(640	)	$	19,385	$	(964	)

_________________


(1)	Includes approximately 44 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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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):



	September 30, 2012				December 31, 2011
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
Description of Securities:
Federal Agency Mortgage Backed Securities	$	20,543	$	1,241	$	25,077	$	1,220
U.S. Government Bonds	9,264		739		10,263		972
Municipal Obligations	34,980		1,869		30,310		1,792
Corporate Obligations	12,594		1,099		7,641		459
Total Debt Securities	77,381		4,948		73,291		4,443
Common Stock	75,355		25,028		62,479		15,681
Equity Mutual Funds	9,757		1,054		—		—
Cash and Cash Equivalents	4,846		—		3,739		—
Total	$	167,339	$	31,030	$	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 or more. The mortgage-backed securities have an estimated weighted average maturity which generally range from 3 years to 7 years and reflects anticipated future prepayments. The contractual year for maturity of these available-for-sale securities as of September 30, 2012 is as follows (in thousands):



	Total		2012		2013 through 2016		2017 through 2021		2022 and Beyond
Municipal Debt Obligations	$	41,674	$	400	$	10,564	$	19,697	$	11,013
Corporate Debt Obligations	13,066		—		3,324		6,011		3,731
U.S. Government Bonds	16,924		—		5,806		8,056		3,062

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, nine and twelve months ended months ended September 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					Nine Months Ended						Twelve Months Ended
	September 30,					September 30,						September 30,
	2012		2011			2012			2011			2012			2011
Gross unrealized holding losses included in pre-tax income	$	—	$	(1,547	)	$	(166	)	$	(1,746	)	$	(536	)	$	(1,746	)



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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						Nine Months Ended						Twelve Months Ended
	September 30,						September 30,						September 30,
	2012			2011			2012			2011			2012			2011
Proceeds from sales of available-for-sale securities	$	14,582		$	31,435		$	74,095		$	67,841		$	89,180		$	82,561
Gross realized gains included in pre-tax income	$	447		$	552		$	1,526		$	1,248		$	1,757		$	1,657
Gross realized losses included in pre-tax income	(129		)	(289		)	(2,276		)	(583		)	(2,414		)	(512		)
Gross unrealized losses included in pre-tax income	—			(1,547		)	(166		)	(1,746		)	(536		)	(1,746		)
Net gains (losses) in pre-tax income	$	318		$	(1,284	)	$	(916	)	$	(1,081	)	$	(1,193	)	$	(601	)
Net unrealized holding gains (losses) included in accumulated other comprehensive income	$	6,169		$	(7,503	)	$	11,986		$	(4,914	)	$	18,470		$	(1,290	)
Net (gains) losses reclassified out of accumulated other comprehensive income	(318		)	1,284			916			1,081			1,193			601
Net gains (losses) in other comprehensive income	$	5,851		$	(6,219	)	$	12,902		$	(3,833	)	$	19,663		$	(689	)

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 investment 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 investment 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The fair value of the Company’s decommissioning trust funds and investment in debt securities, at September 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 September 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:
Investment in Debt Securities	$	1,254	$	—	$	—	$	1,254
Available for sale:
U.S. Government Bonds	$	16,924	$	16,924	$	—	$	—
Federal Agency Mortgage Backed Securities	21,307		—		21,307		—
Municipal Bonds	41,674		—		41,674		—
Corporate Asset Backed Obligations	13,066		—		13,066		—
Subtotal Debt Securities	92,971		16,924		76,047		—
Common Stock	79,150		79,150		—		—
Equity Mutual Funds	9,757		9,757		—		—
Cash and Cash Equivalents	4,846		4,846		—		—
Total available for sale	$	186,724	$	110,677	$	76,047	$	—



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:
Investment 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, nine and twelve month periods ending September 30, 2012 and September 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 other income a gain on the sale of the debt security of $0.4 million during the twelve month period ending September 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, nine and twelve months ended September 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 September 30, 2012, the related consolidated statements of operations and comprehensive operations for the three-month, nine-month and twelve-month periods ended September 30, 2012 and 2011, and the related consolidated statements of cash flows for the nine-month periods ended September 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

November 2, 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,



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•	possible income tax and interest payments as a result of audit adjustments proposed by the IRS or state taxing authorities, and


•	other circumstances affecting anticipated operations, sales and costs.

These lists are not all-inclusive because it is not possible to predict all factors. A discussion of some of these factors is included in 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, nine and twelve month periods ended September 30, 2012 and 2011. Net income and basic earnings per share for the three, nine and twelve month periods ended September 30, 2012 and 2011 is shown below:



	Three Months Ended				Nine Months Ended				Twelve Months Ended
	September 30,				September 30,				September 30,
	2012		2011		2012		2011		2012		2011
Net income (in thousands)	$	51,789	$	58,321	$	86,027	$	98,086	$	91,480	$	105,551
Basic earnings per share	1.29		1.41		2.15		2.33		2.28		2.50

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



	Three Months Ended			Nine Months Ended			Twelve Months Ended
September 30, 2011 net income	$	58,321		$	98,086		$	105,551
Change in (net of tax):
Increased (decreased) allowance for funds used during construction (a)	1,432			184			(1,903		)
Increased (decreased) investment and interest income (b)	1,038			(528		)	(1,258		)
Increased miscellaneous non-operating income and deductions (c)	709			986			1,198
Decreased retail non-fuel base revenues (d)	(5,077		)	(3,736		)	(2,400		)
Decreased transmission revenues (e)	(2,326		)	(1,756		)	(1,533		)
Increased employee pensions and benefits expense (f)	(1,164		)	(2,716		)	(2,817		)
Decreased deregulated Palo Verde Unit 3 revenues (g)	(759		)	(2,867		)	(2,670		)
Increased operating and maintenance expense at fossil fuel generating plants (h)	(738		)	(2,845		)	(4,992		)
Decreased (increased) Palo Verde operations and maintenance expense (i)	(194		)	535			1,252
Other	547			684			1,052
September 30, 2012 net income	$	51,789		$	86,027		$	91,480

______________

(a)

Allowance for funds used during construction ("AFUDC") increased in the three and nine months ended September 30, 2012, compared to the same periods last year due to increased construction work in progress subject to AFUDC primarily reflecting construction work in progress on Rio Grande Unit 9 and the Montana Power Station in 2012. AFUDC decreased in the twelve months ended September 30, 2012 compared to the same period last year primarily due to lower balances of



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construction work in progress subject to AFUDC reflecting the completion and placing in service the Newman Unit 5 Phase II generating plant addition in April 2011.

(b)

Investment and interest income increased for the three months ended September 30, 2012, compared to the same period last year primarily due to impairments in our decommissioning trust investments recorded in the third quarter of 2011 with no comparable activity in the third quarter of 2012. The increase was partially offset by the $0.6 million of interest recorded in the three months ended September 30, 2011, related to the favorable settlement agreement with Tucson Electric Power Company resolving a transmission dispute. Investment and interest income decreased for the nine and twelve months ended September 30, 2012, compared to the same periods in 2011, primarily due to the $0.6 million of interest recorded in the three months ended September 2011 related to the favorable settlement agreement with Tucson Electric Power Company mentioned above, and $0.8 million of interest earned on a Texas deferred asset for energy efficiency costs recorded in first quarter of 2011 with no comparable activity in the current period. The decrease for the nine month period was partially offset by increased income earned on investments in our decommissioning trust.


(c)	Miscellaneous non-operating income and deductions increased for the three, nine, and twelve months ended September 30, 2012, compared to the same periods last year primarily due to a $1.1 million gain recognized on the sale of assets in the third quarter of 2012, with no comparable activity in the prior periods.

(d)

Retail non-fuel base revenues decreased for the three months ended September 30, 2012, compared to the same period in 2011, primarily due to a decrease in kWh sales to all customer classes reflecting hotter summer weather in 2011 and a reduction in non-fuel base rates for our Texas customers. Retail non-fuel base revenues decreased for the nine and twelve months ended September 30, 2012, compare to the same periods last year due to a decrease in non-fuel base revenues from sales to small commercial and industrial customers and large commercial and industrial customers due to a reduction in non-fuel base rates in Texas which became effective May 1, 2012, increased use of lower interruptible rates, and decreased consumption by several large commercial and industrial customers. 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)	Transmission wheeling revenues decreased for the three, nine, and twelve months ended September 30, 2012, compared to the same periods 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 $4.5 million, $4.1 million, and $3.9 million, pre-tax, respectively.


(f)	Employee pensions and benefits expense increased for the three, nine, and twelve months ended September 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.

(g)

Revenues from retail sales of deregulated Palo Verde Unit 3 power decreased for the three, nine, and twelve months ended September 30, 2012, compared to the same periods last year, due to lower proxy market prices due to the decline in natural gas prices, and increases in costs of nuclear fuel. The decrease for the nine month period also resulted from an 11% decrease in generation at Palo Verde Unit 3 due to a refueling outage beginning on March 17, 2012, which was completed on April 17, 2012.


(h)	Operations and maintenance expense increased at our fossil fuel generating plants for the three, nine, and twelve months ended September 30, 2012, when compared to the same periods last year, primarily due to the timing of maintenance of local gas-fired generation.


(i)	Palo Verde non-fuel operations and maintenance expense for the twelve months ended September 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.



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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. Residential and small commercial customers comprise 75% or more of our non-fuel base 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. 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. For the three, nine, and twelve months ended September 30, 2012, retail non-fuel base revenues were negatively impacted by cooler summer weather when compared to the same periods in 2011. For the three, nine, and twelve month periods ending September 30, 2012, cooling degree days decreased 16%, 10%, and 9% when compared to the same periods last year, respectively. The table below shows heating and cooling degree days compared to a 10-year average.



	Three Months Ended			Nine Months Ended			Twelve Months Ended
	September 30,		10-Year	September 30,		10-Year	September 30,		10-Year
	2012	2011	Average	2012	2011	Average	2012	2011	Average*
Heating degree days	6	—	1	1,215	1,305	1,277	2,312	2,100	2,273
Cooling degree days	1,497	1,787	1,477	2,712	2,997	2,514	2,850	3,128	2,615

______________

* Calendar year basis.

Customer growth is a key driver of the growth of retail sales. The average number of retail customers grew 1.1% for the three months ended September 30, 2012 and 1.4% for the nine and twelve months ended September 30, 2012 when compared to the same periods last year. See the tables presented on pages 33, 34 and 35 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 decreased $8.1 million, or 4.2% for the three months ended September 30, 2012, when compared to the same period last year due to a decrease in kWh sales in all customer classes reflecting a return to more normal weather. In 2011, our service territory experienced hotter than normal summer weather. Cooling degree days decreased 16.2% in the third quarter of 2012 compared to the same period in 2011 and were comparable to the 10-year average. Non-fuel base revenues from sales to small commercial and industrial customers and large commercial and industrial customers decreased 6.4% and 7.4%, respectively, in the third quarter primarily due to a reduction in non-fuel base rates in Texas which became effective 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 6.7% for the three month period. KWh sales to residential customers



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decreased 1.7% and non-fuel base revenues from residential customers decreased 2.6%. KWh sales to public authorities decreased 2.0% and non-fuel base revenues from public authorities decreased 2.4%.

Retail non-fuel base revenues decreased by $5.9 million, or 1.3%, for the nine months ended September 30, 2012, when compared to the same period last year. The decrease in revenues was primarily due to a reduction in non-fuel base rates to Texas customers which primarily impacted small and large commercial and industrial customers. Non-fuel base revenues from sales to small commercial and industrial customers and large commercial and industrial customers decreased 3.8% and 6.8%, respectively. In addition, increased use of lower interruptible rates rather than higher rates that are not interruptible, and decreased consumption by several large commercial and industrial customers contributed to the decrease in non-fuel base revenues. KWh sales to large commercial and industrial customers decreased 2.8% for the nine month period. KWh sales to residential and small commercial and industrial customers increased primarily due to the 1.4% increase in the average number of customers served. During the nine months ended September 30, 2012, cooling degree days decreased 9.5% when compared to the same period in 2011 but were 7.9% above the 10-year average. KWh sales to residential customers increased 1.7% and non-fuel base revenues from residential customers increased 0.7%. KWh sales to public authorities increased 2.2% and non-fuel revenues from public authorities increased 1.3%.

Retail non-fuel base revenues for the twelve months ended September 30, 2012 decreased by $3.8 million or 0.7%, compared to the same period in 2011. The decrease in revenues was primarily due to a reduction in non-fuel base rates to Texas customers which primarily impacted small and large commercial and industrial customers. Non-fuel base revenues from sales to small commercial and industrial customers and large commercial and industrial customers decreased 2.6% and 3.5%, respectively. In addition, increased use of lower interruptible rates rather than higher rates that are not interruptible, and decreased consumption by several large commercial and industrial customers contributed to the decrease in non-fuel base revenues. KWh sales to large commercial and industrial customers decreased 0.5% for the twelve month period. KWh sales to residential and small commercial and industrial customers increased primarily due to the 1.4% increase in the average number of customers served. During the twelve months ended September 30, 2012, cooling degree days decreased 8.9% when compared the same period in 2011 but were 9.0% above the 10-year average. KWh sales to residential customers increased 1.5% and non-fuel base revenues from residential customers increased 0.8%. KWh sales to public authorities increased 2.8% and non-fuel base revenues from public authorities increased 1.1%.

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, nine, and twelve months ended September 30, 2012, we over-recovered our fuel costs by $5.2 million, $20.8 million, and $24.4 million, respectively, compared to a fuel under-recovery of $3.8 million, $17.5 million, and $3.9 million in the same periods in 2011. Refunds of $6.8 million, $12 million, and $11.5 million were made to our Texas customers in September 2012, April 2011, and December 2010, respectively. On April 25, we received approval to reduce our fixed fuel factor charged to Texas retail customers effective May 1, 2012. At September 30, 2012, we had a net fuel over-recovery balance of $7.0 million, including $2.8 million in Texas, $4.1 million in New Mexico, and $0.1 million in FERC.

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 decreased $8.6 million, or 34.8% for the three months ended September 30, 2012, when compared to the same period last year, as a result of a 26.1% decrease in MWh sales and lower average market prices for power. Retained margins from off-system sales increased $0.1 million for the three months ended September 30, 2012, compared to the same period last year. Off-system sales revenues decreased $9.5 million, or 15.1% for the nine months ended September 30, 2012, when compared to the same period last year, as a result of a 9.1% decrease in MWh sales and lower average market prices for power.



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Retained margins from off-system sales increased $1.5 million for the nine months ended September 30, 2012, compared to the same period last year primarily due to the negative impacts in 2011 of power purchases required for system reliability when key generation and transmission facilities were either out of service or were threatened to be out of service. Off-system sales revenues decreased $14.9 million, or 17.9% for the twelve months ended September 30, 2012, when compared to the same period last year, as a result of an 11.7% decline in MWh sales and lower average market prices for power. Retained margins from off-system sales increased $1.4 million for the twelve months ended September 30, 2012, compared to the same period last year, due to the negative impact in 2011 of power purchases required for system reliability discussed above.



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Comparisons of kWh sales and operating revenues are shown below (in thousands):
						Increase (Decrease)
Quarter Ended September 30:	2012			2011		Amount			Percent
kWh sales:
Retail:
Residential	884,809			899,708		(14,899		)	(1.7	)%
Commercial and industrial, small	693,774			703,479		(9,705		)	(1.4	)
Commercial and industrial, large	260,567			279,339		(18,772		)	(6.7	)
Sales to public authorities	443,418			452,370		(8,952		)	(2.0	)
Total retail sales	2,282,568			2,334,896		(52,328		)	(2.2	)
Wholesale:
Sales for resale	20,565			21,046		(481		)	(2.3	)
Off-system sales	537,071			726,753		(189,682		)	(26.1	)
Total wholesale sales	557,636			747,799		(190,163		)	(25.4	)
Total kWh sales	2,840,204			3,082,695		(242,491		)	(7.9	)
Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	80,325		$	82,465	$	(2,140	)	(2.6	)%
Commercial and industrial, small	60,776			64,929		(4,153		)	(6.4	)
Commercial and industrial, large	12,587			13,597		(1,010		)	(7.4	)
Sales to public authorities	30,815			31,570		(755		)	(2.4	)
Total retail non-fuel base revenues	184,503			192,561		(8,058		)	(4.2	)
Wholesale:
Sales for resale	718			387		331			85.5
Total non-fuel base revenues	185,221			192,948		(7,727		)	(4.0	)
Fuel revenues:
Recovered from customers during the period	39,222			49,636		(10,414		)	(21.0	)	(1)
Under (over) collection of fuel	(5,238		)	3,786		(9,024		)	—
New Mexico fuel in base rates	23,174			23,626		(452		)	(1.9	)
Total fuel revenues	57,158			77,048		(19,890		)	(25.8	)	(2)
Off-system sales:
Fuel cost	13,640			23,258		(9,618		)	(41.4	)
Shared margins	2,222			1,310		912			69.6
Retained margins	265			157		108			68.8
Total off-system sales	16,127			24,725		(8,598		)	(34.8	)
Other	8,743			12,912		(4,169		)	(32.3	)	(3)
Total operating revenues	$	267,249		$	307,633	$	(40,384	)	(13.1	)
Average number of retail customers:
Residential	341,477			336,738		4,739			1.4	%
Commercial and industrial, small	37,893			38,292		(399		)	(1.0	)
Commercial and industrial, large	51			51		—			—
Sales to public authorities	4,578			4,637		(59		)	(1.3	)
Total	383,999			379,718		4,281			1.1


(1)	Excludes $6.8 million of refunds in 2012 related to Texas deferred fuel revenues from prior periods.


(2)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $2.6 million and $3.8 million, respectively.


(3)	Represents revenues with no related kWh sales. 2011 includes revenues from a one-time $4.5 million settlement of a transmission dispute with Tucson Electric Power Company.



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							Increase (Decrease)
Nine Months Ended September 30:	2012			2011			Amount			Percent
kWh sales:
Retail:
Residential	2,113,071			2,078,247			34,824			1.7	%
Commercial and industrial, small	1,826,463			1,816,081			10,382			0.6
Commercial and industrial, large	794,727			817,549			(22,822		)	(2.8	)
Sales to public authorities	1,226,886			1,200,597			26,289			2.2
Total retail sales	5,961,147			5,912,474			48,673			0.8
Wholesale:
Sales for resale	53,062			52,045			1,017			2.0
Off-system sales	1,966,560			2,162,793			(196,233		)	(9.1	)
Total wholesale sales	2,019,622			2,214,838			(195,216		)	(8.8	)
Total kWh sales	7,980,769			8,127,312			(146,543		)	(1.8	)
Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	187,738		$	186,376		$	1,362		0.7	%
Commercial and industrial, small	149,296			155,203			(5,907		)	(3.8	)
Commercial and industrial, large	32,340			34,703			(2,363		)	(6.8	)
Sales to public authorities	75,566			74,588			978			1.3
Total retail non-fuel base revenues	444,940			450,870			(5,930		)	(1.3	)
Wholesale:
Sales for resale	1,892			1,722			170			9.9
Total non-fuel base revenues	446,832			452,592			(5,760		)	(1.3	)
Fuel revenues:
Recovered from customers during the period	102,725			109,171			(6,446		)	(5.9	)	(1)
Under (over) collection of fuel	(20,828		)	17,524			(38,352		)	—
New Mexico fuel in base rates	57,881			57,151			730			1.3
Total fuel revenues	139,778			183,846			(44,068		)	(24.0	)	(2)
Off-system sales:
Fuel cost	45,612			60,777			(15,165		)	(25.0	)
Shared margins	6,865			2,722			4,143			—
Retained margins	824			(697		)	1,521			—
Total off-system sales	53,301			62,802			(9,501		)	(15.1	)
Other	24,168			27,110			(2,942		)	(10.9	)	(3)
Total operating revenues	$	664,079		$	726,350		$	(62,271	)	(8.6	)
Average number of retail customers:
Residential	340,591			335,792			4,799			1.4	%
Commercial and industrial, small	37,994			37,484			510			1.4
Commercial and industrial, large	50			50			—			—
Sales to public authorities	4,584			4,675			(91		)	(1.9	)
Total	383,219			378,001			5,218			1.4


(1)	Excludes $6.8 million and $12.0 million of refunds in 2012 and 2011, respectively, related to Texas deferred fuel revenues from prior periods.


(2)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $7.1 million and $11.6 million, respectively.


(3)	Represents revenues with no related kWh sales. 2011 includes revenues from a one-time $4.1 million settlement of a transmission dispute with Tucson Electric Power Company.



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							Increase (Decrease)
Twelve Months Ended September 30:	2012			2011			Amount			Percent
kWh sales:
Retail:
Residential	2,668,214			2,628,411			39,803			1.5	%
Commercial and industrial, small	2,362,600			2,349,394			13,206			0.6
Commercial and industrial, large	1,073,218			1,078,409			(5,191		)	(0.5	)
Sales to public authorities	1,605,854			1,562,764			43,090			2.8
Total retail sales	7,709,886			7,618,978			90,908			1.2
Wholesale:
Sales for resale	63,673			62,148			1,525			2.5
Off-system sales	2,491,398			2,821,759			(330,361		)	(11.7	)
Total wholesale sales	2,555,071			2,883,907			(328,836		)	(11.4	)
Total kWh sales	10,264,957			10,502,885			(237,928		)	(2.3	)
Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	235,448		$	233,592		$	1,856		0.8	%
Commercial and industrial, small	190,186			195,299			(5,113		)	(2.6	)
Commercial and industrial, large	43,044			44,600			(1,556		)	(3.5	)
Sales to public authorities	95,348			94,345			1,003			1.1
Total retail non-fuel base revenues	564,026			567,836			(3,810		)	(0.7	)
Wholesale:
Sales for resale	2,292			2,145			147			6.9
Total non-fuel base revenues	566,318			569,981			(3,663		)	(0.6	)
Fuel revenues:
Recovered from customers during the period	138,684			143,878			(5,194		)	(3.6	)	(1)
Under (over) collection of fuel	(24,435		)	3,911			(28,346		)	—
New Mexico fuel in base rates	74,184			73,133			1,051			1.4
Total fuel revenues	188,433			220,922			(32,489		)	(14.7	)	(2)
Off-system sales:
Fuel cost	59,571			78,651			(19,080		)	(24.3	)
Shared margins	8,026			5,236			2,790			53.3
Retained margins	961			(402		)	1,363			—
Total off-system sales	68,558			83,485			(14,927		)	(17.9	)
Other	32,433			33,306			(873		)	(2.6	)	(3)
Total operating revenues	$	855,742		$	907,694		$	(51,952	)	(5.7	)
Average number of retail customers:
Residential	339,818			335,306			4,512			1.3	%
Commercial and industrial, small	38,034			37,289			745			2.0
Commercial and industrial, large	50			50			—			—
Sales to public authorities	4,558			4,686			(128		)	(2.7	)
Total	382,460			377,331			5,129			1.4


(1)	Excludes $6.8 million and $23.5 million of refunds in 2012 and 2011, respectively, related to Texas deferred fuel revenues from prior periods.


(2)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $10.3 million and $14.5 million, respectively.


(3)	Represents revenues with no related kWh sales. Includes revenues from 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 51%, 54% and 55% of our Company-generated energy for the three, nine, and twelve months ended September 30, 2012, respectively. Fluctuations in the price of natural gas have had a significant impact on our cost of energy.

Energy expenses decreased $26.3 million or 26.6% for the three months ended September 30, 2012, when compared to 2011, primarily due to (i) decreased natural gas costs of $17.8 million due to a 29.1% decrease in the average price of natural gas and a 2.5% decrease in MWhs generated with natural gas, and (ii) decreased costs of purchased power of $9.6 million due to a 40.0% decrease in the MWhs purchased partially offset by a 4.7% increase in the average market price for power. These decreases were partially offset by increased nuclear fuel costs of $1.3 million due to an 8.5% increase in the cost of nuclear fuel consumed and a 2.0% increase in MWhs generated with nuclear fuel. The table below details the sources and costs of energy for the three months ended September 30, 2012 and 2011.



	Three Months Ended September 30,
	2012					2011
Fuel Type	Cost		MWh	Cost per MWh		Cost		MWh	Cost per MWh
	(in thousands)					(in thousands)
Natural gas	$	39,744	1,159,840	$	34.27	$	57,526	1,190,045	$	48.34
Coal	3,433		158,858	21.61		3,614		174,628	20.70
Nuclear	13,155		1,348,586	9.75		11,894		1,322,790	8.99
Total	56,332		2,667,284	21.12		73,034		2,687,463	27.18
Purchased power	16,223		375,606	43.19		25,845		626,562	41.25
Total energy	$	72,555	3,042,890	23.84		$	98,879	3,314,025	29.84

Our energy expenses decreased $49.3 million or 20.7% for the nine months ended September 30, 2012, when compared to 2011. The decrease was primarily due to decreased natural gas costs of $34.9 million due to a 33.0% decrease in the average cost of natural gas. The decrease in natural gas costs was partially offset by a 7.1% 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 $17.3 million or 28.6% decrease in purchased power costs due to a 24.6% decrease in MWhs purchased and a 5.3% decrease in the average market price for power, and (ii) decreased coal costs of $2.1 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 $5.1 million, or 15.2% primarily due to a 13.3% increase in the price of nuclear fuel and a 1.7% increase in MWh generated by nuclear fuel. The subsequent table details the sources and costs of energy for the nine month periods ended September 30, 2012 and 2011.



	Nine Months Ended September 30,
	2012					2011
Fuel Type	Cost		MWh	Cost per MWh		Cost		MWh	Cost per MWh
	(in thousands)					(in thousands)
Natural gas (a)	$	96,778	2,853,949	$	33.91	$	131,708	2,663,827	$	50.63
Coal (b)	9,921		480,555	20.64		12,030		486,607	19.92
Nuclear	38,433		3,898,862	9.86		33,373		3,834,651	8.70
Total	145,132		7,233,366	20.06		177,111		6,985,085	25.47
Purchased power	43,304		1,272,110	34.04		60,616		1,687,144	35.93
Total energy	$	188,436	8,505,476	22.15		$	237,727	8,672,229	27.51

______________


(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.



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Our energy expenses decreased $43.3 million or 14.8% for the twelve months ended September 30, 2012, when compared to 2011, primarily due to (i) decreased natural gas costs of $32.0 million due to a 27.1% decrease in the average price of natural gas partially offset by a 7.9% 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, (ii) decreased purchased power costs of $18.1 million due to a 21.2% decrease in the MWhs purchased and a 3.3% decrease in the average cost of purchased power, and (iii) decreased coal costs of $2.2 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 $8.9 million primarily due to a 13.0% 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 September 30, 2012 and 2011.



	Twelve Months Ended September 30,
	2012					2011
Fuel Type	Cost		MWh	Cost per MWh		Cost		MWh	Cost per MWh
	(in thousands)					(in thousands)
Natural gas (a)	$	129,330	3,536,911	$	36.57	$	161,300	3,277,481	$	50.18
Coal (b)	13,164		641,880	20.51		15,411		675,511	19.36
Nuclear (c)	49,034		5,006,266	9.79		40,090		5,011,800	8.66
Total	191,528		9,185,057	20.85		216,801		8,964,792	24.64
Purchased power	57,837		1,720,090	33.62		75,904		2,183,392	34.76
Total energy	$	249,365	10,905,147	22.87		$	292,705	11,148,184	26.63

______________


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


(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 $4.1 million, or 7.2% for the three months ended September 30, 2012, compared to the same period last year, primarily due to (i) increased administrative and general expense of $2.1 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, and (ii) increased operations expense at Palo Verde of $1.6 million. Other operations expense increased $6.0 million, or 3.6% for the nine months ended September 30, 2012, compared to the same period last year, primarily due to (i) increased administrative and general expense of $4.2 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 OPEB plans, and (ii) increased operations expense at Palo Verde of $1.6 million. Other operations expense increased $4.7 million, or 2.1% for the twelve months ended September 30, 2012, compared to the same period last year, primarily due to increased administrative and general expense of $4.6 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 OPEB plans.

Maintenance expense

Maintenance expense was relatively unchanged for the three months ended September 30, 2012, compared to the same period last year. Maintenance expense increased $1.8 million, or 4.4%, for the nine months ended September 30, 2012, compared to the same period last year, primarily 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 at Palo Verde was performed at a reduced cost when compared to the 2011 spring refueling outage. Maintenance expense increased $6.6 million, or 11.5% for the twelve months ended September 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.



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Depreciation and amortization expense

Depreciation and amortization expense decreased $1.1 million, or 5.4% for the three months ended September 30, 2012, compared to the same periods last year, primarily due to reduced depreciation rates for our gas-fired generation plant and our transmission and distribution plant. The 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 $1.4 million and $1.8 million, or 2.4% and 2.2%, for the nine and twelve months ended September 30, 2012, compared to the same periods last year, primarily due to (i) 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, (ii) reduced depreciation rates for our gas-fired generation plant and our transmission and distribution plant due to the Texas rate settlement discussed above, and (iii) the 2011 amortization of a New Mexico regulatory asset related to renewable energy credits with no comparable amortization in the current periods. The twelve month decrease was 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 decreased $1.3 million, or 7.7% for the three months ended September 30, 2012, as compared to the same period last year primarily due to lower revenue-related taxes resulting from a decrease in billed revenues reflecting both lower fuel and base rates. Taxes other than income taxes remained relatively unchanged for the nine and twelve months ended September 30, 2012, compared to the same periods last year.

Other income (deductions)

Other income (deductions) increased $3.4 million for the three months ended September 30, 2012, compared to the same period last year, primarily due to (i) impairments in our decommissioning trust investments of $1.3 million recorded in 2011 with no impairments recognized in 2012, (ii) a $1.1 million gain recognized on the sale of assets with no comparable amount in 2011, and (iii) increased allowance for equity funds used during construction (“AEFUDC”) resulting from higher balances of construction work in progress. Other income (deductions) increased $0.8 million for the nine months ended September 30, 2012, compared to the same period last year, due to a $1.1 million gain recognized on the sale of assets. Other income (deductions) for the twelve months ended September 30, 2012, compared to the twelve months ended September 30, 2011, decreased $1.2 million primarily due to 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) decreased $0.4 million , or 3.4% for the three months ended September 30, 2012, compared to the same period last year, primarily due to increased allowance for borrowed funds used during construction ("ABFUDC") as a result of higher balances of construction work in progress in 2012. Interest charges (credits) remained relatively unchanged for the nine months ended September 30, 2012, when compared to the same period last year. Interest charges (credits) increased $1.2 million, or 2.7%, for the twelve months ended September 30, 2012, compared to the same period last year, primarily due to decreased ABFUDC as a result of lower balances of construction work in progress in 2012 reflecting the completion of Newman Unit 5 in April 2011.

Income tax expense

Income tax expense decreased by $5.5 million, or 16.4%, $7.1 million, or 13.6%, and $6.0 million, or 11.4%, in the three, nine and twelve months ended September 30, 2012, compared to the same periods last year, primarily due to lower pre-tax income.

New Accounting Standards



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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. After reconsideration of its presentation requirements for reclassification, the FASB issued in August 2012, an exposure draft related to the presentation of items reclassified out of accumulated other comprehensive income. The exposure draft proposes that entities present separately in the notes tabular information about items that are reclassified out of each component of accumulated other comprehensive income and, for those items reclassified in their entirety into net income, the net income line item affected by the reclassification. The comment deadline was October 15, 2012. 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 September 30, 2012, our capital structure, including common stock, long-term debt, and short-term borrowings under the revolving credit facility, consisted of 47.7% common stock equity and 52.3% debt. At September 30, 2012, we had on hand $8.7 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 $3.3 million in reduced base revenues for the remaining three months of 2012 as a result of these lower rates. As part of the settlement we 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 in current costs of fuel changes in prices for natural gas. The lower fixed fuel factor 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 nine months ended September 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, including AFUDC. As of September 30, 2012, we had expended $69.0 million on Rio Grande Unit 9, including AFUDC, of which $31.8 million was incurred during 2012. Estimated cash construction expenditures for all capital projects for 2012 are expected to be approximately $220.7 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 anticipate issuing long-term debt in the form of senior notes in the next twelve months to repay short-term borrowings and to fund 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 $144.6 million in the nine months ended September 30, 2012 compared to $129.7 million in the nine months ended September 30, 2011. Capital requirements for purchases of nuclear fuel were $41.7 million for the nine months ended September 30, 2012 compared to $33.9 million for the nine months ended September 30, 2011.

On September 28, 2012, we paid $10.0 million of quarterly dividends to shareholders. We have paid a total of $28.9 million in cash dividends during the nine months ended September 30, 2012. On October 23, 2012, we declared a quarterly dividend to be paid December 28, 2012, which will require cash of $10.0 million. 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 nine months ended September 30, 2012. As of September 30, 2012, a total of 393,816 shares remain eligible for repurchase.

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 distribution of dividends 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 resulting in 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 $16.4 million of the projected $19.8 million 2012 annual contribution to our retirement plans during the nine months ended September 30, 2012. In the nine months ended September 30, 2012, we contributed $1.8 million of the projected $3.7 million 2012 annual contribution to our OPEB plan, and $3.4 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. In addition, we are in compliance with the funding requirements of the federal law and the Arizona Nuclear Power Project Participation Agreement for our 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 nine months ended September 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 nine months ended September 30, 2012, we had an over-recovery of fuel costs, net of refunds, of $14.0 million, compared to an under-recovery, net of refunds, of $29.6 million during the nine months ended September 30, 2011. At September 30, 2012, we had a net fuel over-recovery balance of $7.0 million, including $2.8 million in Texas, $4.1 million in New Mexico, and $0.1 million in FERC.

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 $139.5 million at September 30, 2012, of which $29.5 million had been borrowed under the RCF and $110 million was borrowed through senior notes. At September 30, 2011, the total amounts borrowed for nuclear fuel by RGRT was $127.8 million of which $17.8 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 September 30, 2012, $32.0 million was outstanding under the RCF for working capital or general corporate purposes. No borrowings were outstanding at September 30, 2011 under the RCF for working capital or general corporate purposes.

On August 28, 2012, we completed a refunding transaction related to our 2005 Series A refunding pollution control bonds totaling $59.2 million in which new pollution control bonds totaling $59.2 million were issued at a fixed rate of 4.5%. The bonds are unsecured and will mature in 2042. On August 28, 2012, we also completed a remarketing transaction related to our 2002 Series A refunding pollution control bonds totaling $33.3 million in which new pollution control bonds totaling $33.3 million were issued at a fixed rate of 1.875%. The bonds were unsecured and mature in 2032 although they are required to be remarketed in 2017.

We anticipate issuing long-term debt in the form of senior notes in the next twelve months to repay short-term borrowings and for future construction of electric plant. Based on current projections and the expected issuance of long-term debt, we believe that we will have adequate liquidity through our current cash balances, cash from operations, and available borrowings under the RCF to meet all our anticipated cash requirements for the next twelve months.

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 September 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.



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Item 4.	Controls and Procedures

Evaluation of disclosure controls and procedures. Under the supervision and with the participation of our management, including our chief executive officer and our chief financial officer, we conducted an evaluation pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934 of our disclosure controls and procedures as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934. Based on that evaluation, our chief executive officer and our chief financial officer concluded that, as of September 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 September 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
July 1 to July 31, 2012	—	$	—	—	393,816
August 1 to August 31, 2012	—	—		—	393,816
September 1 to September 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: November 2, 2012



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EL PASO ELECTRIC COMPANY

INDEX TO EXHIBITS




Exhibit Number			Exhibit

4.01			Ordinance No. 2012-1256 adopted by the City Council of Farmington, New Mexico on June 12, 2012 authorizing and providing for the issuance by the City of Farmington, New Mexico of $33,300,000 in aggregate principal amount of its Pollution Control Revenue Refunding Bonds, 2012 Series A (El Paso Electric Company Four Corners Project).

4.02			Remarketing and Purchase Agreement dated August 1, 2012 among El Paso Electric Company and U.S. Bancorp Investments, Inc. relating to the Pollution Control Bonds referred to in Exhibit 4.01.

4.03			Tender Agreement dated August 1, 2012 between El Paso Electric Company and Union Bank, N.A., relating to the Pollution Control Bonds referred to in Exhibit 4.01.

4.04			Amended and Restated Installment Sale Agreement, dated as of August 1, 2012, between El Paso Electric Company and the City of Farmington, New Mexico, relating to the Pollution Control Bonds referred to in Exhibit 4.01.

4.05			Indenture of Trust between Maricopa County, Arizona Pollution Control Corporation and Union Bank, N.A., as Trustee, dated as of August 1, 2012 relating to $59,235,000 Maricopa County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds 2012 Series A (El Paso Electric Company Palo Verde Project).

4.06			Loan Agreement dated August 1, 2012 between Maricopa County, Arizona Pollution Control Corporation and El Paso Electric Company relating to the Pollution Control Bonds referred to in Exhibit 4.05.

4.07			Bond Purchase Agreement dated August 15, 2012, among Maricopa County, Arizona Pollution Control Corporation, U.S. Bancorp Investments, Inc., and Merrill Lynch, Pierce, Fenner & Smith Incorporated relating to the Pollution Control Bonds referred to in Exhibit 4.05.

†10.06			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).

10.07			Amendment No. 15, dated January 13, 2011, to the Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, between Arizona Public Service Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Tucson Gas & Electric Company and the Company.

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 October 1, 2012, substantially identical in all material respects to this Exhibit, have been entered into with Catherine A. Allen; Patricia Z. Holland-Branch; and Stephen N. Wertheimer; directors of the Company.



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