Edgar Filing: EL PASO ELECTRIC CO /TX/

FORM 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2006

¨	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 0-296

El Paso Electric Company

(Exact name of registrant as specified in its charter)

Texas

74-0607870

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)


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

(915) 543-5711

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES x NO ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨

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

As of October 31, 2006, there were 46,681,060 shares of the Company’s no par value common stock outstanding.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

INDEX TO FORM 10-Q


		Page No.
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Consolidated Balance Sheets – September 30, 2006 and December 31, 2005		1

Consolidated Statements of Operations – Three Months, Nine Months and Twelve Months Ended September 30, 2006 and 2005		3

Consolidated Statements of Comprehensive Operations – Three Months, Nine Months and Twelve Months Ended September 30, 2006 and 2005		5

Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2006 and 2005		6

Notes to Consolidated Financial Statements		7

Report of Independent Registered Public Accounting Firm		27

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		28

Item 3. Quantitative and Qualitative Disclosures About Market Risk		45

Item 4. Controls and Procedures		45

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		46

Item 1A. Risk Factors		46

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		46

Item 6. Exhibits		46

(i)

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS


ASSETS (In thousands)	September 30, 2006 (Unaudited)			December 31, 2005
Utility plant:
Electric plant in service	$	1,943,358		$	1,913,196
Less accumulated depreciation and amortization		(785,767	)		(740,339	)

Net plant in service		1,157,591			1,172,857
Construction work in progress		114,057			83,092
Nuclear fuel; includes fuel in process of $2,432 and $6,990, respectively		68,453			66,516
Less accumulated amortization		(32,538	)		(30,768	)

Net nuclear fuel		35,915			35,748

Net utility plant		1,307,563			1,291,697

Current assets:
Cash and temporary investments		61,786			7,956
Accounts receivable, principally trade, net of allowance for doubtful accounts of $3,043 and $2,474, respectively		87,366			76,006
Accumulated deferred income taxes		1,823			2,628
Inventories, at cost		31,645			28,553
Undercollection of fuel revenues		51,335			71,611
Income taxes receivables		7,565			16,349
Prepayments and other		6,171			8,463

Total current assets		247,691			211,566

Deferred charges and other assets:
Decommissioning trust funds		107,799			96,010
Regulatory assets		25,301			26,050
Undercollection of fuel revenues, non-current		—			20,720
Other		18,969			19,406

Total deferred charges and other assets		152,069			162,186

Total assets	$	1,707,323		$	1,665,449

See accompanying notes to consolidated financial statements.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS (Continued)


CAPITALIZATION AND LIABILITIES (In thousands except for share data)	September 30, 2006 (Unaudited)			December 31, 2005
Capitalization:
Common stock, stated value $1 per share, 100,000,000 shares authorized, 63,709,829 and 63,382,456 shares issued, and 133,119 and 124,973 restricted shares, respectively	$	63,843		$	63,507
Capital in excess of stated value		279,769			275,393
Deferred and unearned compensation		1,161			2,150
Retained earnings		473,261			421,632
Accumulated other comprehensive loss, net of tax		(25,263	)		(30,167	)

		792,771			732,515
Treasury stock, 17,163,208 and 15,365,108 shares, respectively, at cost		(217,468	)		(176,076	)

Common stock equity		575,303			556,439
Long-term debt, net of current portion		590,858			590,838
Financing obligations, net of current portion		22,711			20,180

Total capitalization		1,188,872			1,167,457

Current liabilities:
Current portion of long-term debt and financing obligations		21,655			21,727
Accounts payable, principally trade		37,354			47,128
Taxes accrued other than federal income taxes		22,874			16,021
Interest accrued		10,180			4,484
Other		27,505			24,165

Total current liabilities		119,568			113,525

Deferred credits and other liabilities:
Accumulated deferred income taxes		134,605			123,233
Accrued postretirement benefit liability		106,732			105,084
Asset retirement obligation		71,700			66,997
Accrued pension liability		42,524			45,952
Regulatory liabilities		14,993			15,817
Other		28,329			27,384

Total deferred credits and other liabilities		398,883			384,467

Commitments and contingencies

Total capitalization and liabilities	$	1,707,323		$	1,665,449

See accompanying notes to consolidated financial statements.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands except for share data)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Operating revenues	$	228,949		$	242,031		$	623,174		$	590,516

Energy expenses:
Fuel		62,618			81,096			160,988			182,151
Purchased and interchanged power		25,503			23,701			91,127			54,642

		88,121			104,797			252,115			236,793

Operating revenues net of energy expenses		140,828			137,234			371,059			353,723

Other operating expenses:
Other operations		48,263			46,222			137,975			131,777
Maintenance		9,764			8,671			46,748			30,737
Depreciation and amortization		16,879			18,750			50,957			66,175
Taxes other than income taxes		14,867			12,313			39,785			32,762

		89,773			85,956			275,465			261,451

Operating income		51,055			51,278			95,594			92,272

Other income (deductions):
Investment and interest income, net		1,443			1,623			3,576			3,561
Loss on extinguishments of debt		—			(30	)		—			(19,448	)
Miscellaneous non-operating income		8			55			145			770
Miscellaneous non-operating deductions		(979	)		(1,281	)		(3,026	)		(2,955	)

		472			367			695			(18,072	)

Interest charges (credits):
Interest on long-term debt and financing obligations		8,896			8,870			26,450			32,287
Other interest		964			221			1,009			448
Capitalized interest and AFUDC		(1,199	)		(1,536	)		(3,351	)		(3,925	)

		8,661			7,555			24,108			28,810

Income before income taxes		42,866			44,090			72,181			45,390
Income tax expense		15,790			16,078			20,552			16,583

Net income	$	27,076		$	28,012		$	51,629		$	28,807

Basic earnings per share	$	0.57		$	0.59		$	1.07		$	0.60

Diluted earnings per share	$	0.56		$	0.58		$	1.06		$	0.60

Weighted average number of shares outstanding		47,843,730			47,826,500			48,085,238			47,646,788

Weighted average number of shares and dilutive potential shares outstanding		48,380,845			48,590,859			48,569,697			48,183,301

See accompanying notes to consolidated financial statements.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands except for share data)


	Twelve Months Ended September 30,
	2006			2005
Operating revenues	$	836,571		$	756,145

Energy expenses:
Fuel		241,707			230,708
Purchased and interchanged power		116,525			68,965

		358,232			299,673

Operating revenues net of energy expenses		478,339			456,472

Other operating expenses:
Other operations		184,485			179,160
Maintenance		63,349			46,811
Depreciation and amortization		67,250			89,725
Taxes other than income taxes		52,050			40,925

		367,134			356,621

Operating income		111,205			99,851

Other income (deductions):
Investment and interest income, net		5,640			5,347
Loss on extinguishments of debt		(113	)		(20,112	)
Miscellaneous non-operating income		496			1,345
Miscellaneous non-operating deductions		(4,257	)		(3,683	)

		1,766			(17,103	)

Interest charges (credits):
Interest on long-term debt and financing obligations		34,925			44,297
Other interest		1,260			564
Capitalized interest and AFUDC		(5,209	)		(5,004	)

		30,976			39,857

Income before income taxes and cumulative effect of accounting change		81,995			42,891
Income tax expense		22,558			15,266

Income before cumulative effect of accounting change		59,437			27,625
Cumulative effect of accounting change, net of tax		(1,093	)		—

Net income	$	58,344		$	27,625

Basic earnings per share:
Income before cumulative effect of accounting change	$	1.23		$	0.58
Cumulative effect of accounting change, net of tax		(0.02	)		—

Net income	$	1.21		$	0.58

Diluted earnings per share:
Income before cumulative effect of accounting change	$	1.22		$	0.57
Cumulative effect of accounting change, net of tax		(0.02	)		—

Net income	$	1.20		$	0.57

Weighted average number of shares outstanding		48,039,830			47,559,379

Weighted average number of shares and dilutive potential shares outstanding		48,596,806			48,162,904

See accompanying notes to consolidated financial statements.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS

(Unaudited)

(In thousands)


	Three Months Ended September 30,						Nine Months Ended September 30,						Twelve Months Ended September 30,
	2006			2005			2006			2005			2006			2005
Net income	$	27,076		$	28,012		$	51,629		$	28,807		$	58,344		$	27,625
Other comprehensive income (loss):
Minimum pension liability adjustment		—			—			—			—			(6,128	)		(1,413	)
Net unrealized gains (losses) on marketable securities:
Net holding gains (losses) arising during period		4,501			153			5,468			(1,760	)		5,433			621
Reclassification adjustments for net (gains) losses included in net income		53			89			509			244			(299	)		99
Net losses on cash flow hedges:
Losses arising during period		—			—			—			(22,439	)		—			(22,439	)
Reclassification adjustment for interest expense included in net income		65			84			196			104			235			104

Total other comprehensive income (loss) before income taxes		4,619			326			6,173			(23,851	)		(759	)		(23,028	)

Income tax benefit (expense) related to items of other comprehensive income (loss):
Minimum pension liability adjustment		—			—			—			—			2,299			532
Net unrealized gains (losses) on marketable securities		(910	)		(48	)		(1,195	)		304			(1,027	)		(143	)
Losses on cash flow hedges		(25	)		(33	)		(74	)		8,412			(88	)		8,412

Total income tax benefit (expense)		(935	)		(81	)		(1,269	)		8,716			1,184			8,801

Other comprehensive income (loss), net of tax		3,684			245			4,904			(15,135	)		425			(14,227	)

Comprehensive income	$	30,760		$	28,257		$	56,533		$	13,672		$	58,769		$	13,398

See accompanying notes to consolidated financial statements.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)


	Nine Months Ended September 30,
	2006			2005
Cash flows from operating activities:
Net income	$	51,629		$	28,807
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service		50,957			66,175
Amortization of nuclear fuel		11,401			12,258
Deferred income taxes, net		11,000			22,983
Loss on extinguishments of debt		–			19,448
Other amortization and accretion		9,307			8,836
Gain on sale of asset		–			(374	)
Other operating activities		429			–
Change in:
Accounts receivable		(11,360	)		(16,117	)
Inventories		(2,737	)		(527	)
Net recovery (deferral) of fuel revenues		40,996			(44,481	)
Prepayments and other		9,730			(9,628	)
Accounts payable		(9,774	)		6,599
Taxes accrued other than federal income taxes		6,853			1,129
Interest accrued		5,696			(3,712	)
Other current liabilities		3,340			(701	)
Deferred charges and credits		(1,780	)		(7,975	)

Net cash provided by operating activities		175,687			82,720

Cash flows from investing activities:
Cash additions to utility property, plant and equipment		(65,507	)		(58,352	)
Cash additions to nuclear fuel		(11,175	)		(9,888	)
Proceeds from sale of asset		–			1,944
Capitalized interest and AFUDC:
Utility property, plant and equipment		(2,902	)		(3,671	)
Nuclear fuel		(449	)		(254	)
Decommissioning trust funds:
Purchases, including funding of $5.0 and $4.6 million, respectively		(25,226	)		(19,004	)
Sales and maturities		18,982			12,969
Other investing activities		2,062			1,906

Net cash used for investing activities		(84,215	)		(74,350	)

Cash flows from financing activities:
Proceeds from exercise of stock options		1,419			4,218
Repurchases of treasury stock		(41,392	)		–
Proceeds from issuance of long-term notes payable		–			397,688
Repurchases of and payments on first mortgage bonds		–			(381,847	)
Settlement on derivative instruments classified as cash flow hedges		–			(22,439	)
Pollution control bonds:
Proceeds		–			193,135
Payments		–			(193,135	)
Financing obligations:
Proceeds		13,264			11,585
Payments		(10,803	)		(12,849	)
Other financing activities		(130	)		(9,966	)

Net cash provided by financing activities		(37,642	)		(13,610	)

Net increase (decrease) in cash and temporary investments		53,830			(5,240	)
Cash and temporary investments at beginning of period		7,956			29,401

Cash and temporary investments at end of period	$	61,786		$	24,161

See accompanying notes to consolidated financial statements.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

A.	Principles of Preparation

These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto in the Annual Report of El Paso Electric Company on Form 10-K for the year ended December 31, 2005 (the “2005 Form 10-K”). Capitalized terms used in this report and not defined herein have the meaning ascribed for such terms in the 2005 Form 10-K. In the opinion of management of the Company, the accompanying consolidated financial statements contain all adjustments necessary to present fairly the financial position of the Company at September 30, 2006 and December 31, 2005; the results of its operations and comprehensive operations for the three, nine and twelve months ended September 30, 2006 and 2005; and its cash flows for the nine months ended September 30, 2006 and 2005. The results of operations and comprehensive operations for the three and nine months ended September 30, 2006 and the cash flows for the nine months ended September 30, 2006 are not necessarily indicative of the results to be expected for the full calendar year.

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

Stock-Based Compensation. The Company has two stock-based long-term incentive plans. Effective January 1, 2006, the Company adopted SFAS No. 123 (revised) “Accounting for Stock-Based Compensation,” which requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with some limited exceptions). Such cost will be recognized over the period during which an employee is required to provide service in exchange for the award (the “requisite service period”) which typically will be the vesting period. Compensation cost is not recognized for anticipated forfeitures prior to vesting of equity instruments. SFAS No. 123 (revised) applies to all awards granted after January 1, 2006 and to awards modified, repurchased or cancelled after that date. Additionally, compensation cost for outstanding awards for which the requisite service has not been rendered as of January 1, 2006 shall be expensed as the requisite service is rendered on or after such date. The compensation cost for that portion of awards shall be based on the grant-date fair value of those awards as calculated for pro forma disclosure under SFAS No. 123. SFAS No. 123 (revised) replaces SFAS No. 123, “Accounting for Stock – Based Compensation,” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. See Note D.

Unbilled Revenues. Accounts receivable include accrued unbilled revenues of $16.7 million and $16.4 million at September 30, 2006 and December 31, 2005, respectively.

New Accounting Standards. In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

No. 157 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company does not believe SFAS No. 157 will have a significant impact on its consolidated financial statements.

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R).” SFAS No. 158 requires the recognition of the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and recognition of changes in that funded status in the year in which the changes occur through comprehensive income of a business entity. SFAS No. 158 also requires the measurement of the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. This statement is effective as of the end of the fiscal year ending after December 15, 2006. The Company will adopt the provisions of this statement in our financial statements for the year ending December 31, 2006. The Company has not yet completed the analysis of the ultimate impact that this new pronouncement will have on its balance sheet.

In June 2006, the FASB issued FASB Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109.” FIN 48 clarifies the accounting for uncertainty in income taxes recognized in the financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 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 and provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. The Company will adopt the provisions of this interpretation in our financial statements for the fiscal year beginning January 1, 2007. The Company has not yet completed the analysis of the ultimate impact this new pronouncement will have on its financial statements.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Supplemental Cash Flow Disclosures (in thousands)


	Nine Months Ended September 30,
	2006		2005
Cash paid for:
Interest on long-term debt and financing obligations	$	19,296	$	35,034
Income taxes		1,732		1,195
Non-cash financing activities:
Grants of restricted shares of common stock		1,500		1,953

B.	Regulation

FERC Regulatory Matters

In January 2006, the Company filed a complaint with the FERC to interpret the terms of a Power Exchange and Transmission Agreement (the “Transmission Agreement”) entered into with Tucson Electric Power (“TEP”) in 1982. TEP claimed that, under the Transmission Agreement, it was entitled to up to 400 MW of transmission rights on the Company’s transmission system that would enable it to transmit power from a new generating station located near Deming, New Mexico (the “Deming Plant”) to Arizona. The Company asserted that TEP’s rights under the Transmission Agreement do not include transmission rights necessary to transmit such power as contemplated by TEP and that TEP must acquire any such rights in the open market from the Company at applicable tariff rates or other transmission providers. On April 24, 2006, the FERC ruled in the Company’s favor, finding that TEP does not have the transmission rights under the Transmission Agreement to transmit power from the Deming Plant to Arizona. The ruling was based on written evidence presented and without an evidentiary hearing. TEP’s request for a rehearing of the FERC’s decision was granted in part and denied in part in an order issued October 4, 2006. The October 4 order grants a hearing to examine the disputed evidence; however, the hearing is to be held in abeyance to allow time for the parties to attempt to negotiate a settlement. If a settlement is not reached, the Company and TEP will present their cases before an administrative law judge whose decision will be subject to FERC review. While the Company believes that it is not probable that TEP will prevail, the Company cannot predict the outcome of this case. During the nine months ended September 30, 2006, TEP has paid the Company $3.1 million for transmission service to the Deming Plant which the Company has included in operating revenues. If the FERC were to rule in TEP’s favor, the Company may be required to refund the revenues it has received from TEP for transmission service to date relating to the Deming Plant and may lose the opportunity to receive compensation from TEP for such transmission service in the future. An adverse ruling by the FERC could have a material negative effect on the Company’s results of operations.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Texas Regulatory Matters

The rates and services of the Company are regulated in Texas by municipalities and by the Texas Commission. The largest municipality in the Company’s Texas service area is the City of El Paso (the “City”). The Texas Commission has exclusive appellate jurisdiction to review municipal orders and ordinances regarding rates and services within municipalities in Texas and original jurisdiction over certain other activities of the Company. The decisions of the Texas Commission are subject to judicial review.

New Texas Freeze Period and Franchise Agreement. On July 21, 2005, the Company entered into an agreement with the City (the “City Rate Agreement”), to extend its existing freeze period for an additional five years expiring June 30, 2010 (the “New Texas Freeze Period”). Under the City Rate Agreement which became effective as of July 1, 2005, most retail base rates will remain at their current level for the next five years. If, during the term of the agreement, the Company’s return on equity falls below the bottom of a defined range, the Company has the right to initiate a rate case and seek an adjustment to base rates. If the Company’s return on equity exceeds the top of the range, the Company will refund, at the City’s direction, an amount equal to 50% of the City jurisdictional pre-tax return in excess of the ceiling. The range is market-based and currently is approximately 8% to 12%.

Pursuant to the City Rate Agreement, the Company will share with its Texas customers 25% of off-system sales margins and wheeling revenues. Under the prior rate agreement, the Company shared 50% of off-system sales margins and wheeling revenues with Texas customers. The City Rate Agreement requires a variance to the substantive rules of the Texas Commission regarding the sharing of margins. In PUC Docket No. 32289, filed on January 17, 2006, the Company has sought Texas Commission approval of the margin sharing provisions of the agreement. The Company filed a non-unanimous stipulation (the “Stipulation”) with the Texas Commission on July 31, 2006. Settling parties include the Texas Commission staff, a large industrial customer, and the City. The Stipulation provides for the Company to retain 75% of Texas jurisdictional off-system sales margins and extends the rate freeze and earnings sharing provisions of the City Rate Agreement to customers outside the City.

On October 17, 2006, the Company entered into a settlement agreement (the “Settlement Agreement”) with the Office of the Attorney General of the State of Texas (the “State”) regarding PUC Docket No. 32289. Under the terms of the Settlement Agreement, the State agreed that it would not oppose the City Rate Agreement or the Stipulation. The Company agreed that, upon expiration of the City Rate Agreement on June 30, 2010, the Company would credit to its Texas customers 90% of Texas jurisdictional off-system sales margins. This provision is not binding on the Texas Commission or other settling parties. Further, after the expiration of the City Rate Agreement, the Company agreed that it will begin treating its wheeling expenses and revenues associated with non-native load in a manner consistent with then-existing Texas Commission rules and other substantive and procedural law. In addition, the Company agreed that, upon the expiration of the City Rate Agreement, it would file a full base rate case with the Texas Commission and the applicable cities having original rate jurisdiction if requested to do so by the Texas Commission staff, the City, the State or the Texas Office of Public

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Utility Counsel. The Company also retained the right to voluntarily file a full base rate case. The Company currently anticipates that it will need base rate relief in that time frame.

The Texas Commission conducted a hearing in PUC Docket No. 32289 on October 18, 2006, and no parties filed any opposition to the Company’s request for Texas Commission approval of the sharing provisions of the City Rate Agreement. The Company expects a decision from the Texas Commission in this docket in December 2006 or January 2007. The Company is unable to predict how the Texas Commission will rule in this matter. If the Texas Commission does not approve the margin sharing provisions of the City Rate Agreement, the Company and the City have agreed to negotiate in good faith to amend the City Rate Agreement to achieve a similar economic result.

Under the terms of the City Rate Agreement, the Company has committed to spend at least 0.3% of its total El Paso revenues on civic and charitable causes within the City. Further, in accordance with the City Rate Agreement, the Company and the City engaged at the Company’s expense the services of an independent consultant to review the reasonableness of certain operating expenses of the Company. On June 2, 2006, the consultant issued its report stating that such expenses were reasonable and as a result the City Rate Agreement remained in full force and effect. Consistent with the prior rate agreement, the City Rate Agreement may be reopened by the City in the event of a merger or change in control of the Company to seek rate reductions based on post-merger synergy savings.

The City also granted to the Company a new 25-year franchise which became effective August 2, 2005 and increased franchise fee payments from 2% to 3.25% of gross revenues received for services within the City limits. The franchise governs the Company’s use of City-owned rights-of-way and the payment of franchise fees. In August 2005 a dispute arose over the timing and characterization of past and future franchise fee payments to the City. The parties are continuing to discuss a resolution of this issue, and the Company does not believe that such resolution will have a material adverse impact on its results of operations or financial condition.

Fuel and Purchased Power Costs. Although the Company’s base rates are frozen under the City Rate Agreement, pursuant to Texas Commission rules and the City Rate Agreement, the Company’s fuel costs are passed through to its customers. In January and July of each year, the Company can request adjustments to its fuel factor to more accurately reflect projected energy costs associated with providing electricity, seek recovery of past undercollections of fuel revenues, and refund past overcollections of fuel revenues. All such fuel revenue and expense activities are subject to periodic final review by the Texas Commission in fuel reconciliation proceedings.

In November 2005, the Texas Commission approved the Company’s request to (i) increase Texas jurisdictional fixed fuel factors by $30.6 million or 23% annually to reflect an average cost of natural gas of $7.28 per MMBtu; and (ii) recover under-recovered fuel costs through August 2005 of $53.6 million over a 24-month period through a fuel surcharge. The fixed fuel factor and fuel surcharge were implemented effective with billings in October 2005.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

On January 5, 2006, the Company filed a petition (PUC Docket No. 32240) with the Texas Commission to increase its fixed fuel factors and to surcharge under-recovered fuel costs as a result of higher natural gas prices. The Company requested an increase in its Texas jurisdiction fixed fuel factors of $30.8 million or 16% annually to reflect an average cost of natural gas of $9.35 per MMBtu. The Company also requested a fuel surcharge to recover over a twelve-month period approximately $34 million of fuel undercollections, including interest, for under-recoveries for the period September 2005 through November 2005. The requested fuel factor and fuel surcharge were placed into effect on an interim basis subject to refund effective with February 2006 bills to customers. This proceeding has been abated pending the Texas Commission’s decision in PUC Docket No. 32289, the margin sharing proceeding discussed above. Once a decision is issued in PUC Docket No. 32289, the Company will seek to negotiate with parties to resolve the proceeding. Any settlement will be subject to final approval by the Texas Commission.

New Mexico Regulatory Matters

The rates and services of the Company are regulated in New Mexico by the NMPRC. The largest municipality in the Company’s New Mexico service area is the City of Las Cruces. The NMPRC has jurisdiction to review utility agreements with municipalities regarding utility rates and services in New Mexico. The decisions of the NMPRC are subject to judicial review.

Fuel and Purchased Power Costs. On August 29, 2005, the Company filed the annual reconciliation of its Fuel and Purchased Power Cost Adjustment Clause (“FPPCAC”) for the period June 1, 2004 through May 31, 2005 in compliance with the requirements of the NMPRC’s Final Order in NMPRC Case No. 03-00302-UT. The Company requested reconciliation of all its fuel and purchased power costs for this period, and requested recovery of $1.3 million for the New Mexico jurisdictional portion of purchased power capacity costs consistent with its interpretation of NMPRC rules. In April 2006, the Company received a NMPRC final order finding that the Company can recover purchased power capacity costs through its New Mexico fuel adjustment clause and providing for recovery of the $1.3 million of capacity costs during the reconciliation period over a 12-month period beginning in May 2006. The Company also recognized deferred fuel revenue in 2006 for the period of June 1, 2005 through December 2005, of $0.8 million, to reflect recovery of these costs. The NMPRC also determined that the Company’s fuel and purchased power costs were reconciled for the limited purpose of verifying all actual fuel and purchased power revenues and expenses recorded by the Company and that the Company had administered its fuel clause in accordance with prior orders and rules of the NMPRC. The reasonableness of fuel costs will be subject to review by the NMPRC in the Company’s current rate filing.

Current Rate Filing. On June 30, 2006, the Company filed a petition with the NMPRC to increase overall rates by approximately $31.7 million. The filing requests an increase in base rates of $13.1 million prior to the reclassification of $29.4 million of fuel costs currently in base rates to the fuel adjustment clause. Consequently, the Company is requesting a $16.3 million reduction in base revenues after considering the reclassification of fuel costs. An increase of $18.6 million in fuel clause recoveries has been requested before the reclassification of base fuel and $48.0 million after the reclassification of

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

base fuel. Requested natural gas costs of $9.50 per MMBtu are based upon the forecast period June 2007 through May 2008. The Company is requesting that the NMPRC allow it to recover all fuel and purchased power costs through its fuel adjustment clause. In addition, the Company is requesting that energy provided from Palo Verde Unit 3 which has been deregulated in New Mexico be included in the fuel adjustment clause at market rates. Requested rates would not be effective before June 1, 2007 when the Company’s existing rate freeze expires. Hearings are scheduled to begin in late January 2007 and a final order is expected in July 2007. Management cannot predict at this time the final rates and rate treatments that the NMPRC will approve pursuant to this filing.

C.	Palo Verde

The original spent fuel storage facilities at Palo Verde had sufficient capacity to store all fuel discharged from normal operation of all three Palo Verde units through 2003. Alternative on-site storage facilities and casks have been constructed and supplement the original facilities. We expect to incur significant costs for on-site spent fuel storage during the life of Palo Verde that we believe are the responsibility of the DOE. Until an agreement is reached with the DOE for recovery of those costs, these costs are included in fuel costs and amortized as that fuel is burned. In December 2003, APS, in conjunction with other nuclear plant operators, filed suit against the DOE on behalf of the Palo Verde Participants to recover monetary damages associated with the delay in the DOE’s acceptance of spent fuel. APS has advised the Palo Verde Participants that the stay for the APS case has been lifted and that the case will likely go to trial in 2008. We are unable to predict the outcome of these matters at this time.

For a full discussion of spent fuel storage, see Note C of Notes to Consolidated Financial Statements in the 2005 Form 10-K.

D.	Common Stock

Long-Term Incentive Plans

The Company’s shareholders have approved the adoption of two stock-based long-term incentive plans. The first plan was approved in 1996 (the “1996 Plan”) and authorized the issuance of up to 3.5 million shares of common stock for the benefit of officers, key employees and directors. The second plan was approved in 1999 (the “1999 Plan”) and authorized the issuance of up to two million shares of common stock for the benefit of directors, officers, managers, other employees and consultants. Under the plans, common stock may be issued through the award or grant of non-statutory stock options, incentive stock options, stock appreciation rights, restricted stock, bonus stock and performance stock. As of September 30, 2006, there were 174,385 shares available for future awards under these two plans. The Company may issue new shares, purchase shares on the open market, or issue shares from shares the Company has repurchased to meet the share requirements of these plans.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

As discussed in Note A, the Company adopted SFAS No. 123 (revised) effective January 1, 2006. The Company adopted the “modified prospective application method” as provided for in SFAS No. 123 (revised) which provides for compensation expense related to unvested stock awards to be recognized prospectively. Under the modified prospective application method, compensation expense for unvested awards is recognized over the remaining service periods of those awards and the cumulative change in compensation expense vested in prior periods is recognized in the period the new accounting standard is adopted.

Stock Options. Stock options have been granted at exercise prices equal to or greater than the market value of the underlying shares at the date of grant. The fair value for these options was estimated at the grant date using the Black-Scholes option pricing model. The options expire ten years from the date of grant unless terminated earlier by the Board of Directors. No stock options were granted during 2005 or the nine months ended September 30, 2006.

The following table summarizes the transactions in the Company’s stock options for the nine months ended September 30, 2006:


	Options Outstanding		Weighted Average Exercise Price		Options Exercisable
Options at December 31, 2005	1,354,448		$	11.12	1,044,448
Options vested	—			13.69	170,000
Options exercised	(100,000	)		5.56	(100,000	)

Options at March 31, 2006	1,254,448			11.57	1,114,448
Options exercised	(100,000	)		7.00	(100,000	)

Options at June 30, 2006	1,154,448			11.96	1,014,448
Options exercised	(20,000	)		8.13	(20,000	)

Options at September 30, 2006	1,134,448			12.03	994,448

The Company received approximately $1.4 million in cash for the 220,000 stock options exercised in the nine months ended September 30, 2006, which had an intrinsic value of $3.0 million and a grant date fair value of $0.6 million. No current tax benefits were realized for the tax deduction from stock options exercised during the nine months ended September 30, 2006 because the Company is in a tax net operating loss position. No options were forfeited or expired during the nine months ended September 30, 2006. There were 170,000 options which vested during the nine months ended September 30, 2006 with an aggregate intrinsic value of $1.5 million at September 30, 2006, and a fair value at grant date of $1.2 million.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Stock option awards provide for vesting periods of up to six years. Stock options outstanding and exercisable at September 30, 2006 are set forth in the following table:


	Options Outstanding				Options Exercisable
Exercise Price Range	Number Outstanding	Average Remaining Contractual Life in Years	Weighted Average Exercise Price		Number Exercisable	Average Remaining Contractual Life in Years	Weighted Average Exercise Price
$ 6.56 - $ 8.125	260,000	1.3	$	7.40	260,000	1.3	$	7.40
9.50 - 13.85	549,448	5.3		12.85	429,448	5.2		12.77
13.94 - 14.95	325,000	4.8		14.35	305,000	4.7		14.37

	1,134,448				994,448

As of September 30, 2006, there were 994,448 exercisable stock options with a weighted average exercise price of $11.86 per share, a weighted average grant date fair value of $5.75 per share, and an aggregate intrinsic value of $10.4 million. The aggregate intrinsic value of the 1,134,448 outstanding stock options at September 30, 2006 was $11.7 million.

The Company recorded compensation cost of $0.2 million and $0.6 million for the three and nine months ended September 30, 2006, respectively, related to the 140,000 outstanding unvested stock option awards and the tax benefit and capitalized costs related to these compensation costs were less than $0.1 million and $0.2 million, respectively. The unvested stock option awards have remaining $0.3 million of unrecognized compensation cost. That cost is expected to be recognized over the next 1.25 years. The weighted average aggregate fair value at grant date of these unvested stock options is $0.9 million. Weighted average assumptions and grant-date fair value for options granted in 2004 are presented below:


Risk-free interest rate		4.01	%
Expected life, in years		7.3
Expected volatility		22.42	%
Expected dividend yield		—
Fair value per option	$	4.87

Restricted Stock. The Company has awarded restricted stock under its long-term incentive plans. Restrictions from resale generally lapse and awards vest over periods of one to five years. The market value of vested restricted stock awards is expensed at the time of grant. The market value of the unvested restricted stock at the date of grant is recorded as deferred and unearned compensation and is shown as a separate component of common stock equity and is amortized to expense over the restriction period. For the three months ended September 30, 2006 and 2005, approximately $0.4 million and $0.4 million, respectively, related to restricted stock awards was charged to expense and the tax benefit related to these expenses was $0.2 million and $0.1 million, respectively. For the nine months ended September 30, 2006 and 2005, approximately $1.2 million and $1.1 million, respectively, related to restricted stock awards was charged to expense and the tax benefit related to these expenses was

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

$0.5 million and $0.4 million, respectively. For the twelve months ended September 30, 2006 and 2005, approximately $1.6 million and $1.4 million, respectively, was expensed related to restricted stock awards and the tax benefit related to these expenses was $0.6 million and $0.5 million, respectively. Any capitalized costs related to these expenses would be less than $0.1 million for all periods. The aggregate intrinsic value for restricted stock vested during the nine months ended September 30, 2006 was $1.3 million with a related fair value at grant date of $1.3 million. The outstanding restricted stock has remaining $1.2 million of unrecognized expense at September 30, 2006 that is expected to be recognized over the weighted average remaining contractual term of the outstanding restricted stock of approximately one year. The aggregate intrinsic value of the 133,119 outstanding restricted shares at September 30, 2006 was $3.0 million.

The following table summarizes the unvested restricted stock awards for the first nine months of 2006:


	Total Shares		Weighted Average Grant Date Fair Value
Restricted shares outstanding at December 31, 2005	124,973		$	17.87
Restricted stock awards	21,762			20.79
Lapsed restrictions and vesting	(14,849	)		13.90

Restricted shares outstanding at March 31, 2006	131,886			18.80
Restricted stock awards	52,706			19.39
Lapsed restrictions and vesting	(51,790	)		20.00

Restricted shares outstanding at June 30, 2006	132,802			18.56
Restricted stock awards	1,266			20.16
Lapsed restrictions and vesting	(949	)		20.45

Restricted shares outstanding at September 30, 2006	133,119			18.57

The holder of a restricted stock award has rights as a shareholder of the Company, including the right to vote and, if applicable, receive cash dividends on restricted stock, except that certain restricted stock awards require any cash dividends on restricted stock to be delivered to the Company in exchange for additional shares of restricted stock of equivalent market value.

Performance Shares. The Company has granted performance share awards to certain officers under the Company’s existing long-term incentive plans, which provide for issuance of Company stock based on the achievement of certain performance criteria over a three-year period. The payout varies between 0% to 200% of performance shares. On January 1, 2006, 68,425 performance shares were issued at the 175% performance level with a total cost of $1.4 million which had been expensed ratably over 2004 and 2005. The requisite service period for these shares ended December 31, 2005, and the shares had an aggregate intrinsic value of $1.4 million. On January 1, 2007, 2008 and 2009, subject to meeting certain performance criteria, additional performance shares will be issued. In accordance with

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

SFAS No. 123 (revised), the Company will recognize the related compensation expense by ratably amortizing the grant date fair market value of awards over the requisite service period and the compensation expense will only be adjusted for forfeitures. The actual number of shares issued can range from zero to 348,200 shares.

The fair market value at the date of grant for the three separate grants of performance shares was based upon a Monte Carlo simulation. The Monte Carlo simulation reflected the structure of the performance plan which calculates the share payout on relative performance of the Company over a three-year performance period based upon total return to shareholders. The fair market value was determined as the average payout of one million simulation paths discounted to the grant date using a risk-free interest rate based upon the constant maturity treasury rate yield curve at the grant date.

The following table summarizes the outstanding performance share awards at the 100% performance level:


	Number Outstanding		Weighted Average Grant Date Fair Value
Performance shares outstanding at December 31, 2005	142,500		$	20.27
Performance share awards	70,700			18.37
Performance shares issued	(39,100	)		18.39

Performance shares outstanding at September 30, 2006	174,100			19.92

The outstanding performance awards have remaining $1.5 million of unrecognized expense at September 30, 2006 that is expected to be recognized over the weighted average remaining contractual term of the awards of approximately 1.5 years. The aggregate intrinsic value of the 174,100 outstanding awards (based on 100% performance level) at September 30, 2006 was $3.9 million.

The Company recorded $0.3 million of compensation expense for the three months ended September 30, 2006, for the performance share awards with related tax benefits of $0.1 million. During the first quarter of 2006, the Company recorded a cumulative adjustment to operating expense related to 2004 and 2005 performance stock awards to reflect the implementation of SFAS No. 123 (revised) which reduced expense by $0.7 million pretax, $0.4 million after-tax. For the nine and twelve months ended September 30, 2006, the Company recorded $0.2 million and $0.8 million of compensation expense, respectively, for the performance share awards which included the cumulative adjustment.

Prior to implementing SFAS No. 123 (revised) the Company recognized compensation expense for performance share awards by ratably amortizing their fair market value at the end of the reporting period based on the Company’s performance at that time over the performance cycles. The Company has recorded compensation expense related to performance shares awards of $0.5 million, $0.9 million, and $1.7 million for the three, nine, and twelve months ended September 30, 2005, respectively.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Proforma Results. If compensation expense for the incentive plans had been amortized on a straight-line basis over the vesting period, consistent with the provisions of SFAS No. 123 (revised), the Company’s net earnings and earnings per share for the three, nine and twelve months ended September 30, 2005 and the twelve months ended September 30, 2006 would have been reduced to the proforma amounts presented below (in thousands, except for per share data):


	Three Months Ended September 30, 2005		Nine Months Ended September 30, 2005		Twelve Months Ended September 30,
	Three Months Ended September 30, 2005		Nine Months Ended September 30, 2005		2006		2005
Net income, as reported	$	28,012	$	28,807	$	58,344	$	27,625
Deduct: Compensation expense, net of tax		59		579		379		450

Proforma net income	$	27,953	$	28,228	$	57,965	$	27,175

Basic earnings per share:
As reported	$	0.59	$	0.60	$	1.21	$	0.58
Proforma		0.58		0.59		1.21		0.57

Diluted earnings per share:
As reported		0.58		0.60		1.20		0.57
Proforma		0.58		0.59		1.19		0.56

Prior to the adoption of SFAS No. 123 (revised), the Company presented all tax benefits for deductions resulting from the exercise of share-based compensation as operating cash flows in the Condensed Consolidated Statement of Cash Flows. SFAS No. 123 (revised) requires the benefits of tax deductions in excess of the taxes expensed on recognized compensation cost to be reported as financing cash flows. The Company currently has no excess tax benefits because of its tax net operating loss position.

Common Stock Repurchase Program

In the third quarter of 2006, the Board of Directors (the “Board”) authorized the repurchase of up to 2.3 million shares of the Company’s outstanding common stock (the “2006 Plan”). The shares authorized under the 2006 Plan are in addition to the shares which were available under a buy back program previously approved by the Board in February 2004 (the “2004 Plan”). No common stock was repurchased during the first or second quarters of 2006. During the third quarter of 2006, the Company repurchased 1,798,100 shares of common stock at an aggregate cost of $41.4 million. As of September 30, 2006, no shares remain available under the 2004 Plan, and approximately 2.2 million shares remain authorized to be repurchased under the 2006 Plan. The Company may in the future make purchases of its stock pursuant to its stock repurchase plan at open market prices and may engage in private transactions, where appropriate. The repurchased shares will be available for issuance under employee benefit and stock option plans, or may be retired.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Reconciliation of Basic and Diluted Earnings Per Share

The reconciliation of basic and diluted earnings per share before cumulative effect of accounting change is presented below:


	Three Months Ended September 30,
	2006					2005
	Income		Shares	Per Share		Income		Shares	Per Share
	(In thousands)					(In thousands)
Basic earnings per share:
Net income	$	27,076	47,843,730	$	0.57	$	28,012	47,826,500	$	0.59

Effect of dilutive securities:
Unvested restricted stock		—	156,091				—	181,868
Stock options		—	381,024				—	582,491
Diluted earnings per share:

Net income	$	27,076	48,380,845	$	0.56	$	28,012	48,590,859	$	0.58


	Nine Months Ended September 30,
	2006					2005
	Income		Shares	Per Share		Income		Shares	Per Share
	(In thousands)					(In thousands)
Basic earnings per share:
Net income	$	51,629	48,085,238	$	1.07	$	28,807	47,646,788	$	0.60

Effect of dilutive securities:
Unvested restricted stock		—	138,238				—	106,264
Stock options		—	346,221				—	430,249
Diluted earnings per share:

Net income	$	51,629	48,569,697	$	1.06	$	28,807	48,183,301	$	0.60


	Twelve Months Ended September 30,
	2006					2005
	Income		Shares	Per Share		Income		Shares	Per Share
	(In thousands)					(In thousands)
Basic earnings per share:
Income before cumulative effect of accounting change	$	59,437	48,039,830	$	1.23	$	27,625	47,559,379	$	0.58

Effect of dilutive securities:
Unvested restricted stock		—	160,560				—	119,766
Stock options		—	396,416				—	483,759
Diluted earnings per share:

Income before cumulative effect of accounting change	$	59,437	48,596,806	$	1.22	$	27,625	48,162,904	$	0.57

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the three, nine and twelve months ended September 30, 2006 and 2005, no options were excluded from the computation of diluted earnings per share because the exercise price was greater than the average market price.

E.	Income Taxes

In May 2006, legislation was approved in Texas revamping the state franchise (income) tax. The tax legislation changes the franchise tax from a tax based upon either taxable capital or taxable income to a 1% tax on taxable margins. The revised franchise tax is effective for tax payments in 2008 based upon 2007 taxable margin. Taxable margin for the Company is based upon revenues taxable for federal income tax purposes less cost of goods sold which includes all costs of producing electricity, but does not include post-production costs, such as transmission, distribution, and administrative and general expenses. Even with the lower tax rate, the expansion of the tax base will result in higher franchise tax expense beginning in 2007.

For accounting purposes, the revised franchise tax is an income tax subject to the requirements of SFAS No. 109, “Accounting for Income Taxes”. SFAS No. 109 requires that deferred tax assets and liabilities be adjusted for changes in tax law in the period of change. As a result, the Company recorded a $6.2 million reduction in its net deferred tax liability in the second quarter of 2006 and a corresponding reduction in income tax expense. The adjustment to the net deferred income tax liability includes: (i) a reduction of $2.7 million in net Texas deferred income tax liabilities associated with temporary differences that will not reverse in the future under the revised franchise tax calculation; (ii) a reduction of $6.8 million in net Texas deferred income tax liabilities for the change in tax rate from 4.5% to 1% effective in 2007; and (iii) an increase of $3.3 million in deferred federal income tax liabilities to reflect the change in deferred federal income taxes associated with deferred Texas franchise taxes.

F.	Commitments, Contingencies and Uncertainties

For a full discussion of commitments and contingencies, see Note I of Notes to Consolidated Financial Statements in the 2005 Form 10-K. In addition, see Note B above and Notes B and C of Notes to Consolidated Financial Statements in the 2005 Form 10-K regarding matters related to regulation and Palo Verde, including decommissioning, spent fuel storage, disposal of low-level radioactive waste, steam generators, reactor vessel heads and liability and insurance matters.

Power Contracts

In 2004, the Company entered into a contract with Southwestern Public Service Company (“SPS”) for the purchase of up to 133 MW of capacity and associated energy for a term of 20 years beginning January 1, 2006. The contract provides that, in the event the transactions thereunder are subject to adverse regulatory action, the affected party may initiate discussions with the other party to assess whether modifications to the agreement may be appropriate. If the parties are unable to reach a mutually satisfactory resolution within six months, either party may terminate the contract by providing not less than two years’ prior written notice to the other party.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

In October 2006, the Company received notice from SPS alleging that SPS has been subject to adverse regulatory action by the Texas Commission in a fuel surcharge proceeding (Docket No. 32685) which purportedly determined that SPS should assign incremental fuel costs to the contract. The contract provides for SPS to charge average fuel costs. The Company does not believe that the Texas Commission’s order in Docket No. 32685 constitutes an adverse regulatory action under the contract and intends to vigorously defend its position, including intervening in Docket No. 32685. The Company is unable to predict the outcome of this matter. If the Company is unsuccessful in defending its position or negotiating mutually satisfactory modifications to the contract, SPS may be able to terminate the contract early. If the contract is terminated early, the Company would need to replace the SPS contract.

In June 2006, the Company began exchanging up to 100 MW of capacity and associated energy with Phelps Dodge Energy. The contract provides for Phelps Dodge to deliver energy to the Company from its ownership interest in the Luna Energy Facility, an approximate 570 MW natural gas-fired combined cycle generation facility located in Luna County, New Mexico and for the Company to deliver a like amount of energy at the Greenlee delivery point. The Company may purchase up to 100 MW at a specified price at times when energy is not exchanged. The agreement was approved by the Federal Energy Regulatory Commission and continues through December 31, 2021.

Environmental Matters

The Company is subject to regulation with respect to air, soil and water quality, solid waste disposal and other environmental matters by federal, state, tribal and local authorities. Those authorities govern current facility operations and have continuing jurisdiction over facility modifications. Failure to comply with these environmental regulatory requirements can result in actions by regulatory agencies or other authorities that might seek to impose on the Company administrative, civil, and/or criminal penalties. If the United States regulates greenhouse gas emissions, the Company’s fossil fuel generation assets will be faced with the additional cost of monitoring, controlling and reporting these emissions. A significant portion of the Company’s generation assets are nuclear and gas-fired. As a result, the Company does not believe such regulations would impose greater burdens on the Company than on most other electric utilities. In addition, unauthorized releases of pollutants or contaminants into the environment can result in costly cleanup obligations that are subject to enforcement by regulatory agencies. Environmental regulations can change rapidly and are often difficult to predict. While the Company strives to prepare for and implement changes necessary to comply with changing environmental regulations, substantial expenditures may be required for the Company to comply with such regulations in the future.

The Company analyzes the costs of its obligations arising from environmental matters on an ongoing basis and believes it has made adequate provision in its financial statements to meet such obligations. As a result of this analysis, the Company has a provision for environmental remediation obligations of approximately $2.0 million as of September 30, 2006, which is related to compliance with

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

federal and state environmental standards. However, unforeseen expenses associated with compliance 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, 2006 and 2005 to comply with federal environmental statutes (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,				Twelve Months Ended September 30,
	2006		2005		2006		2005		2006		2005
Clean Air Act	$	280	$	300	$	769	$	875	$	1,000	$	944
Clean Water Act (1)		1		213		936		549		2,136		1,295

(1)	Includes $1.1 million and $0.6 million in remediation costs for the twelve months ended September 30, 2006 and 2005, respectively.

Along with many other companies, the Company received from the Texas Commission on Environmental Quality (“TCEQ”) a request for information in 2003 in connection with environmental conditions at a facility in San Angelo, Texas that was operated by the San Angelo Electric Service Company (“SESCO”). In November 2005, TCEQ proposed the SESCO site for listing on the registry of Texas state superfund sites and mailed notice to more than five hundred entities, including the Company, indicating that TCEQ considers each of them to be “potentially responsible parties” at the SESCO site. The Company received from the SESCO working group of potentially responsible parties a settlement offer in May 2006 for remediation and other expenses expected to be incurred in connection with the SESCO site. The Company’s position is that any liability it may have related to the SESCO site was discharged in the Company’s bankruptcy. At this time, the Company has not agreed to the settlement or to otherwise participate in the cleanup of the SESCO site and is unable to predict the outcome of this matter. While the Company has no reason at present to believe that it will incur material liabilities in connection with the SESCO site, it has accrued $0.3 million for potential costs related to this matter.

In the first quarter of 2006, a fuel oil release was discovered at one of the Company’s local generating plants. The fuel oil from an above ground storage tank spilled due to a pipeline malfunction and was contained inside a safety corridor. It is estimated that approximately 95% of fuel oil released was recovered and placed back into the fuel inventory. During the second quarter of 2006, the Company completed its assessment of the situation and started the remediation process on the contaminated soil containing the remaining 5% of the fuel oil. The estimated cost to address this incident is $0.8 million which has been recorded as maintenance expense in the Company’s financial statements.

On September 26, 2006, the Secretary of the New Mexico Environment Department issued a Compliance Order concerning the Company’s Rio Grande Generating Station, located in Dona Ana County, New Mexico. The Compliance Order alleges that, on approximately 650 occasions between May of 2000 and September of 2005, the Rio Grande Generating Station emitted sulfur dioxide, nitrogen oxides or carbon monoxide in excess of its permitted emission rates and failed to properly report these

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

allegedly excess emissions. The Compliance Order asserts a statutory authority to seek a civil penalty of up to $15,000 per violation for each of the violations alleged. The Company disputes the allegations made and has requested a hearing before the New Mexico Environment Department on the matter. While the Company cannot predict the outcome of this matter, it believes no penalties have been incurred.

Except as described herein, the Company is not aware of any other active investigation of its compliance with environmental requirements by the Environmental Protection Agency, the TCEQ or the New Mexico Environment Department which is expected to result in any material liability. Furthermore, except as described herein, the Company is not aware of any unresolved, potentially material liability it would face pursuant to the Comprehensive Environmental Response, Comprehensive Liability Act of 1980, also known as the Superfund law.

Tax Matters

The Company’s federal income tax returns for the years 1999 through 2002 have been examined by the IRS. On May 9, 2005, the Company received a notice of proposed deficiency from the IRS. The primary audit adjustments proposed by the IRS related to (i) whether the Company was entitled to currently deduct payments related to the repair of the Palo Verde Unit 2 steam generators or whether these payments should be capitalized and depreciated and (ii) whether the Company was entitled to currently deduct payments related to the dry cask storage facilities for spent nuclear fuel or whether these payments should be capitalized and depreciated. The proposed IRS adjustments would affect the timing of these deductions not their ultimate deductibility for federal tax purposes. The Company has protested the audit adjustments through administrative appeals and believes that its treatment of the payments is supported by substantial legal authority. In the event that the IRS prevails, the resulting income tax and interest payments could be material to the Company’s cash flows. The IRS is currently performing an examination of the 2003 and 2004 income tax returns.

The Company has established, and periodically reviews and re-evaluates, an estimated contingent tax liability on its consolidated balance sheet to provide for the possibility of adverse outcomes in tax proceedings. Although the ultimate outcome of the ongoing examination cannot be predicted with certainty, and while the contingent tax liability may not in fact be sufficient, the Company believes that the amount of contingent tax liability recorded as of September 30, 2006 is a reasonable estimate of any additional tax that may be due.

G.	Litigation

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

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

On May 21, 2003, the Company was served with a complaint by the Port of Seattle seeking civil damages under the Sherman Act, the Racketeer Influenced and Corrupt Organization Act, and state antitrust laws, as well as for fraud (Port of Seattle v. Avista Corporation, et al., No. CV03-117OP). The complaint was filed in the United States District Court for the Western District of Washington. The complaint alleges that the Company, indirectly through its dealings with Enron, conspired with the other named defendants to manipulate the California energy market, which had the effect of artificially inflating the price that the Port of Seattle paid for electricity. The Company, together with several other defendants, filed a motion to dismiss. On May 12, 2004, the Court granted the Company’s motion, and the suit was dismissed. The Port of Seattle filed an appeal of the Court’s decision with the U. S. Court of Appeals for the Ninth Circuit. On March 30, 2006, the Court of Appeals upheld the dismissal of this matter. No further appeal was filed and the dismissal is final.

On May 5, 2004, Wah Chang, a specialty metals manufacturer which operates a plant in Oregon, filed suit against the Company and other defendants in the United States District Court for the District of Oregon. (Wah Chang v. Avista Corporation, et al., No. 04-619AS). The complaint makes substantially the same allegations as were made in Port of Seattle and seeks the same types of damages. In addition, on June 7, 2004, the City of Tacoma filed suit against the Company and other defendants in the United States District Court for the Western District of Washington (City of Tacoma v. American Electric Power Service Corp., et al., C04-5325RBL). This complaint also makes substantially the same allegations as were made in Port of Seattle and seeks civil damages (including treble damages) from the Company and the other defendants for violations of certain antitrust provisions under the Sherman Act. Both of these matters were transferred to the same court that heard and dismissed the Port of Seattle lawsuit and on February 11, 2005, the Court granted the Company’s motion to dismiss both cases. Wah Chang and the City of Tacoma have both filed notices of appeal with the U.S. Court of Appeals for the Ninth Circuit. The parties have filed briefs in both cases and are awaiting a hearing and decision. While the Company believes that these matters are without merit and intends to defend itself vigorously, the Company is unable to predict the outcome or range of possible loss.

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

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

H.	Employee Benefits

Retirement Plans

The net periodic benefit cost recognized for the three, nine and twelve months ended September 30, 2006 and 2005 is made up of the components listed below as determined using the projected unit credit actuarial cost method (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Components of net periodic benefit cost:
Service cost	$	1,425		$	1,291		$	4,276		$	3,873
Interest cost		2,759			2,658			8,276			7,974
Expected return on plan assets		(2,789	)		(2,359	)		(8,367	)		(7,077	)
Amortization of:
Net loss		1,151			1,049			3,453			3,146
Prior service cost		29			29			87			87

Net periodic benefit cost	$	2,575		$	2,668		$	7,725		$	8,003


	Twelve Months Ended September 30,
	2006			2005
Components of net periodic benefit cost:
Service cost	$	5,567		$	4,975
Interest cost		10,934			10,526
Expected return on plan assets		(10,716	)		(9,222	)
Amortization of:
Net loss		4,536			4,040
Prior service cost		115			187

Net periodic benefit cost	$	10,436		$	10,506

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

During the nine months ended September 30, 2006, the Company contributed $11.2 million of its projected $13.7 million 2006 annual contribution to its retirement plans.

Other Postretirement Benefits

The net periodic benefit cost recognized for the three, nine and twelve months ended September 30, 2006 and 2005 is made up of the components listed below (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Components of net periodic benefit cost:
Service cost	$	1,030		$	1,187		$	3,090		$	3,561
Interest cost		1,532			1,667			4,596			5,001
Expected return on plan assets		(368	)		(345	)		(1,104	)		(1,036	)
Amortization of:
Net gain		—			—			—			—
Prior service cost		(694	)		(89	)		(2,082	)		(267	)

Net periodic benefit cost	$	1,500		$	2,420		$	4,500		$	7,259


	Twelve Months Ended September 30,
	2006			2005
Components of net periodic benefit cost:
Service cost	$	4,278		$	3,880
Interest cost		6,262			5,572
Expected return on plan assets		(1,450	)		(1,349	)
Amortization of:
Net gain		—			(387	)
Prior service cost		(2,170	)		(518	)

Net periodic benefit cost	$	6,920		$	7,198

During the nine months ended September 30, 2006, the Company contributed $2.9 million of its projected $3.4 million 2006 annual contribution to its postretirement benefit plan.

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

El Paso Electric Company:

We have reviewed the condensed consolidated balance sheet of El Paso Electric Company and subsidiary as of September 30, 2006, the related condensed consolidated statements of operations and comprehensive operations for the three-month, nine-month, and twelve-month periods ended September 30, 2006 and 2005, and the related condensed consolidated statements of cash flows for the nine-month periods ended September 30, 2006 and 2005. These condensed 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 condensed 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, 2005, 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 March 10, 2006, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2005, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

KPMG LLP

Houston, Texas

November 3, 2006

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 2005 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,

•

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 rates following the end of the New Texas Freeze Period ending June 30, 2010 and the New Mexico Stipulation ending May 31, 2007,

•

loss of margins on off-system sales due to changes in wholesale power prices or availability of competitive generation resources,

•

increased costs at Palo Verde,

•

reductions in output at generation plants including Palo Verde,

•

unscheduled outages including outages at Palo Verde,

•

potential for strike or lock out due to union employees working without a contract,

•

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,

•

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

•

changes in environmental regulations,

•

the impact of changes and downturns in the energy industry and the market for trading wholesale electricity,

•

approval by the Texas Commission of the 75% off-system sales margin retention percentage as contemplated in the City Rate Agreement,

•

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 assets,

•

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

•

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

•

homeland security considerations,

•

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

•

other circumstances affecting anticipated operations, sales and costs.

These lists are not all-inclusive because it is not possible to predict all factors. A discussion of some of these factors is included in this document under the headings “Risk Factors” and in the 2005 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 2005 Form 10-K.

Palo Verde Operations

We own approximately 600 megawatts (undivided interest) of generating capacity in the three generating units at the Palo Verde nuclear power station. The operation of Palo Verde not only affects our ability to make off-system sales, but also impacts fuel costs to native load customers and represents a significant portion of our non-fuel operating expenses. Generation from Palo Verde declined 15% in the nine months ended September 30, 2006 compared to the same period in 2005 due primarily to reduced output from Palo Verde Unit 1.

Palo Verde Unit 1 operated at significantly reduced power levels from December 25, 2005 until March 18, 2006 and did not operate from March 18, 2006 until early July 2006 while repairs and modifications were made to one of its shutdown cooling lines. Palo Verde Unit 1 reached full capacity on July 16, 2006. Palo Verde Unit 1 experienced a 27 day outage in September and October 2006 to replace pressurizer heaters. Palo Verde operations and maintenance costs increased $11.1 million for the nine months ended September 30, 2006 compared to the same period last year primarily due to the repairs and modifications of Unit 1 and a scheduled Unit 3 maintenance and refueling outage.

While the outage at Palo Verde Unit 1 negatively impacted our off-system sales margins, historically we have made fewer off-system sales in the second and third quarters relative to the first quarter. We retained off-system sales margins of $4.4 million and $3.6 million, in the third quarter of 2006 and 2005, respectively. Off-system sales margins retained for the nine months ended September 30, 2006 and for the same time period in 2005 were $11.3 million and $12.0 million, respectively.

Income Taxes

In May 2006, legislation was approved in Texas revamping the state franchise (income) tax. The tax legislation changes the franchise tax from a tax based upon either taxable capital or taxable income to a 1% tax on taxable margins. The revised franchise tax is effective for tax payments in 2008 based upon 2007 taxable margin. Our taxable margin is based upon revenues taxable for federal income tax purposes less cost of goods sold which includes all costs of producing electricity, but does not include post-production costs. Even with the lower tax rate, the expansion of the tax base will result in higher franchise tax expense beginning in 2007.

For accounting purposes, the revised franchise tax is an income tax subject to the requirements of SFAS No. 109, “Accounting for Income Taxes”. SFAS No. 109 requires that deferred tax assets and liabilities be adjusted for changes in tax law in the period of change. As a result, we recorded a $6.2 million reduction in our net deferred tax liability in the second quarter of 2006 and a corresponding reduction in income tax expense. The adjustment to the net deferred income tax liability includes: (i) a reduction of $2.7 million in net Texas deferred income tax liabilities associated with temporary differences that will not reverse in the future under the revised franchise tax calculation; (ii) a reduction of $6.8 million in net Texas deferred income tax liabilities for the change in tax rate from 4.5% to 1% effective in 2007; and (iii) an increase of $3.3 million in deferred federal income tax liabilities to reflect the change in deferred federal income taxes associated with deferred Texas franchise taxes.

Power Exchange and Transmission Agreement with Tucson Electric Power

In January 2006, we filed a complaint with the FERC to interpret the terms of a Power Exchange and Transmission Agreement (the “Transmission Agreement”) entered into with Tucson Electric Power (“TEP”) in 1982. TEP claimed that, under the Transmission Agreement, it was entitled to up to 400 MW of transmission rights on our transmission system that would enable it to transmit power from a new generating station located near Deming, New Mexico (the “Deming Plant”) to Arizona. We asserted that TEP’s rights under the Transmission Agreement do not include transmission rights necessary to transmit such power as contemplated by TEP and that TEP must acquire any such rights in the open market from us at applicable tariff rates or other transmission providers. On April 24, 2006, the FERC ruled in our favor, finding that TEP does not have the transmission rights under the Transmission Agreement to transmit power from the Deming Plant to Arizona. The ruling was based on written evidence presented and without a hearing. TEP’s request for a rehearing of the FERC’s decision was

granted in part and denied in part in an order issued October 4, 2006. The October 4 order grants a hearing to examine the disputed evidence; however, the hearing is to be held in abeyance to allow time for the parties to attempt to negotiate a settlement. If a settlement is not reached, we and TEP will present our cases before an administrative law judge whose decision will be subject to judicial review. We believe that it is not probable that TEP will prevail, but we cannot predict the outcome of this case. During the nine months ended September 30, 2006, TEP has paid us, and we have recorded as operating revenues in our financial statements, $3.1 million for transmission service to the Deming Plant. If the FERC were to rule in TEP’s favor, we may be required to refund the revenues we have received from TEP for transmission service to date relating to the Deming Plant and may lose the opportunity to receive compensation from TEP for such transmission service in the future. An adverse ruling by the FERC could have a material negative effect on our results of operations.

New Rate Agreement with the City of El Paso

As previously disclosed, we entered into a rate agreement with the City of El Paso (the “City”) on July 21, 2005 (the “City Rate Agreement”). Pursuant to the terms of the City Rate Agreement, the City and we agreed that we would credit to our Texas customers 25% of Texas jurisdictional off-system sales margins and wheeling revenues and that we would retain 75% of such margins and revenues. The sharing mechanism is tied to the rate freeze which expires June 30, 2010 subject to five-year extensions upon our request and consent by the City. This sharing provision of the City Rate Agreement requires a variance to the substantive rules of the Texas Commission and we sought Texas Commission approval of the sharing provisions of the City Rate Agreement in PUC Docket No. 32289 filed on January 17, 2006. On July 31, 2006, we, along with the Texas Commission staff, the City and a large industrial customer filed a non-unanimous stipulation with the Texas Commission which supported the requested off-system margin sharing and extended the rate freeze and earnings sharing provisions of the City Rate Agreement to Texas customers outside the City (the “Stipulation”). If the Texas Commission does not approve the sharing provisions of the City Rate Agreement, we and the City have agreed to negotiate in good faith to amend the agreement to achieve a similar economic result to the parties.

On October 17, 2006, we entered into a settlement agreement (the “Settlement Agreement”) with the Office of the Attorney General of the State of Texas (the “State”) regarding PUC Docket No. 32289. Under the terms of the Settlement Agreement, the State agreed that it would not oppose the City Rate Agreement or the Stipulation. We agreed that, upon expiration of the City Rate Agreement on June 30, 2010, we would credit to our Texas customers 90% of Texas jurisdictional off-system sales margins. This provision is not binding on the Texas Commission or other settling parties. Further, after the expiration of the City Rate Agreement, we agreed that we will begin treating our wheeling expenses and revenues associated with non-native load in a manner consistent with then-existing Texas Commission rules and other substantive and procedural law. In addition, we agreed that, upon the expiration of the City Rate Agreement, we would file a full base rate case with the Texas Commission and the applicable cities having original rate jurisdiction if requested to do so by the Texas Commission staff, the City, the State or the Texas Office of Public Utility Counsel. We also retained the right to voluntarily file a full base rate case. We currently anticipate that we will need base rate relief in that time frame.

The Texas Commission conducted a hearing in PUC Docket No. 32289 on October 18, 2006, and no parties filed any opposition to our request for Texas Commission approval of the sharing provisions of the City Rate Agreement. We expect a decision from the Texas Commission in this docket

in December 2006 or January 2007. We are unable to predict how the Texas Commission will rule in this matter.

Summary

The following is an overview of our results of operations for the three, nine and twelve month periods ended September 30, 2006 and 2005. Income for the three, nine and twelve month periods ended September 30, 2006 and 2005 is shown below:


	Three Months Ended September 30,				Nine Months Ended September 30,				Twelve Months Ended September 30,
	2006		2005		2006		2005		2006		2005
Net income before cumulative effect of accounting change (in thousands)	$	27,076	$	28,012	$	51,629	$	28,807	$	59,437	$	27,625
Basic earnings per share before cumulative effect of accounting change		0.57		0.59		1.07		0.60		1.23		0.58

The following table and accompanying explanations show the primary factors affecting the after-tax change in income before cumulative effect of accounting change between the 2006 and 2005 periods presented (in thousands):


	Three Months Ended			Nine Months Ended			Twelve Months Ended
September 30, 2005 net income before cumulative effect of accounting change	$	28,012		$	28,807		$	27,625
Change in (net of tax):
Decreased depreciation and amortization expense (a)		1,160			9,435			13,935
Increased transmission wheeling revenue (b)		952			3,570			4,171
Accrual for Texas fuel case (c)		904			904			904
Decreased loss on extinguishment of debt (d)		19			12,058			12,399
Income tax adjustment for change in tax law (e)		—			6,174			6,174
Increased Palo Verde operations and maintenance expense (f)		(998	)		(6,895	)		(8,073	)
Increased taxes other than income taxes (g)		(1,583	)		(4,354	)		(6,897	)
Increased fossil fuel plant maintenance (h)		(362	)		(4,277	)		(3,628	)
Increased (decreased) retail base revenues (i)		(262	)		5,097			6,014
Increased (decreased) interest charges on long-term debt (j)		(16	)		3,619			5,811
Other		(750	)		(2,509	)		1,002

September 30, 2006 net income before cumulative effect of accounting change	$	27,076		$	51,629		$	59,437

(a)	Depreciation and amortization decreased due to completing the recovery of certain fresh-start accounting related assets over the term of the Texas Rate Stipulation which ended July 2005.

(b)	Increased transmission wheeling revenues reflects transmission sales to third party owners, including TEP, of a new generation plant in southern New Mexico. See previous discussion entitled “Power Exchange and Transmission Agreement with Tucson Electric Power.”

(c)	Accrual for Texas fuel case reflects an accrual for a fuel disallowance related to the Texas Commission’s review of fuel costs for the period January 1, 2002 through February 29, 2004.

(d)	A loss on extinguishment of debt was recognized in 2005 due to the refinancing of all our first mortgage bonds in the second quarter of 2005 with no comparable amounts in 2006.

(e)	An income tax adjustment was recorded in 2006 to reduce deferred tax expense and accumulated deferred taxes to reflect the change in tax rate and methodology due to a revision of the Texas franchise (income) tax law passed in May 2006.

(f)	Palo Verde operations and maintenance expense increased in 2006 when compared to the same periods last year due to increased expenses at Unit 1 and at Unit 3 during a scheduled maintenance and refueling outage.

(g)	Taxes other than income taxes increased primarily due to an increase in the El Paso city franchise fee rate which took effect in August 2005 and higher taxable revenues which include fuel surcharges in Texas.

(h)	Maintenance costs at our gas-fired generating plants increased in 2006 when compared to the same periods last year.

(i)

Retail base revenues decreased for the three months ended September 30, 2006 compared to the same period last year primarily due to decreased revenues from residential customers which were affected by the mild summer weather in the third quarter of 2006. Retail base revenues increased for the nine and twelve months ended September 30, 2006 compared to the same periods last year primarily due to increased kWh sales reflecting growth in the number of customers served in 2006.

(j)

Interest charges decreased for the nine and twelve months ended September 30, 2006 compared to the same periods last year due to lower interest expense on long-term debt resulting from the refinancing of first mortgage bonds with long-term senior notes in the second quarter of 2005 and the August 2005 reissuance and remarketing of pollution control bonds at lower interest rates.

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 for the three, nine and twelve months ended September 30, 2006 and 2005. 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. Under the terms of our City Rate Agreement, we share with our Texas customers 25% of our off-system sales margins and wheeling revenues. (See Note B of the Notes to Consolidated Financial Statements).

Revenues from the sale of electricity include fuel costs, which are essentially passed through to customers through fuel adjustment mechanisms in Texas and New Mexico and a portion through base revenues in New Mexico. We record deferred fuel revenues for the difference between fuel costs and fuel revenues until such amounts are collected from or refunded to customers. “Base revenues” refers to our revenues from the sale of electricity excluding such fuel costs except for a portion of fuel costs in New Mexico.

Retail base revenues. Retail base revenues decreased by $0.5 million or 0.3% for the three months ended September 30, 2006 when compared to the same period in 2005 primarily due to decreased revenues from residential customers. Residential base revenues decreased by $1.3 million or 2.2% in the third quarter of 2006 compared to the same period in 2005 primarily due to the mild and wet summer weather in the third quarter of 2006. During the third quarter of 2006, cooling degree days were over 15% below both last year and the 10-year average. The impact of mild weather on residential sales was largely offset by a 2.6% increase in the average number residential customers.

The decrease in residential base revenues was partially offset by increases in base revenues from small commercial and industrial customers, large commercial and industrial customers, and sales to public authorities. The impact of the mild and wet summer weather in the third quarter of 2006 on small commercial and industrial customers was offset by an increase in sales due to a 3.4% increase in average number of customers served resulting in a 0.7% increase in revenues. Likewise, sales to other public

authorities increased as a result of a 1.0% increase in the average number of customers served. The increase in base revenues for large commercial and industrial customers is primarily the result of a 2.8% increase in kWh sales.

Retail base revenues increased by $8.7 million or 2.4% for the nine months ended September 30, 2006 when compared to the same period in 2005 primarily due to a 2.7% increase in the average number of customers served. The mild weather in the third quarter of 2006 was largely offset by warmer summer weather in the second quarter of 2006. Cooling degree days for the nine months ended September 30, 2006 were approximately 3% and 1% below both last year and the 10-year average, respectively. As a result, retail base revenues for the residential, small commercial and industrial and other public authorities customer classes increased primarily due to customer growth.

Retail base revenues increased by $10.5 million or 2.3% for the twelve months ended September 30, 2006 when compared to the same period in 2005. Residential base revenues increased by $4.4 million or 2.4% due to a 2.6% increase in kWh sales primarily due to an increase in the average number of residential customers served. The increase in retail base revenues was also due to increased kWh sales to small commercial and industrial customers and increased kWh sales to public authority customers of 1.7% and 3.6%, respectively, driven by growth in customers served.

Retail base revenue percentages by customer class are presented below:


	Three Months Ended September 30,				Nine Months Ended September 30,				Twelve Months Ended September 30,
	2006		2005		2006		2005		2006		2005
Residential	42	%	43	%	40	%	40	%	39	%	39	%
Commercial and industrial, small	35		34		36		35		36		36
Commercial and industrial, large	8		8		8		9		9		9
Sales to public authorities	15		15		16		16		16		16

Total base revenues	100	%	100	%	100	%	100	%	100	%	100	%

No retail customer accounted for more than 2% of our base revenues during such periods. As shown in the table above, residential and small commercial customers comprise approximately 75% of our revenues. While this customer base is more stable, it is also more sensitive to changes in weather conditions. As a result, our business is relatively more seasonal than some electric utilities, with higher kWh sales and revenues during the summer cooling season.

Heating and cooling degree days can be used to evaluate the effect of weather on energy use. For each degree the average outdoor temperature varies from a standard of 65 degrees Fahrenheit a degree day is recorded.

As shown in the table below, cooling degree days were below both the 10-year average and 2005 periods for the three, nine and twelve months ended September 30, 2006.


	Three Months Ended September 30,		10-Year Average	Nine Months Ended September 30,		10-Year Average	Twelve Months Ended September 30,		10-Year Average*
	2006	2005	10-Year Average	2006	2005	10-Year Average	2006	2005	10-Year Average*
Heating degree days	—	—	1	1,040	1,291	1,309	1,925	2,423	2,405
Cooling degree days	1,223	1,521	1,450	2,385	2,465	2,420	2,469	2,540	2,530

*	Calendar year basis for 2005 and 2004, respectively.

Fuel revenues. Fuel revenues consist of two parts: (i) revenues collected from customers under fuel recovery mechanisms approved by the state commissions, and (ii) deferred fuel revenues which are comprised of the difference between fuel costs and fuel revenues collected from customers. In New Mexico, the fuel adjustment clause allows us to reflect current fuel costs in the fuel clause and to recover under-recoveries or refund over-recoveries in the clause with a two-month lag with the exception of a cap on fuel costs for 10% of kWh sales. In Texas, fuel costs are recovered through a fixed fuel factor that may be adjusted two times per year. 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. Natural gas prices increased significantly in 2005. As a result, EPE significantly under-recovered fuel costs until it increased fixed fuel factors in Texas in October 2005 and February 2006.

In July 2005 we filed with the Texas Commission for an increase in our fixed fuel factor and to surcharge fuel under-recoveries. A settlement allowed us, beginning in October 2005, to increase our fixed fuel factor and to surcharge $53.6 million of fuel under-recoveries over a 24-month period. In January 2006, we again filed with the Texas Commission to increase our fixed fuel factor and surcharge approximately $34 million of additional fuel under-recoveries, including interest for the period of September through November 2005, over a twelve-month period. We received Texas Commission approval to implement the new fuel factor and surcharge on an interim basis beginning with February 2006 billings. Due to these increases in our fixed fuel factor and higher kWh sales, fuel revenues recovered from Texas customers increased $17.4 million, $45.4 million and $52.9 million for the three, nine and twelve month periods ending September 30, 2006 compared to the same periods in 2005. In addition, the amount of fuel under-recoveries deferred for future collection for both the Texas and New Mexico jurisdictions declined $32.9 million, $43.0 million and $12.0 million for the three, nine and twelve months ended September 30, 2006, respectively, compared to the same periods in 2005.

Off-system sales. Off-system sales are primarily made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations. Off-system kWh sales increased 5% for the three months ended September 30, 2006 compared to the same period last year. Off-system kWh sales declined 12% and 19% for the nine and twelve months ended September 30, 2006, respectively, when compared to the nine and twelve months ended September 30, 2005. Reduced output at Palo Verde resulted in a decline in available energy to sell in the off-system market during these periods.

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


						Increase (Decrease)
Quarter Ended September 30:	2006			2005		Amount			Percent
kWh sales:
Retail:
Residential		653,852			673,092		(19,240	)	(2.9	)%
Commercial and industrial, small		629,222			642,342		(13,120	)	(2.0	)
Commercial and industrial, large		317,599			309,002		8,597		2.8
Sales to public authorities		379,711			374,459		5,252		1.4

Total retail sales		1,980,384			1,998,895		(18,511	)	(0.9	)

Wholesale:
Sales for resale		12,323			12,800		(477	)	(3.7	)
Off-system sales		379,279			360,157		19,122		5.3

Total wholesale sales		391,602			372,957		18,645		5.0

Total kWh sales		2,371,986			2,371,852		134		0.0

Operating revenues:
Base revenues:
Retail:
Residential	$	58,262		$	59,599	$	(1,337	)	(2.2	)%
Commercial and industrial, small		48,373			48,030		343		0.7
Commercial and industrial, large		11,326			11,161		165		1.5
Sales to public authorities		21,126			20,747		379		1.8

Total retail base revenues (1)		139,087			139,537		(450	)	(0.3	)
Wholesale:
Sales for resale		501			508		(7	)	(1.4	)

Total base revenues		139,588			140,045		(457	)	(0.3	)

Fuel revenues:
Recovered from customers during the period		65,419			47,852		17,567		36.7	(2)(3)
Under (over) collection of fuel		(6,483	)		26,408		(32,891	)	(124.5	)(3)

Total fuel revenues		58,936			74,260		(15,324	)	(20.6	)
Off-system sales		24,263			23,640		623		2.6
Other		6,162			4,086		2,076		50.8	(4)(5)

Total operating revenues	$	228,949		$	242,031	$	(13,082	)	(5.4	)

Average number of retail customers:
Residential		309,299			301,580		7,719		2.6	%
Commercial and industrial, small		32,762			31,677		1,085		3.4
Commercial and industrial, large		59			60		(1	)	(1.7	)
Sales to public authorities		4,780			4,733		47		1.0

Total		346,900			338,050		8,850		2.6

(1)	Includes fuel recovered through New Mexico base rates of $8.9 million and $9.0 million for 2006 and 2005, respectively.

(2)	Excludes $17.4 million of prior periods deferred fuel revenues recovered through Texas fuel surcharges for the three months ended September 30, 2006.

(3)	Reflects increases in Texas fixed fuel factors in October 2005 and February 2006.

(4)	Primarily due to increased transmission revenues.

(5)	Represents revenues with no related kWh sales.


	2006		2005		Increase (Decrease)
Nine Months Ended September 30:	2006		2005		Amount			Percent
kWh sales:
Retail:
Residential		1,643,387		1,608,976		34,411		2.1	%
Commercial and industrial, small		1,659,965		1,631,809		28,156		1.7
Commercial and industrial, large		885,747		883,862		1,885		0.2
Sales to public authorities		1,024,746		977,947		46,799		4.8

Total retail sales		5,213,845		5,102,594		111,251		2.2

Wholesale:
Sales for resale		36,003		34,016		1,987		5.8
Off-system sales		1,055,256		1,193,299		(138,043	)	(11.6	)

Total wholesale sales		1,091,259		1,227,315		(136,056	)	(11.1	)

Total kWh sales		6,305,104		6,329,909		(24,805	)	(0.4	)

Operating revenues:
Base revenues:
Retail:
Residential	$	145,515	$	142,296	$	3,219		2.3	%
Commercial and industrial, small		130,192		126,964		3,228		2.5
Commercial and industrial, large		31,525		31,271		254		0.8
Sales to public authorities		57,912		55,883		2,029		3.6

Total retail base revenues		365,144		356,414		8,730		2.4
Wholesale:
Sales for resale		1,409		1,340		69		5.1

Total base revenues (1)		366,553		357,754		8,799		2.5

Fuel revenues:
Recovered from customers during the period		173,218		116,070		57,148		49.2	(2)(3)
Under (over) collection of fuel		1,472		44,461		(42,989	)	(96.7	)(3)

Total fuel revenues		174,690		160,531		14,159		8.8
Off-system sales		64,964		62,024		2,940		4.7
Other		16,967		10,207		6,760		66.2	(4)(5)

Total operating revenues	$	623,174	$	590,516	$	32,658		5.5

Average number of retail customers:
Residential		307,553		299,641		7,912		2.6	%
Commercial and industrial, small		32,483		31,462		1,021		3.2
Commercial and industrial, large		58		59		(1	)	(1.7	)
Sales to public authorities		4,800		4,618		182		3.9

Total		344,894		335,780		9,114		2.7

(1)	Includes fuel recovered through New Mexico base rates of $23.2 million and $22.6 million for 2006 and 2005, respectively.

(2)	Excludes $43.1 million of prior periods deferred fuel revenues recovered through Texas fuel surcharges for the nine months ended September 30, 2006.

(3)	Reflects increases in Texas fixed fuel factors in October 2005 and February 2006.

(4)	Primarily due to increased transmission revenues.

(5)	Represents revenues with no related kWh sales.


					Increase (Decrease)
Twelve Months Ended September 30:	2006		2005		Amount			Percent

kWh sales:
Retail:
Residential		2,124,509		2,071,353		53,156		2.6	%
Commercial and industrial, small		2,155,074		2,118,229		36,845		1.7
Commercial and industrial, large		1,167,391		1,189,639		(22,248	)	(1.9	)
Sales to public authorities		1,316,915		1,271,391		45,524		3.6

Total retail sales		6,763,889		6,650,612		113,277		1.7

Wholesale:
Sales for resale		43,870		41,194		2,676		6.5
Off-system sales		1,282,735		1,577,641		(294,906	)	(18.7	)

Total wholesale sales		1,326,605		1,618,835		(292,230	)	(18.1	)

Total kWh sales		8,090,494		8,269,447		(178,953	)	(2.2	)

Operating revenues:
Base revenues:
Retail:
Residential	$	186,886	$	182,476	$	4,410		2.4	%
Commercial and industrial, small		170,469		166,241		4,228		2.5
Commercial and industrial, large		41,575		41,881		(306	)	(0.7	)
Sales to public authorities		75,706		73,505		2,201		3.0

Total retail base revenues		474,636		464,103		10,533		2.3
Wholesale:
Sales for resale		1,756		1,622		134		8.3

Total base revenues (1)		476,392		465,725		10,667		2.3

Fuel revenues:
Recovered from customers during the period		221,648		149,152		72,496		48.6	(2)(3)
Under (over) collection of fuel		36,550		48,588		(12,038	)	(24.8	)(3)

Total fuel revenues		258,198		197,740		60,458		30.6
Off-system sales		81,149		79,684		1,465		1.8
Other		20,832		12,996		7,836		60.3	(4)(5)

Total operating revenues	$	836,571	$	756,145	$	80,426		10.6

Average number of retail customers:
Residential		306,515		299,374		7,141		2.4	%
Commercial and industrial, small		32,338		31,350		988		3.2
Commercial and industrial, large		59		60		(1	)	(1.7	)
Sales to public authorities		4,794		4,601		193		4.2

Total		343,706		335,385		8,321		2.5

(1)	Includes fuel recovered through New Mexico base rates of $30.0 million and $29.2 million for 2006 and 2005, respectively.

(2)	Excludes $49.1 million of prior periods deferred fuel revenues recovered through Texas fuel surcharges for the twelve months ended September 30, 2006.

(3)	Reflects increases in Texas fixed fuel factors in October 2005 and February 2006.

(4)	Primarily due to increased transmission revenues.

(5)	Represents revenues with no related kWh sales.

Energy expenses

Our sources of energy include electricity generated from nuclear fuel, natural gas and coal plants owned by the Company and purchased power. Palo Verde represents approximately 40% of our available net generating capacity and approximately 47%, 41% and 41%, respectively, of our available energy for the three, nine and twelve months ended September 30, 2006.

Energy expenses decreased $16.7 million for the three months ended September 30, 2006 when compared to 2005 due to lower natural gas prices and decreased natural gas generation. During the third quarter of 2006, we were able to displace gas-fired generation with increased purchases of economy energy in the wholesale power market. The average cost of purchased power in the three month period ended September 30, 2006 was $55.37 per megawatt-hour compared to our cost of generating power at our gas-fired generating plants of $79.83 per megawatt-hour. As a result, we purchased 40% more energy in the third quarter of 2006 compared to the third quarter of 2005. In addition, the average cost of purchased power in the third quarter of 2006 was approximately 25% lower than purchased power in the third quarter of 2005. Increased generation from our low-cost coal and nuclear generating plants also reduced fuel costs in the third quarter of 2006.

Energy expenses increased $15.3 million for the nine months ended September 30, 2006 when compared to 2005 primarily due to increased costs of purchased power of $36.5 million. We purchased 76% more energy in the first nine months of 2006 compared to the same period in 2005. The increase in purchased power expense was partially offset by a decrease in natural gas and nuclear fuel costs due to a decline in gas-fired and nuclear generation.

Energy expenses increased $58.6 million for the twelve months ended September 30, 2006 when compared to 2005 primarily due to increased costs of purchased power of $47.6 million as a result of increased volumes and higher market prices for power. In addition, the cost of natural gas increased $14.2 million due to higher gas costs which were almost 20% higher in the twelve months ended September 30, 2006 compared to the twelve months ended September 30, 2005.


	Three Months Ended September 30,
	2006					2005
Fuel Type	Cost		MWh	Cost per MWh		Cost			MWh	Cost per MWh
	(In thousands)					(In thousands)
Natural gas	$	52,948	663,225	$	79.83	$	72,709		847,711	$	85.77
Coal		3,197	209,090		15.29		3,139	(a)	206,882		15.17
Nuclear		6,473	1,195,808		5.41		5,901		1,165,294		5.06

Total		62,618	2,068,123		30.28		81,749		2,219,887		36.83
Purchased power		25,503	460,567		55.37		23,701		326,178		72.66

Total energy	$	88,121	2,528,690		34.85	$	105,450		2,546,065		41.42


	Nine Months Ended September 30,
	2006						2005
Fuel Type	Cost			MWh	Cost per MWh		Cost			MWh	Cost per MWh
	(In thousands)						(In thousands)
Natural gas	$	136,171	(b)	1,701,301	$	80.04	$	157,667	(c)	2,026,943	$	77.79
Coal		9,238		627,722		14.72		8,756	(a)	584,957		14.97
Nuclear		15,685		2,779,666		5.64		17,024		3,265,382		5.21

Total		161,094		5,108,689		31.53		183,447		5,877,282		31.21
Purchased power		91,127		1,689,201		53.95		54,642		958,133		57.03

Total energy	$	252,221		6,797,890		37.10	$	238,089		6,835,415		34.83


	Twelve Months Ended September 30,
	2006						2005
Fuel Type	Cost			MWh	Cost per MWh		Cost			MWh	Cost per MWh
	(In thousands)						(In thousands)
Natural gas	$	210,105	(b)	2,317,942	$	90.64	$	195,861	(c)	2,590,505	$	75.61
Coal		11,485		821,767		13.98		11,514	(d)	790,697		14.56
Nuclear		20,280		3,591,842		5.65		22,444		4,248,102		5.28

Total		241,870		6,731,551		35.93		229,819		7,629,304		30.12
Purchased power		116,525		1,989,537		58.57		68,965		1,290,659		53.43

Total energy	$	358,395		8,721,088		41.10	$	298,784		8,919,963		33.50

(a)	Excludes a reduction of $0.7 million to our coal reclamation liability recorded in the third quarter of 2005.

(b)	Excludes a fuel refund of $0.1 million.

(c)	Excludes a New Mexico Compensation Tax refund of $0.6 million.

(d)	Excludes an increase of $1.5 million to our coal reclamation liability.

Other operations expense

Other operations expense increased $2.0 million, or 4.4%, for the three months ended September 30, 2006 compared to the same period last year primarily due to increased Palo Verde operations expense of $1.7 million.

Other operations expense increased $6.2 million, or 4.7%, for the nine months ended September 30, 2006 compared to the same period last year primarily due to (i) increased Palo Verde operations expense of $3.2 million; (ii) increased transmission expense of $3.6 million primarily as the result of new wheeling contracts; (iii) increased customer accounts expense of $1.2 million due to increased bad debts, mailing and payroll costs; and (iv) increased outside services of $0.9 million. These increases were partially offset by decreased post-retirement benefit expenses of $2.8 million.

Other operations expense increased $5.3 million, or 3.0%, for the twelve months ended September 30, 2006 compared to the same period last year primarily due to (i) increased Palo Verde operations expense of $4.7 million; (ii) increased transmission expense of $5.0 million primarily as the result of new wheeling contracts; and (iii) increased customer accounts expense of $2.1 million. These increases were partially offset by decreased accruals for employee incentive payments of $5.3 million.

Maintenance expense

Maintenance expense increased $1.1 million, or 12.6%, for the three months ended September 30, 2006 compared to the same period last year primarily due to increased maintenance expense at our gas-fired generating plants of $0.6 million and increased maintenance on our transmission and distribution facilities of $0.5 million.

Maintenance expense increased $16.0 million, or 52.1%, for the nine months ended September 30, 2006 compared to the same period last year primarily due to (i) increased maintenance expense at Palo Verde of $8.0 million; and (ii) increased maintenance at our gas-fired generating plants of $6.5 million.

Maintenance expense increased $16.5 million, or 35.3%, for the twelve months ended September 30, 2006 compared to the same period last year primarily due to increased maintenance expense at Palo Verde of $8.4 million and at our gas-fired generating plants of $5.4 million.

Depreciation and amortization expense

Depreciation and amortization expense decreased $1.9 million, $15.2 million and $22.5 million for the three, nine and twelve months ended September 30, 2006, respectively, compared to the same periods last year primarily due to completing the recovery of certain fresh-start accounting related assets over the term of the Texas Rate Stipulation which ended in July 2005. The decrease was partially offset by higher depreciation due to increases in depreciable plant balances, primarily related to the replacement of Palo Verde Unit 1 steam generators in December 2005.

Taxes other than income taxes

Taxes other than income taxes increased by $2.6 million, $7.0 million and $11.1 million for the three, nine and twelve months ended September 30, 2006, respectively, compared to the same periods last year primarily due to an increase in the El Paso city franchise fees which took effect in August 2005 and higher taxable revenues due to increased kWh sales and increases in fuel recoveries.

Other income (deductions)

Other income (deductions) increased slightly for the three months ended September 30, 2006 compared to the same period last year. Other income (deductions) increased $18.8 million and $18.9 million for the nine and twelve months ended September 30, 2006 compared to the same periods last year primarily due to a decrease in the loss on extinguishment of debt of $19.4 million and $20.0 million, respectively, as a result of the retirement of our first mortgage bonds in the second quarter of 2005.

Interest charges (credits)

Interest charges (credits) increased $1.1 million for the three months ended September 30, 2006 compared to last year primarily due to an interest payment in the third quarter of 2006 of $0.8 million to the IRS due to timing of tax payments in prior years with no comparable activity in 2005.

Interest charges (credits) decreased $4.7 million and $8.9 million for the nine and twelve months ended September 30, 2006, respectively, compared to the same periods last year primarily due to a decrease of $5.8 million and $9.4 million, respectively, in interest on long-term debt and financing obligations resulting from (i) the repurchase and retirement of first mortgage bonds, (ii) the May 2005 issuance of unsecured senior notes at a lower interest rate than the first mortgage bonds, and (iii) the reissuance and remarketing of our pollution control bonds in August 2005 at lower interest rates.

Income tax expense

Income tax expense decreased $0.3 million for the three months ended September 30, 2006 when compared to the same period last year primarily due to the decrease in pretax income. For the nine months ended September 30, 2006 the increase in income tax expense of $4.0 million was due to increased pretax income and was partially offset by a $6.2 million adjustment of deferred income taxes. We recorded a $6.2 million reduction in deferred income tax expense to recognize the change in the tax rate from 4.5% to 1% and change in methodology resulting from a revision of the Texas franchise (income) tax law in the second quarter of 2006. For the twelve months ended September 30, 2006 income tax expense increased $7.3 million compared to the same period last year due to increased pretax income and a $6.2 million benefit from the IRS settlement recorded in the third quarter of 2004 offset by the $6.2 million reduction to deferred income taxes due to the change in Texas franchise (income) tax discussed above.

Cumulative effect of accounting change

The cumulative effect of accounting change for the twelve months ended September 30, 2006 of $1.1 million, net of tax, relates to the adoption of FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” (“FIN 47”) in December 2005. FIN 47 provides guidance on the recognition and measurement of liabilities associated with the retirement and disposal obligations of tangible long-lived assets not already accounted for under SFAS No. 143. FIN 47 affected the accounting for the disposal obligations related to our fuel oil storage tanks, water wells, evaporative ponds and asbestos at our gas-fired generating stations.

New accounting standards

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We do not believe SFAS No. 157 will have a significant impact on our consolidated financial statements.

measurement of the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. This statement is effective as of the end of the fiscal year ending after December 15, 2006. We will adopt the provisions of this statement in our financial statements for the year ending December 31, 2006. We have not completed the analysis of the ultimate impact this new pronouncement will have on our balance sheet.

In June 2006, the FASB issued FASB Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109.” FIN 48 clarifies the accounting for uncertainty in income taxes recognized in the financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 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 and provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We will adopt the provisions of this interpretation in our financial statements for the fiscal year beginning January 1, 2007. We have not completed the analysis of the ultimate impact this new pronouncement will have on our financial statements.

Liquidity and Capital Resources

Our principal liquidity requirements in the near-term are expected to consist of the interest payments on our indebtedness, capital expenditures related to our generating facilities and transmission and distribution systems, and operating expenses, including fuel costs and taxes. We expect that cash flows from operations will be sufficient for such purposes. As of September 30, 2006, we had approximately $61.8 million in cash and cash equivalents, an increase of $53.8 million from the balance of $8.0 million on December 31, 2005.

Capital Requirements. Substantial increases in the cost of natural gas during 2004 and 2005, and the delay in reflecting higher fuel costs in fixed fuel factors in Texas led to the under-recovery of the Texas jurisdictional portion of our fuel costs by $60.0 million, including interest, for the period from March 2004 to September 2005. In November 2005, the Texas Commission approved a settlement of a fuel factor filing which provided for (i) a surcharge over a 24-month period of fuel under-recoveries of $53.6 million, including interest through August 2005; and (ii) new fuel factors which reflect natural gas costs of $7.28 per MMBtu. We had previously been permitted to implement the increase in the fuel factor and the fuel surcharge on an interim basis beginning with October 2005 billings.

In January 2006, we filed a request with the Texas Commission for an additional increase in our fixed fuel factors and to surcharge over a twelve-month period approximately $34 million for fuel under-recoveries, including interest, for the period September 2005 to November 2005. The requested fuel factor and fuel surcharge were placed into effect on an interim basis subject to refund effective with February 2006 bills to customers. For the first nine months of 2006, we under-recovered fuel costs in Texas by approximately $4.7 million. However, we collected $43.1 million in fuel surcharges in the nine months ended September 2006, reducing our deferred fuel balance and increasing cash flow by $38.4 million. We should continue to realize increased cash flow as we collect these fuel surcharges during the remainder of 2006 and in 2007.

Our long-term liquidity requirements consist primarily of construction of electric utility plant and the payment of interest on debt. Projected utility construction expenditures will consist primarily of

expanding and updating the transmission and distribution systems, addition of new generation, and the cost of capital improvements and replacements at Palo Verde and other generating facilities, including the replacement of steam generators in Palo Verde Unit 3. See Part I, Item 1, “Business – Construction Program” in our 2005 Form 10-K. We expect that a significant portion of our construction expenditures will be financed with internal sources of funds through 2008.

During the twelve months ended September 30, 2006, we utilized $32.5 million of federal income tax loss carryforwards and $42.0 million of state income tax loss carryforwards as a result of deferred fuel costs collected from customers and other increases in taxable income. We anticipate that existing federal and state tax loss carryforwards will be fully utilized in 2006. Our future cash flow requirements for federal and state income taxes are expected to increase over that required in recent years.

We continually evaluate our funding requirements related to our retirement plans, other postretirement benefit plans, and decommissioning trust funds. We have contributed $11.2 million of the projected $13.7 million 2006 annual contribution to our retirement plans during the nine months ended September 30, 2006. We have also contributed $2.9 million of the projected $3.4 million 2006 annual contribution to our other postretirement benefit plan and $5.0 million of the projected $6.7 million 2006 annual contribution to our decommissioning trust funds during the nine months ended September 30, 2006.

In the third quarter of 2006, the Board of Directors (the “Board”) authorized the repurchase of up to 2.3 million shares of the Company’s outstanding common stock (the “2006 Plan”). The shares authorized under the 2006 Plan are in addition to the shares which were available under a buy back program previously approved by the Board in February 2004 (the “2004 Plan”). No common stock or long-term debt was repurchased during the first or second quarter of 2006. During the third quarter of 2006, the Company repurchased 1,798,100 shares of common stock at an aggregate cost of $41.4 million. As of September 30, 2006, no shares remain available under the 2004 Plan, and approximately 2.2 million shares remain authorized to be repurchased under the 2006 Plan.

We may in the future make purchases of our stock pursuant to our stock repurchase plan at open market prices and may engage in private transactions, where appropriate. The repurchased shares will be available for issuance under employee benefit and stock option plans, or may be retired. Common stock equity as a percentage of capitalization, including the current portion of long-term debt and financing obligations, was 47.5% as of September 30, 2006.

Capital Sources. As discussed in our 2005 Form 10-K, we issued senior notes in May 2005 to fund the reacquisition of our first mortgage bonds which resulted in significant savings in interest costs. In addition, in August 2005, we reissued and remarketed pollution control bonds resulting in a significant savings in interest costs.

While we maintain the ability to issue long-term debt, if needed, and to finance capital requirements, we expect to meet all our capital requirements during 2006 with internal sources of cash. Due to the increased volatility in the natural gas markets we decided to expand our existing revolving credit facility from $100 million to $150 million. The expansion came at a time of heightened competition in the bank markets resulting in lower borrowing costs under the new facility. The

revolving credit facility will continue to provide for up to $70 million for nuclear fuel purchases with any amounts not borrowed for nuclear fuel available for working capital purposes.

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 2005 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, 2006, there have been no material changes in the market risks we faced or the fair values of assets and liabilities disclosed in Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” in our 2005 Form 10-K.

Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures. During the period covered by this report, the Company’s chief executive officer and chief financial officer, after evaluating the effectiveness of the Company’s “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e)) as of September 30, 2006, (the “Evaluation Date”), concluded that as of the Evaluation Date, our disclosure controls and procedures (as required by paragraph (b) of the Securities Exchange Act of 1934 Rules 13a-15 or 15d-15) were adequate and designed to ensure that material information relating to us and our consolidated subsidiary would be made known to them by others within those entities.

Changes in internal control over financial reporting. In July 2006, we began outsourcing our payroll process to an applications service provider. Management took the necessary steps to maintain reasonable assurance that internal controls over financial reporting continued to function as designed during the conversion to the new process. In addition, management evaluated our internal controls over financial reporting after conversion to the new process to ensure that internal controls over financial reporting are and continue to operate effectively. Based on management’s review of our disclosure controls and procedures (as required by paragraph (b) of the Securities Exchange Act of 1934 Rules 13a-15 or 15d-15) management determined that such controls were adequate and designed to ensure that material information relating to us and our consolidated subsidiary would be made known to management by others within those entities.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

Our 2005 Form 10-K and our Form 10-Q Quarterly Reports for the quarters ended March 31, 2006 and June 30, 2006 include a detailed discussion of our risk factors.

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

(c) Issuer Purchases of Equity Securities.


Period	Total Number of Shares Purchased	Average Price Paid per Share (Including Commissions)		Total Number of Shares Purchased as Part of a Publicly Announced Program	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs (a) (b)
July 1 to July 31, 2006	0	$	—	0	1,705,158	(c)
August 1 to August 31, 2006	509,300		22.58	509,300	1,195,858
September 1 to September 30, 2006 (b)	1,288,800		23.19	1,288,800	2,207,058

(a)	In February 2004, the Company’s Board of Directors authorized a stock repurchase program permitting the repurchase of up to 2 million shares of its outstanding common stock.

(b)	In September 2006, the Company’s Board of Directors authorized a new stock repurchase program permitting the repurchase of up to 2.3 million additional shares of its outstanding common stock.

(c)	The number of shares that may be repurchased has been reduced from the number previously reported to include 44,842 shares repurchased from a director.

Item 6. Exhibits

See Index to Exhibits incorporated herein by reference.

SIGNATURES

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


		EL PASO ELECTRIC COMPANY

By:		/s/ SCOTT D. WILSON
		Scott D. Wilson
		Executive Vice President,
		Chief Financial Officer and
		Chief Administrative Officer
		(Duly Authorized Officer and
		Principal Financial Officer)

Dated: November 6, 2006

EL PASO ELECTRIC COMPANY

INDEX TO EXHIBITS


Exhibit Number		Exhibit

†10.07		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)

10.08		Settlement Agreement between the State of Texas and the Company, dated as of October 17, 2006

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


†		In lieu of non-employee director cash compensation, two agreements, dated as of October 1, 2006, substantially identical in all material respects to this Exhibit, have been entered into with Kenneth R. Heitz; and Patricia Z. Holland-Branch; directors of the Company.