Edgar Filing: EL PASO ELECTRIC CO /TX/

2014 June 10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_________________________________

Form 10-Q

(Mark One)



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

For the quarterly period ended June 30, 2014



o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from _______ to _______

Commission file number 001-14206

El Paso Electric Company

(Exact name of registrant as specified in its charter)



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

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

(915) 543-5711

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES x NO o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer	x	Accelerated filer	o

Non-accelerated filer	o	Smaller reporting company	o

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

As of July 31, 2014, there were 40,351,191 shares of the Company’s no par value common stock outstanding.

Table of Contents

EL PASO ELECTRIC COMPANY

INDEX TO FORM 10-Q



		Page No.
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
Balance Sheets – June 30, 2014 and December 31, 2013		1
Statements of Operations – Three Months, Six Months and Twelve Months Ended June 30, 2014 and 2013		3
Statements of Comprehensive Operations – Three Months, Six Months and Twelve Months Ended June 30, 2014 and 2013		5
Statements of Cash Flows – Six Months Ended June 30, 2014 and 2013		6
Notes to Financial Statements		7
Report of Independent Registered Public Accounting Firm		26
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41
Item 4.	Controls and Procedures	41
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43
Item 4.	Mine Safety Disclosures	43
Item 5.	Other Information	43
Item 6.	Exhibits	43



	( i)

Table of Contents

PART I. FINANCIAL INFORMATION


Item 1.	Financial Statements

EL PASO ELECTRIC COMPANY

BALANCE SHEETS



	June 30, 2014			December 31, 2013
	(Unaudited)

ASSETS (In thousands)
Utility plant:
Electric plant in service	$	3,113,909		$	3,076,549
Less accumulated depreciation and amortization	(1,233,926		)	(1,214,088		)
Net plant in service	1,879,983			1,862,461
Construction work in progress	347,412			282,647
Nuclear fuel; includes fuel in process of $46,404 and $48,492, respectively	184,110			188,185
Less accumulated amortization	(73,458		)	(75,820		)
Net nuclear fuel	110,652			112,365
Net utility plant	2,338,047			2,257,473
Current assets:
Cash and cash equivalents	12,696			25,592
Accounts receivable, principally trade, net of allowance for doubtful accounts of $1,738 and $2,261, respectively	98,935			65,350
Accumulated deferred income taxes	6,838			26,965
Inventories, at cost	45,400			45,942
Undercollection of fuel revenues	19,569			7,248
Prepayments and other	11,453			7,694
Total current assets	194,891			178,791
Deferred charges and other assets:
Decommissioning trust funds	225,713			214,095
Regulatory assets	97,319			101,050
Other	33,052			34,879
Total deferred charges and other assets	356,084			350,024
Total assets	$	2,889,022		$	2,786,288

See accompanying notes to financial statements.



	1

Table of Contents

EL PASO ELECTRIC COMPANY

BALANCE SHEETS (Continued)



	June 30, 2014			December 31, 2013
	(Unaudited)
CAPITALIZATION AND LIABILITIES (In thousands except for share data)
Capitalization:
Common stock, stated value $1 per share, 100,000,000 shares authorized, 65,706,047 and 65,639,091 shares issued, and 138,896 and 120,534 restricted shares, respectively	$	65,845		$	65,760
Capital in excess of stated value	316,493			314,443
Retained earnings	998,407			985,665
Accumulated other comprehensive income, net of tax	17,730			2,612
	1,398,475			1,368,480
Treasury stock, 25,492,919 shares at cost	(424,647		)	(424,647		)
Common stock equity	973,828			943,833
Long-term debt	999,665			999,620
Total capitalization	1,973,493			1,943,453
Current liabilities:
Short-term borrowings under the revolving credit facility	97,772			14,352
Accounts payable, principally trade	66,008			61,795
Taxes accrued	20,838			25,206
Interest accrued	12,225			12,189
Overcollection of fuel revenues	—			1,048
Other	25,268			22,932
Total current liabilities	222,111			137,522
Deferred credits and other liabilities:
Accumulated deferred income taxes	455,620			449,925
Accrued pension liability	60,070			84,012
Accrued postretirement benefit liability	53,256			50,655
Asset retirement obligation	68,115			65,214
Regulatory liabilities	26,116			26,416
Other	30,241			29,091
Total deferred credits and other liabilities	693,418			705,313
Commitments and contingencies
Total capitalization and liabilities	$	2,889,022		$	2,786,288

See accompanying notes to financial statements.



	2

Table of Contents

EL PASO ELECTRIC COMPANY

STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands except for share data)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Operating revenues	$	251,801		$	240,114		$	437,317		$	417,404
Energy expenses:
Fuel	69,672			61,430			121,258			105,829
Purchased and interchanged power	18,128			15,913			36,043			28,790
	87,800			77,343			157,301			134,619
Operating revenues net of energy expenses	164,001			162,771			280,016			282,785
Other operating expenses:
Other operations	60,285			59,033			116,423			115,000
Maintenance	15,945			15,985			30,227			28,537
Depreciation and amortization	21,083			19,562			41,651			38,930
Taxes other than income taxes	15,557			13,847			30,919			26,629
	112,870			108,427			219,220			209,096
Operating income	51,131			54,344			60,796			73,689
Other income (deductions):
Allowance for equity funds used during construction	3,461			2,515			6,367			5,178
Investment and interest income, net	1,923			1,834			6,164			3,065
Miscellaneous non-operating income	590			1			2,107			2
Miscellaneous non-operating deductions	(599		)	(1,633		)	(1,018		)	(2,104		)
	5,375			2,717			13,620			6,141
Interest charges (credits):
Interest on long-term debt and revolving credit facility	14,607			14,610			29,186			29,206
Other interest	288			154			461			303
Capitalized interest	(1,281		)	(1,307		)	(2,527		)	(2,609		)
Allowance for borrowed funds used during construction	(1,967		)	(1,518		)	(3,651		)	(3,141		)
	11,647			11,939			23,469			23,759
Income before income taxes	44,859			45,122			50,947			56,071
Income tax expense	14,763			15,929			16,236			19,244
Net income	$	30,096		$	29,193		$	34,711		$	36,827

Basic earnings per share	$	0.75		$	0.73		$	0.86		$	0.92

Diluted earnings per share	$	0.75		$	0.72		$	0.86		$	0.92

Dividends declared per share of common stock	$	0.28		$	0.265		$	0.545		$	0.515
Weighted average number of shares outstanding	40,180,569			40,111,757			40,164,913			40,095,002
Weighted average number of shares and dilutive potential shares outstanding	40,212,403			40,159,970			40,180,830			40,119,109

See accompanying notes to financial statements.



	3

Table of Contents

EL PASO ELECTRIC COMPANY

STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands except for share data)



	Twelve Months Ended
	June 30,
	2014			2013
Operating revenues	$	910,275		$	873,455
Energy expenses:
Fuel	242,197			208,105
Purchased and interchanged power	69,616			61,960
	311,813			270,065
Operating revenues net of energy expenses	598,462			603,390
Other operating expenses:
Other operations	238,578			238,336
Maintenance	62,758			58,102
Depreciation and amortization	82,347			77,365
Taxes other than income taxes	62,037			55,794
	445,720			429,597
Operating income	152,742			173,793
Other income (deductions):
Allowance for equity funds used during construction	11,197			10,435
Investment and interest income, net	10,132			6,462
Miscellaneous non-operating income	3,014			1,216
Miscellaneous non-operating deductions	(2,549		)	(3,214		)
	21,794			14,899
Interest charges (credits):
Interest on long-term debt and revolving credit facility	58,615			56,670
Other interest	589			1,015
Capitalized interest	(5,217		)	(5,253		)
Allowance for borrowed funds used during construction	(6,565		)	(6,251		)
	47,422			46,181
Income before income taxes	127,114			142,511
Income tax expense	40,647			49,076
Net income	$	86,467		$	93,435

Basic earnings per share	$	2.15		$	2.33

Diluted earnings per share	$	2.15		$	2.32

Dividends declared per share of common stock	$	1.075		$	1.015
Weighted average number of shares outstanding	40,149,261			40,053,677
Weighted average number of shares and dilutive potential shares outstanding	40,157,220			40,104,513

See accompanying notes to financial statements.



	4

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EL PASO ELECTRIC COMPANY

STATEMENTS OF COMPREHENSIVE OPERATIONS

(Unaudited)

(In thousands)



	Three Months Ended						Six Months Ended						Twelve Months Ended
	June 30,						June 30,						June 30,
	2014			2013			2014			2013			2014			2013
Net income	$	30,096		$	29,193		$	34,711		$	36,827		$	86,467		$	93,435
Other comprehensive income (loss):
Unrecognized pension and postretirement benefit costs:
Net gain (loss) arising during period	—			—			19,700			—			102,664			(2,109		)
Prior service benefit	—			—			—			—			97			—
Reclassification adjustments included in net income for amortization of:
Prior service benefit	(2,070		)	(1,400		)	(3,529		)	(2,800		)	(6,289		)	(5,682		)
Net loss	1,829			2,745			2,952			5,420			8,004			11,406
Net unrealized gains/losses on marketable securities:
Net holding gains (losses) arising during period	6,070			(2,232		)	7,068			4,561			20,206			8,671
Reclassification adjustments for net gains included in net income	(102		)	(246		)	(2,967		)	(88		)	(3,432		)	(280		)
Net losses on cash flow hedges:
Reclassification adjustment for interest expense included in net income	109			101			216			202			425			398
Total other comprehensive income (loss) before income taxes	5,836			(1,032		)	23,440			7,295			121,675			12,404
Income tax benefit (expense) related to items of other comprehensive income (loss):
Unrecognized pension and postretirement benefit costs	90			(511		)	(7,332		)	(1,081		)	(39,817		)	(1,449		)
Net unrealized losses (gains) on marketable securities	(1,215		)	650			(858		)	(637		)	(3,321		)	(1,705		)
Losses on cash flow hedges	(40		)	(38		)	(132		)	(90		)	(210		)	(140		)
Total income tax benefit (expense)	(1,165		)	101			(8,322		)	(1,808		)	(43,348		)	(3,294		)
Other comprehensive income (loss), net of tax	4,671			(931		)	15,118			5,487			78,327			9,110
Comprehensive income	$	34,767		$	28,262		$	49,829		$	42,314		$	164,794		$	102,545

See accompanying notes to financial statements.



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EL PASO ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)



	Six Months Ended
	June 30,
	2014			2013
Cash flows from operating activities:
Net income	$	34,711		$	36,827
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service	41,651			38,930
Amortization of nuclear fuel	21,877			21,897
Deferred income taxes, net	15,141			16,888
Allowance for equity funds used during construction	(6,367		)	(5,178		)
Other amortization and accretion	9,145			8,258
Gain on sale of property, plant and equipment	(2,083		)	—
Other operating activities	(3,031		)	(87		)
Change in:
Accounts receivable	(33,585		)	(43,626		)
Inventories	(100		)	(2,047		)
Net undercollection of fuel revenues	(13,369		)	(8,940		)
Prepayments and other	(6,691		)	(8,022		)
Accounts payable	1,983			2,733
Other current liabilities	428			900
Deferred charges and credits	(2,739		)	(7,146		)
Net cash provided by operating activities	56,971			51,387
Cash flows from investing activities:
Cash additions to utility property, plant and equipment	(105,999		)	(110,279		)
Cash additions to nuclear fuel	(17,690		)	(16,879		)
Capitalized interest and AFUDC:
Utility property, plant and equipment	(10,018		)	(8,319		)
Nuclear fuel	(2,527		)	(2,609		)
Allowance for equity funds used during construction	6,367			5,178
Decommissioning trust funds:
Purchases, including funding of $2.3 million	(40,924		)	(26,914		)
Sales and maturities	36,374			22,362
Proceeds from sale of property, plant and equipment	2,377			—
Other investing activities	1,650			3,419
Net cash used for investing activities	(130,390		)	(134,041		)
Cash flows from financing activities:
Dividends paid	(21,969		)	(20,714		)
Borrowings under the revolving credit facility:
Proceeds	142,951			28,486
Payments	(59,531		)	(24,322		)
Other financing activities	(928		)	(207		)
Net cash provided by (used for) financing activities	60,523			(16,757		)
Net decrease in cash and cash equivalents	(12,896		)	(99,411		)
Cash and cash equivalents at beginning of period	25,592			111,057
Cash and cash equivalents at end of period	$	12,696		$	11,646

See accompanying notes to financial statements.



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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

A. Principles of Preparation

These condensed financial statements should be read in conjunction with the financial statements and notes thereto in the Annual Report of El Paso Electric Company on Form 10-K for the year ended December 31, 2013 (the "2013 Form 10-K"). Capitalized terms used in this report and not defined herein have the meaning ascribed to such terms in the 2013 Form 10-K. In the opinion of the Company’s management, the accompanying financial statements contain all adjustments necessary to present fairly the financial position of the Company at June 30, 2014 and December 31, 2013; the results of its operations and comprehensive operations for the three, six and twelve months ended June 30, 2014 and 2013; and its cash flows for the six months ended June 30, 2014 and 2013. The results of operations and comprehensive operations for the three and six months ended June 30, 2014 and the cash flows for the six months ended June 30, 2014 are not necessarily indicative of the results to be expected for the full calendar year.

Pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC"), certain financial information has been condensed and certain footnote disclosures have been omitted. Such information and disclosures are normally included in financial statements prepared in accordance with generally accepted accounting principles.

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

Revenues. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated based on monthly generation volumes and by applying an average revenue/kWh to the number of estimated kWhs delivered but not billed. Accounts receivable included accrued unbilled revenues of $34.5 million at June 30, 2014 and $19.8 million at December 31, 2013. The Company presents revenues net of sales taxes in its statements of operations.



Supplemental Cash Flow Disclosures (in thousands)
		Six Months Ended
		June 30,
		2014		2013
Cash paid (received) for:
	Interest on long-term debt and borrowing under the revolving credit facility	$	27,216	$	26,840
	Income tax paid (refunded), net	2,862		(169		)
Non-cash financing activities:
	Grants of restricted shares of common stock	2,930		2,483
	Issuance of performance shares	—		849

New Accounting Standards. In July 2013, the Financial Accounting Standards Board ("FASB") issued new guidance (Accounting Standards Update ("ASU") 2013-11, Income Taxes (Topic 740)) to eliminate the diversity in the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 requires an entity to present an unrecognized tax benefit in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except in certain circumstances when it would be reflected as a liability. The Company implemented ASU 2013-11 in the first quarter of 2014 on a prospective basis. This ASU did not have a significant impact on the Company's statement of operations or statement of cash flows.

In May 2014, the FASB issued new guidance (ASU 2014-09, Revenue from Contracts with Customers (Topic 606)) to provide a framework that replaces the existing revenue recognition guidance. ASU 2014-09 is the result of a joint effort by the FASB and the International Accounting Standards Board (IASB) intended to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. Generally Accepted Accounting Standards ("GAAP") and International Financial



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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

Reporting Standards. ASU 2014-09 provides that an entity should recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 is effective for annual periods and interim periods within that reporting period beginning after December 15, 2016, for public business entities. Early adoption of ASU 2014-09 is not permitted. The Company is currently assessing the future impact of this ASU.



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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

B. Accumulated Other Comprehensive Income (Loss)



Changes in Accumulated Other Comprehensive Income (Loss) (net of tax) by component are presented below (in thousands):
		Three Months Ended June 30, 2014												Three Months Ended June 30, 2013
		Unrecognized Pension and Postretirement Benefit Costs			Net Unrealized Gains (Losses) on Marketable Securities			Net Losses on Cash Flow Hedges			Accumulated Other Comprehensive Income (Loss)			Unrecognized Pension and Postretirement Benefit Costs			Net Unrealized Gains (Losses) on Marketable Securities			Net Losses on Cash Flow Hedges			Accumulated Other Comprehensive Income (Loss)

Balance at beginning of period		$	(9,388	)	$	34,730		$	(12,283	)	$	13,059		$	(75,032	)	$	27,858		$	(12,492	)	$	(59,666	)
	Other comprehensive income (loss) before reclassifications	—			4,845			—			4,845			—			(1,623		)	—			(1,623		)
	Amounts reclassified from accumulated other comprehensive income (loss)	(151		)	(92		)	69			(174		)	834			(205		)	63			692
Balance at end of period		$	(9,539	)	$	39,483		$	(12,214	)	$	17,730		$	(74,198	)	$	26,030		$	(12,429	)	$	(60,597	)

		Six Months Ended June 30, 2014												Six Months Ended June 30, 2013
		Unrecognized Pension and Postretirement Benefit Costs			Net Unrealized Gains (Losses) on Marketable Securities			Net Losses on Cash Flow Hedges			Accumulated Other Comprehensive Income (Loss)			Unrecognized Pension and Postretirement Benefit Costs			Net Unrealized Gains (Losses) on Marketable Securities			Net Losses on Cash Flow Hedges			Accumulated Other Comprehensive Income (Loss)

Balance at beginning of period		$	(21,330	)	$	36,240		$	(12,298	)	$	2,612		$	(75,737	)	$	22,194		$	(12,541	)	$	(66,084	)
	Other comprehensive income before reclassifications	12,147			5,644			—			17,791			—			3,920			—			3,920
	Amounts reclassified from accumulated other comprehensive income (loss)	(356		)	(2,401		)	84			(2,673		)	1,539			(84		)	112			1,567
Balance at end of period		$	(9,539	)	$	39,483		$	(12,214	)	$	17,730		$	(74,198	)	$	26,030		$	(12,429	)	$	(60,597	)

		Twelve Months Ended June 30, 2014												Twelve Months Ended June 30, 2013
		Unrecognized Pension and Postretirement Benefit Costs			Net Unrealized Gains (Losses) on Marketable Securities			Net Losses on Cash Flow Hedges			Accumulated Other Comprehensive Income (Loss)			Unrecognized Pension and Postretirement Benefit Costs			Net Unrealized Gains (Losses) on Marketable Securities			Net Losses on Cash Flow Hedges			Accumulated Other Comprehensive Income (Loss)

Balance at beginning of period		$	(74,198	)	$	26,030		$	(12,429	)	$	(60,597	)	$	(76,364	)	$	19,344		$	(12,687	)	$	(69,707	)
	Other comprehensive income (loss) before reclassifications	63,518			16,206			—			79,724			(1,264		)	6,944			—			5,680
	Amounts reclassified from accumulated other comprehensive income (loss)	1,141			(2,753		)	215			(1,397		)	3,430			(258		)	258			3,430
Balance at end of period		$	(9,539	)	$	39,483		$	(12,214	)	$	17,730		$	(74,198	)	$	26,030		$	(12,429	)	$	(60,597	)



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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

Amounts reclassified from accumulated other comprehensive income (loss) for the three, six and twelve months ended June 30, 2014 and 2013 are as follows ( in thousands):



Details about Accumulated Other Comprehensive Income (Loss) Components		Three Months Ended June 30,						Six Months Ended June 30,						Twelve Months Ended June 30,						Affected Line Item in the Statement of Operations
		2014			2013			2014			2013			2014			2013			Affected Line Item in the Statement of Operations

Amortization of pension and postretirement benefit costs:
	Prior service benefit	$	2,070		1,400			$	3,529		2,800			$	6,289		$	5,682		(a)
	Net loss	(1,829		)	(2,745		)	(2,952		)	(5,420		)	(8,004		)	(11,406		)	(a)
		241			(1,345		)	577			(2,620		)	(1,715		)	(5,724		)	(a)
	Income tax effect	(90		)	511			(221		)	1,081			574			2,294
		151			(834		)	356			(1,539		)	(1,141		)	(3,430		)	(a)

Marketable securities:
	Net realized gain on sale of securities	102			246			2,967			88			3,432			593			Investment and interest income, net
	Unrealized losses on available-for-sale securities included in pre-tax income	—			—			—			—			—			(313		)	Investment and interest income, net
		102			246			2,967			88			3,432			280			Income before income taxes
		(10		)	(41		)	(566		)	(4		)	(679		)	(22		)	Income tax expense
		92			205			2,401			84			2,753			258			Net income

Loss on cash flow hedge:
	Amortization of loss	(109		)	(101		)	(216		)	(202		)	(425		)	(398		)	Interest on long-term debt and revolving credit facility
		(109		)	(101		)	(216		)	(202		)	(425		)	(398		)	Income before income taxes
		40			38			132			90			210			140			Income tax expense
		(69		)	(63		)	(84		)	(112		)	(215		)	(258		)	Net income

	Total reclassifications	$	174		$	(692	)	$	2,673		$	(1,567	)	$	1,397		$	(3,430	)

(a) These items are included in the computation of net periodic benefit cost. See Note I, Employee Benefits, for additional information.



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C. Regulation

General

The rates and services of the Company are regulated by incorporated municipalities in Texas, the Public Utility Commission of Texas ("PUCT"), the New Mexico Public Regulation Commission ("NMPRC"), and the Federal Energy Regulatory Commission ("FERC"). The PUCT and the NMPRC have jurisdiction to review municipal orders, ordinances and utility agreements regarding rates and services within their respective states and over certain other activities of the Company. The FERC has jurisdiction over the Company's wholesale (sales for resale) transactions, transmission service and compliance with federally-mandated reliability standards. The decisions of the PUCT, NMPRC and the FERC are subject to judicial review.

Texas Regulatory Matters

2012 Texas Retail Rate Settlement. On April 17, 2012, the El Paso City Council approved the settlement of the Company's 2012 Texas retail rate case and fuel reconciliation in PUCT Docket No. 40094. The PUCT issued a final order approving the settlement on May 23, 2012 and the rates were effective as of May 1, 2012. As part of the 2012 Texas retail rate settlement, the Company agreed to submit a future fuel reconciliation request covering the period beginning July 1, 2009 and ending no later than June 30, 2013 by December 31, 2013 or as part of its next rate case, if earlier. The Company filed a fuel reconciliation request covering the period July 1, 2009 through March 31, 2013, as later discussed. The 2012 Texas retail rate settlement also provided for the continuation of the energy efficiency cost recovery factor and the military base discount recovery factor. Both of these surcharges require annual filings to reconcile and revise the recovery factors.

Fuel and Purchased Power Costs. The Company's actual fuel costs, including purchased power energy costs, are recovered from customers through a fixed fuel factor. The PUCT has adopted a fuel cost recovery rule ( the "Texas Fuel Rule") that allows the Company to seek periodic adjustments to its fixed fuel factor. The Company can seek to revise its fixed fuel factor based upon the approved formula at least four months after its last revision except in the month of December. On April 15, 2014, the Company filed a request, which was assigned Docket No. 42384, to increase its fixed fuel factor by $10.7 million or 6.9% annually, pursuant to its approved formula. The revised fixed fuel factor reflects increases in prices for natural gas. The increase in the fixed fuel factor received final approval on May 28, 2014 and was effective with May 2014 billings.

Fuel Reconciliation Proceeding. Pursuant to the 2012 Texas retail rate settlement discussed above, on September 27, 2013, the Company filed an application with the PUCT, designated as Docket No. 41852, to reconcile $545.3 million of fuel and purchased power expenses incurred during the 45-month period from July 1, 2009 through March 31, 2013. A settlement was reached and a final order was issued by the PUCT on July 11, 2014. The quarter ended June 30, 2014 financial results includes a $2.1 million, pre-tax increase to income reflecting the settlement of the Texas fuel reconciliation proceeding. The settlement included the recognition of $3.4 million of Palo Verde performance rewards associated with the 2009 to 2012 performance periods net of disallowed fuel and purchased power costs of $1.75 million of which $0.5 million had been reserved. Palo Verde performance rewards are not recorded on the Company's books until the PUCT has ordered a final determination in a fuel proceeding or comparable evidence of collectability is obtained. In addition, the Company reimbursed intervenors approximately $0.1 million in incurred expenses. The settlement provided for the current mine reclamation costs related to the Four Corners generating units to continue in the amount of approximately $70 thousand per month. The Company also agreed to file a request in a separate proceeding for a PUCT finding on the reasonableness of its decision to not continue participation in Four Corners Units 4 & 5 after July 2016 after the Company enters into an agreement containing the terms of the disposition. The settlement provides that 100% of margins on non-arbitrage sales (as defined by the settlement) and 50% of margins on arbitrage sales be shared with its Texas customers beginning April 1, 2014. For the period April 1, 2014 through June 30, 2015, the Company's total share of margins assignable to Texas retail jurisdiction, on arbitrage and non-arbitrage off-system sales, may not exceed 10% of the total margins assignable to the Texas retail jurisdiction on all off-system sales. The final order completes the regulatory review and reconciliation of the Company's fuel expenses for the period through March 31, 2013.

Montana Power Station Approvals. As discussed further below, the Company has received a Certificate of Convenience and Necessity ("CCN") from the PUCT to construct all four units of the Montana Power Station ("the MPS"). The Company also obtained air permits from state and federal regulatory agencies. None of the air permits were appealed to the courts and they have now become final.

On June 23, 2014, the U.S. Supreme Court issued an opinion in the Utility Air Regulatory Group vs EPA regarding EPA's authority to require greenhouse gas emissions ("GHG") Prevention of Significant Deterioration ("PSD") permits for stationary sources. The opinion concluded that EPA erred in making applicability of the Clean Air Act ("CAA") permitting requirements



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based on GHG emissions, but reasonably interpreted the CAA to require sources that would need PSD permits based on their emission of criteria pollutants to comply with "best available control technology" for GHG. As a result the Company believes its EPA air permit is no longer required and could be rescinded. The Company is analyzing the impact of this decision on its air permits recently issued for the Montana Power Station, as well as the benefits it may provide to approvals for future projects.

On December 13, 2012, in PUCT Docket No. 40301, the Company received CCN approval from the PUCT for MPS Units 1 and 2. On September 6, 2013, the Company filed an application with the PUCT for issuance of a CCN to construct, own and operate two additional 88 MW natural gas-fired generating units designated as the MPS Units 3 and 4 in El Paso County, Texas. The case was designated PUCT Docket No. 41763. Hearings in this case were held before an Administrative Law Judge ("ALJ") in February 2014. On July 11, 2014, the PUCT approved the CCN to construct MPS Units 3 and 4.

The Company filed three transmission line CCN applications with the PUCT as part of the MPS Project:


•	MPS to Caliente: a 115-kV transmission line from the MPS to the existing Caliente Substation in east El Paso. (PUCT Docket No. 41360)


•	MPS In & Out: a 115-kV transmission line from the MPS to intersect with the existing Caliente - Coyote 115-kV transmission line. (PUCT Docket No. 41359)


•	MPS to Montwood: a 115-kV transmission line from the MPS to the existing Montwood Substation in east El Paso. (PUCT Docket No. 41809)

The transmission CCN filings for both the MPS to Caliente line and the MPS In & Out line were filed on April 15, 2013, and the transmission CCN filing for the MPS to Montwood line was filed on September 24, 2013. The Company is requesting to build these transmission lines to connect the new MPS to the electrical grid in order to meet expected customer growth and electric demand and to improve system reliability. A final order approving a unanimous settlement in the MPS to Caliente transmission CCN filing was received on March 10, 2014. Unopposed settlements providing for approval of the MPS In & Out line and the MPS to Montwood line were filed with the PUCT on June 23, 2014. The PUCT is scheduled to consider final orders to approve the settlements on August 7, 2014.

Other Required Approvals. The Company has obtained other required approvals for recovery of fuel costs through fixed fuel factors, other tariffs and approvals as required by the Public Utility Regulatory Act (the "PURA") and the PUCT.

New Mexico Regulatory Matters

2009 New Mexico Stipulation. On December 10, 2009, the NMPRC issued a final order conditionally approving the stipulated rates in NMPRC Case No. 09-00171-UT. The stipulated rates went into effect with January 2010 bills. The stipulated rates provide for an Efficient Use of Energy Factor Rate Rider to recover energy efficiency expenditures which requires an annual filing and approval of the related costs and incentives and any necessary adjustments to the recovery factors.

Fuel and purchased power costs in New Mexico are recovered through a Fuel and Purchased Power Cost Adjustment Clause (the "FPPCAC"). On January 8, 2014, the NMPRC approved the continuation of the FPPCAC without modification in NMPRC Case No. 13-00380-UT. The Company recovers its investment in Palo Verde Unit 3 in New Mexico through the FPPCAC as purchased power using a proxy market price approved in the 2009 New Mexico rate stipulation.

Montana Power Station Approvals. The Company has received a CCN from the NMPRC to construct all four units of the MPS. The Company obtained air permits from the TCEQ and EPA as explained above. On September 6, 2013, the Company filed an application with the NMPRC for issuance of a CCN to construct, own and operate two additional 88 MW natural gas-fired generating units designated as the MPS Units 3 and 4 in El Paso County, Texas. The case was designated NMPRC Case No. 13-00297-UT. A final order approving the Company's application was issued on June 11, 2014.

Revolving Credit Facility, Issuance of Long-Term Debt and Guarantee of Debt. On October 30, 2013, the Company received approval in NMPRC Case No. 13-00317-UT to amend its current $300 million Revolving Credit Facility ("RCF") to include an option, subject to lender's approval, to expand the amount of the potential borrowings available under the facility to $400 million and extend the maturity date by up to four years; issue up to $300 million in new long-term debt; and to guarantee the issuance of up to $50 million of new debt by Rio Grande Resources Trust ("RGRT") to finance future purchases of nuclear fuel and to refinance existing debt obligations related to the financing of purchases of nuclear fuel.

On January 14, 2014, the Company and RGRT entered into a second amended and restated credit agreement related to the



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RCF with JP Morgan Chase Bank, N.A., as administrative agent and issuing bank, and Union Bank, N.A., as syndication agent, and various lending banks party thereto. Under the terms of the agreement, the Company has available $300 million and the ability to increase the RCF by up to $100 million (up to a total of $400 million) upon the satisfaction of certain conditions, more fully set forth in the agreement, including obtaining commitments from lenders or third party financial institutions. The RCF has a term ending January 2019. The Company may extend the maturity date up to two times, in each case for an additional one year period upon the satisfaction of certain conditions.

Other Required Approvals. The Company has obtained other required approvals for other tariffs, securities transactions, long-term resource plans, recovery of energy efficiency costs through a base rate rider and other approvals as required by the NMPRC.

Federal Regulatory Matters

Public Service Company of New Mexico's ("PNM") 2010 Transmission Rate Case. On October 27, 2010, PNM filed a Notice of Transmission Rate Change for transmission delivery services provided by PNM. These rates went into effect on June 1, 2011. The Company takes transmission service from PNM. On January 2, 2013, the FERC issued a letter order approving a unanimous stipulation and agreement. Pursuant to the stipulation, on January 31, 2013, PNM refunded $1.9 million, for amounts that PNM collected since June 1, 2011, in excess of settlement rates. This amount was recorded in the fourth quarter of 2012 as a reduction of transmission expense.

Revolving Credit Facility, Issuance of Long-Term Debt and Guarantee of Debt. On November 15, 2013, the FERC issued an order in Docket No. ES13-59-000 approving the Company's filing to amend its current $300 million RCF to include an option, subject to lender's approval, to expand the amount of the potential borrowings available under the facility to $400 million and extend the maturity date by up to four years; issue up to $300 million in new long-term debt; and to guarantee the issuance of up to $50 million of new debt by RGRT to finance future purchases of nuclear fuel and to refinance existing debt obligations related to the purchase of nuclear fuel. As noted above, on January 14, 2014, the Company and RGRT entered into a second amended and restated credit agreement related to the RCF.

Other Required Approvals. The Company has obtained required approvals for rates and tariffs, securities transactions and other approvals as required by the FERC.



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D. Palo Verde

Spent Nuclear Fuel and Waste Disposal

Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "NWPA"), the United States Department of Energy ("DOE") is legally obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive waste generated by all domestic power reactors by 1998. The DOE's obligations are reflected in a contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (the "Standard Contract") with each nuclear power plant. The DOE failed to begin accepting spent nuclear fuel by 1998. On December 19, 2012, Arizona Public Service Company ("APS"), acting on behalf of itself and the participant owners of Palo Verde, filed a breach of contract lawsuit against the DOE in the United States Court of Federal Claims ("Court of Federal Claims"). On April 21, 2014, the Court of Federal Claims ruled in favor of APS and awarded APS and the other Palo Verde Participants a one-time payment of approximately $57 million for its claim for spent nuclear fuel related damages from January 1, 2007 through June 30, 2011, and reimbursement for certain ongoing future spent nuclear fuel storage costs through at least 2016 through an annual claims submission process. The Company is expected to receive in the second half of 2014 approximately $9 million, representing its share of the award and anticipates that the majority of the award will be refunded to customers through the applicable fuel adjustment clauses.

The One-Mill Fee. In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged DOE's 2010 determination of the adequacy of the one tenth of a cent per kWh fee (the "one-mill fee") paid by the nation's commercial nuclear power plant owners pursuant to their individual obligations under the Standard Contract. This fee is recovered by the Company through applicable fuel adjustment clauses. In June 2012, the U.S. Court of Appeals for the District of Columbia Circuit (the "D.C. Circuit") held that DOE failed to conduct a sufficient fee analysis in making the 2010 determination. The D.C. Circuit remanded the 2010 determination to the Secretary of the DOE ("Secretary") with instructions to conduct a new fee adequacy determination within six months. In February 2013, upon completion of the DOE's revised one-mill fee adequacy determination, the court reopened the proceedings. On November 19, 2013, the D.C. Circuit ordered the Secretary to notify Congress of his intent to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators, as he is required to do pursuant to the NWPA and the court's order. On January 3, 2014, the Secretary notified Congress of his intention to suspend collection of the one-mill fee, subject to Congress' disapproval and on May 12, 2014, APS was notified by the DOE that, effective May 16, 2014, the one-mill fee would be suspended. Electricity generated and sold prior to May 16, 2014 remained subject to the one-mill fee.



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E. Common Stock

Dividend Policy. The Company paid $11.3 million and $10.7 million in quarterly cash dividends during the three months ended June 30, 2014 and 2013, respectively. The Company paid a total of $22.0 million and $43.3 million in quarterly cash dividends during the six and twelve months ended June 30, 2014, respectively. The Company paid a total of $20.7 million and $40.8 million in quarterly cash dividends during the six and twelve months ended June 30, 2013, respectively. On July 24, 2014, the Board of Directors declared a quarterly cash dividend of $0.28 per share payable on September 30, 2014 to shareholders of record on September 15, 2014.



Basic and Diluted Earnings Per Share. The basic and diluted earnings per share are presented below (in thousands except for share data):
	Three Months Ended June 30,
	2014			2013
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	40,180,569			40,111,757
Dilutive effect of unvested performance awards	31,834			48,213
Diluted number of common shares outstanding	40,212,403			40,159,970
Basic net income per common share:
Net income	$	30,096		$	29,193
Income allocated to participating restricted stock	(103		)	(85		)
Net income available to common shareholders	$	29,993		$	29,108
Diluted net income per common share:
Net income	$	30,096		$	29,193
Income reallocated to participating restricted stock	(103		)	(84		)
Net income available to common shareholders	$	29,993		$	29,109
Basic net income per common share:
Distributed earnings	$	0.280		$	0.265
Undistributed earnings	0.470			0.465
Basic net income per common share	$	0.750		$	0.730
Diluted net income per common share:
Distributed earnings	$	0.280		$	0.265
Undistributed earnings	0.470			0.455
Diluted net income per common share	$	0.750		$	0.720



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	Six Months Ended June 30,
	2014			2013
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	40,164,913			40,095,002
Dilutive effect of unvested performance awards	15,917			24,107
Diluted number of common shares outstanding	40,180,830			40,119,109
Basic net income per common share:
Net income	$	34,711		$	36,827
Income allocated to participating restricted stock	(115		)	(102		)
Net income available to common shareholders	$	34,596		$	36,725
Diluted net income per common share:
Net income	$	34,711		$	36,827
Income reallocated to participating restricted stock	(115		)	(102		)
Net income available to common shareholders	$	34,596		$	36,725
Basic net income per common share:
Distributed earnings	$	0.545		$	0.515
Undistributed earnings	0.315			0.405
Basic net income per common share	$	0.860		$	0.920
Diluted net income per common share:
Distributed earnings	$	0.545		$	0.515
Undistributed earnings	0.315			0.405
Diluted net income per common share	$	0.860		$	0.920



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	Twelve Months Ended June 30,
	2014			2013
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	40,149,261			40,053,677
Dilutive effect of unvested performance awards	7,959			46,084
Dilutive effect of stock options	—			4,752
Diluted number of common shares outstanding	40,157,220			40,104,513
Basic net income per common share:
Net income	$	86,467		$	93,435
Income allocated to participating restricted stock	(273		)	(248		)
Net income available to common shareholders	$	86,194		$	93,187
Diluted net income per common share:
Net income	$	86,467		$	93,435
Income reallocated to participating restricted stock	(273		)	(248		)
Net income available to common shareholders	$	86,194		$	93,187
Basic net income per common share:
Distributed earnings	$	1.075		$	1.015
Undistributed earnings	1.075			1.315
Basic net income per common share	$	2.150		$	2.330
Diluted net income per common share:
Distributed earnings	$	1.075		$	1.015
Undistributed earnings	1.075			1.305
Diluted net income per common share	$	2.150		$	2.320



The amount of restricted stock awards and performance shares at 100% performance level excluded from the calculation of the diluted number of common shares outstanding because their effect was antidilutive is presented below:
	Three Months Ended		Six Months Ended		Twelve Months Ended
	June 30,		June 30,		June 30,
	2014	2013	2014	2013	2014	2013
Restricted stock awards	41,753	38,040	60,583	47,071	57,945	45,738
Performance shares (a)	86,110	85,183	107,309	105,090	99,128	86,624

____________________


(a)	Certain performance shares were excluded from the computation of diluted earnings per share as no payouts would have been required based upon performance at the end of each corresponding period.



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F. Income Taxes

The Company files income tax returns in the United States ("U.S.") federal jurisdiction and in the states of Texas, New Mexico and Arizona. The Company is no longer subject to tax examination by the taxing authorities in the federal and New Mexico jurisdictions for years prior to 2009 and in Arizona for years prior to 2008. The Company is currently under audit in Texas for tax years 2007 through 2011. The Company reached a settlement with the Arizona Department of Revenue in March 2014 in their audit of income tax returns for the years 1998 through 2007 which did not have a material effect on income tax expense.

For the three months ended June 30, 2014 and 2013, the Company’s effective tax rate was 32.9% and 35.3%, respectively. For the six months ended June 30, 2014 and 2013, the Company's effective tax rate was 31.9% and 34.3%, respectively. For the twelve months ended June 30, 2014 and 2013, the Company's effective tax rate was 32.0% and 34.4%, respectively. The Company's effective tax rate for all time periods presented differs from the federal statutory tax rate of 35.0% primarily due to the allowance for equity funds used during construction and state income taxes. The Company's effective tax rate for the six months ended June 30, 2014 also differs from the federal statutory tax rate of 35.0% due to capital gains in the qualified decommissioning trusts realized in the first quarter of 2014, which are taxed at a federal rate of 20.0%.

G. Commitments, Contingencies and Uncertainties

For a full discussion of commitments and contingencies, see Note K of Notes to Financial Statements in the 2013 Form 10-K. In addition, see Notes C and D above and Notes C and E of Notes to Financial Statements in the 2013 Form 10-K regarding matters related to wholesale power sales contracts and transmission contracts subject to regulation and Palo Verde, including decommissioning, spent nuclear fuel and waste disposal, and liability and insurance matters.

Power Purchase and Sale Contracts

To supplement its own generation and operating reserves, and to meet required renewable portfolio standards, the Company engages in firm power purchase arrangements which may vary in duration and amount based on evaluation of the Company’s resource needs, the economics of the transactions, and specific renewable portfolio requirements. For a full discussion of power purchase and sale contracts that the Company has entered into with various counterparties, see Note K of Notes to Financial Statements in the 2013 Form 10-K. In addition, the 50 MW Macho Springs solar photovoltaic project located in Luna County, New Mexico began commercial operation in May 2014.

Environmental Matters

General. The Company is subject to extensive laws, regulations and permit requirements with respect to air and greenhouse gas emissions, water discharges, soil and water quality, waste management and disposal, natural resources and other environmental matters by federal, state, regional, tribal and local authorities. Failure to comply with such laws, regulations and requirements can result in actions by authorities or other third parties that might seek to impose on the Company administrative, civil and/or criminal penalties or other sanctions. In addition, releases of pollutants or contaminants into the environment can result in costly cleanup liabilities. These laws, regulations and requirements are subject to change through modification or reinterpretation, or the introduction of new laws and regulations and, as a result, the Company may face additional capital and operating costs to comply. For a full discussion of certain key environmental issues, laws and regulations facing the Company see Note K of Notes to Financial Statements in the 2013 Form 10-K.

Clean Air Interstate Rule/Cross State Air Pollution Rule. The EPA promulgated the Cross-State Air Pollution Rule ("CSAPR") in August 2011, which rule involves requirements to limit emissions of nitrogen oxides ("NOx") and sulfur dioxide ("SO2") from certain of the Company's power plants in Texas and/or purchase allowances representing other parties' emissions reductions. CSAPR was intended to replace the EPA's 2005 Clean Air Interstate Rule ("CAIR"). While the U.S. Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") vacated CSAPR in August 2012 and allowed CAIR to stand until the EPA issued a proper replacement, on April 29, 2014, the U.S. Supreme Court reversed and upheld CSAPR, remanding certain portions of CSAPR to the D.C. Circuit for further consideration. On June 26, 2014, the EPA filed a motion asking the D.C. Circuit to lift its stay on CSAPR, which was scheduled to go into effect on January 1, 2012. The EPA requested that the court toll the original compliance deadlines by three years. The three-year tolling would mean that the Phase 1 emissions budgets would apply in 2015 and 2016 (instead of 2012 and 2013), and the Phase 2 emissions budgets would apply in 2017 and beyond (instead of 2014 and beyond). The Company will evaluate what impact, if any, the D.C. Circuit subsequent holdings on remand will have on its operations.

Other Laws and Regulations and Risks. The Company intends to cease its participation in Four Corners Generating Station ("Four Corners") at the expiration of the 50-year participation agreement in July 2016. The Company believes that it has better economic and cleaner alternatives for serving the energy needs of its customers than coal-fired generation, which is subject to extensive regulation and litigation. For example, as a result of APS's recent Best Available Retrofit Technology Federal



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Implementation Plan compliance strategy notification to the EPA, Four Corners is required to install expensive pollution control equipment in order to continue operation in the future. The Company's share of the cost of these controls is currently estimated by APS to be approximately $39 million if the Company were to extend its participation in the plant. In addition, the EPA has entered into a consent decree which would require it to issue its final rulemaking regarding the regulation of coal combustion residuals ("CCR") under the federal Resource, Conservation and Recovery Act by December 19, 2014. Once issued, the Company may be required to incur significant costs to address CCRs either generated in the past and disposed of at or from Four Corners, as well as CCRs generated in connection with the ongoing operations of Four Corners. Further, assured supplies of water are important for the Company's operations and assets, including Four Corners. Four Corners is located in a region that has been experiencing drought conditions which could affect the plant's water supply. Four Corners has accordingly been involved in negotiations and proceedings with third parties relating to water supply issues. The drought conditions and related negotiations and proceedings could adversely affect the amount of power available, or the price thereof, from Four Corners. The Company is negotiating with APS on the disposition of its ownership interest in Four Corners to allow the other participants to pursue a life extension of the Four Corners plant.

Climate Change. On June 25, 2013, President Obama set forth his plan to address climate change. He reiterated a goal of reducing GHG "in the range of 17 percent" below 2005 levels by 2020. The plan included a variety of executive actions, including future regulatory measures to reduce carbon dioxide emissions from power plants. In a White House memorandum of the same date, the President directed the EPA to issue a new proposal for GHG rulemaking addressing new power plants by September 20, 2013, and a rule for existing power plants by June 1, 2014. The formal proposal for new power plants was published in the Federal Register on January 8, 2014. The Company submitted its comments on the proposal to EPA on May 9, 2014. Also, on June 16, 2014, the EPA published the proposed rule, "Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units," also called the "Clean Power Plan" or the Clean Air Act Section 111(d) proposed rule, to limit GHGs from existing power plants. The rule is proposing state-specific rate-based goals for carbon dioxide emissions from the power sector, as well as guidelines for states to follow in developing plans to achieve the state-specific goals. The Company is reviewing the proposed rule and plans to provide comments to EPA in the assigned comment period. Given the very significant remaining uncertainties regarding these rules, the Company believes it is impossible to meaningfully quantify the costs of these potential requirements at present.

Environmental Litigation and Investigations. Since 2009, the EPA and certain environmental organizations have been scrutinizing, and in some cases, have filed lawsuits, relating to certain air emissions and air permitting matters related to Four Corners. In particular, since July 2011, the U.S. Department of Justice (the "DOJ"), on behalf of the EPA, and APS have been engaged in substantive settlement negotiations in an effort to resolve the pending matters. The allegations being addressed through settlement negotiations are that APS failed to obtain the necessary permits and install the controls necessary under the Clean Air Act ("CAA") to reduce SO2, NOx, and particular matter ("PM"), and that defendants failed to obtain an operating permit under Title V of the CAA that reflects applicable requirements imposed by law. In March 2012, the DOJ provided APS with a draft consent decree to settle the EPA matter, which decree contains specific provisions for the reduction and control of NOx, SO2, and PM, as well as provisions for a civil penalty, and expenditures on environmental mitigation projects with an emphasis on projects that address alleged harm to the Navajo Nation. Settlement discussions are on-going and the Company is unable to predict the outcome of these settlement negotiations. The Company has accrued a total of $0.5 million as a loss contingency related to this matter.

The Company received notice that Earthjustice filed a lawsuit in the United States District Court for New Mexico on October 4, 2011 for alleged violations of the Prevention of Significant Deterioration ("PSD") provisions of the CAA related to Four Corners. On January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the CAA's New Source Performance Standards ("NSPS") program. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required PSD permits and complies with the referenced NSPS program. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, APS and the other Four Corners participants filed motions to dismiss with the court. The case is being held in abeyance while the parties seek to negotiate a settlement. On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay. At such time as the stay is lifted, APS, the Company and the other Four Corners participants may reinstate the motions to dismiss. On July 16, 2014, the stay was extended until August 15, 2014. The Company is unable to predict the outcome of this litigation.

New Mexico Tax Matter Related to Coal Supplied to Four Corners

On May 23, 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four



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Corners (the "Assessment"). The Company's share of the Assessment is approximately $1.5 million. On behalf of the Four Corners participants, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with respect to that partial payment in August 2013. The New Mexico Taxation and Revenue Department denied the refund claim. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed complaints with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial. APS believes the Assessment and the refund claim denial are without merit. The Company cannot predict the timing, results, or potential impacts of the outcome of this litigation.

H. Litigation

The Company is a party to various legal actions. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. Based on a review of these claims and applicable insurance coverage, the Company believes that none of these claims will have a material adverse effect on the financial position, results of operations or cash flows of the Company. See Note C above and Note C of the Notes to Financial Statements in the 2013 Form 10-K for discussion of the effects of government legislation and regulation on the Company.

I. Employee Benefits

Retirement Plans

The net periodic benefit cost recognized for the three, six and twelve months ended June 30, 2014 and 2013 is made up of the components listed below as determined using the projected unit credit actuarial cost method (in thousands):



	Three Months Ended						Six Months Ended						Twelve Months Ended
	June 30,						June 30,						June 30,
	2014			2013			2014			2013			2014			2013
Components of net periodic benefit cost:
Service cost	$	2,189		$	2,430		$	4,362		$	4,830		$	8,859		$	9,245
Interest cost	3,790			3,400			7,660			6,800			14,474			13,579
Expected return on plan assets	(4,656		)	(4,275		)	(9,336		)	(8,550		)	(17,894		)	(15,772		)
Amortization of:
Net loss	2,515			2,745			4,288			5,420			9,966			11,098
Prior service (benefit) cost	(894		)	25			(1,153		)	50			(1,106		)	107
Net periodic benefit cost	$	2,944		$	4,325		$	5,821		$	8,550		$	14,299		$	18,257

During the six months ended June 30, 2014, the Company contributed $6.9 million of its projected $10.9 million 2014 annual contribution to its retirement plans.

During the quarter ended March 31, 2014, the Company implemented certain amendments to the Retirement Income Plan and Excess Benefit Plan. In the first quarter of 2014, the Company offered a cash balance pension plan as an alternative to its current final average pay pension plan for employees hired prior to January 1, 2014. The cash balance pension plan also included an enhanced employer matching contribution to the employee's respective 401(k) Defined Contribution Plan. The revisions in the benefit plans were effective April 1, 2014. As a result of these actions, the Company remeasured the assets and liabilities of the retirement plans based on actuarially determined estimates, using the end of alternative choice date of February 28, 2014 as the remeasurement date. The discount rate used to remeasure the benefit obligation at February 28, 2014 was 4.6% for the Retirement Income Plan and 4.5% for the Excess Benefit Plan, compared to 4.9% for both plans at December 31, 2013. As a result of the changes described above, the benefit obligation of the affected plans decreased $19.7 million, accumulated other comprehensive income before income taxes increased $19.7 million, estimated future benefit payments from 2014 through 2018 increased $21.7 million compared to the previous estimates. The 2014 net periodic benefit cost is estimated to decrease by $6.2 million compared to the net periodic benefit cost incurred in 2013 due to the changes described above and revisions to actuarial assumptions.



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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

Other Postretirement Benefits

The net periodic benefit cost recognized for the three, six and twelve months ended June 30, 2014 and 2013 is made up of the components listed below (in thousands):



	Three Months Ended						Six Months Ended						Twelve Months Ended
	June 30,						June 30,						June 30,
	2014			2013			2014			2013			2014			2013
Components of net periodic benefit cost:
Service cost	$	722		$	1,100		$	1,422		$	2,200		$	3,065		$	4,389
Interest cost	1,107			1,375			2,232			2,750			4,638			5,576
Expected return on plan assets	(533		)	(475		)	(1,058		)	(950		)	(2,059		)	(1,776		)
Amortization of:
Prior service benefit	(1,176		)	(1,425		)	(2,376		)	(2,850		)	(5,183		)	(5,789		)
Net (gain) loss	(686		)	—			(1,336		)	—			(1,962		)	308
Net periodic benefit cost (benefit)	$	(566	)	$	575		$	(1,116	)	$	1,150		$	(1,501	)	$	2,708

The Company has not contributed to its other postretirement benefits plan during the six months ended June 30, 2014 and does not expect to contribute to its other postretirement benefit plan in 2014.

J. Financial Instruments and Investments

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

Long-Term Debt and Short-Term Borrowings Under the RCF. The fair values of the Company's long-term debt and short-term borrowings under the RCF are based on estimated market prices for similar issues and are presented below (in thousands):



	June 30, 2014				December 31, 2013
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Pollution Control Bonds	$	193,135	$	207,424	$	193,135	$	193,990
Senior Notes	696,530		856,280		696,485		734,515
RGRT Senior Notes (1)	110,000		117,385		110,000		115,850
RCF (1)	97,772		97,772		14,352		14,352
Total	$	1,097,437	$	1,278,861	$	1,013,972	$	1,058,707

_______________

(1)

Nuclear fuel financing as of June 30, 2014 and December 31, 2013 is funded through the $110 million RGRT Senior Notes and $16.8 million and $14.4 million, respectively under the RCF. As of June 30, 2014, $81.0 million was outstanding under the RCF for working capital or general corporate purposes. As of December 31, 2013, no amount was outstanding under the RCF for working capital or general corporate purposes. The interest rate on the Company's borrowings under the RCF is reset throughout the quarter reflecting current market rates. Consequently, the carrying value approximates fair value.

Marketable Securities. The Company's marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair value which was $225.7 million and $214.1 million at June 30, 2014 and December 31, 2013, respectively. These securities are classified as available for sale under FASB guidance for certain investments in debt and equity securities and are valued using prices and other relevant information generated by market transactions involving identical or comparable securities. The reported fair values include gross unrealized losses on marketable securities whose impairment the Company has deemed to



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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

be temporary. The tables below present the gross unrealized losses and the fair value of these securities, aggregated by investment category and length of time that individual securities have been in a continuous unrealized loss position (in thousands):



	June 30, 2014
	Less than 12 Months					12 Months or Longer					Total
	Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses
Description of Securities (1):
Federal Agency Mortgage Backed Securities	$	—	$	—		$	2,422	$	(110	)	$	2,422	$	(110	)
U.S. Government Bonds	—		—			15,900		(792		)	15,900		(792		)
Municipal Obligations	2,520		(46		)	14,608		(621		)	17,128		(667		)
Corporate Obligations	500		(4		)	1,814		(54		)	2,314		(58		)
Total Debt Securities	3,020		(50		)	34,744		(1,577		)	37,764		(1,627		)
Common Stock	517		(6		)	410		(33		)	927		(39		)
Total Temporarily Impaired Securities	$	3,537	$	(56	)	$	35,154	$	(1,610	)	$	38,691	$	(1,666	)

_________________


(1)	Includes approximately 97 securities.



	December 31, 2013
	Less than 12 Months					12 Months or Longer					Total
	Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses
Description of Securities (2):
Federal Agency Mortgage Backed Securities	$	6,444	$	(169	)	$	1,421	$	(119	)	$	7,865	$	(288	)
U.S. Government Bonds	8,114		(245		)	10,866		(840		)	18,980		(1,085		)
Municipal Obligations	12,286		(335		)	7,782		(479		)	20,068		(814		)
Corporate Obligations	3,284		(96		)	901		(54		)	4,185		(150		)
Total Debt Securities	30,128		(845		)	20,970		(1,492		)	51,098		(2,337		)
Common Stock	2,305		(126		)	—		—			2,305		(126		)
Total Temporarily Impaired Securities	$	32,433	$	(971	)	$	20,970	$	(1,492	)	$	53,403	$	(2,463	)

_________________


(2)	Includes approximately 122 securities.

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



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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

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



	June 30, 2014				December 31, 2013
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
Description of Securities:
Federal Agency Mortgage Backed Securities	$	14,602	$	676	$	9,929	$	433
U.S. Government Bonds	12,929		285		6,258		126
Municipal Obligations	13,639		625		8,783		450
Corporate Obligations	11,791		874		9,188		506
Total Debt Securities	52,961		2,460		34,158		1,515
Common Stock	111,783		48,088		103,808		43,145
Common Collective Trust-Equity Funds	17,542		498		—		—
Equity Mutual Funds	—		—		16,802		3,081
Cash and Cash Equivalents	4,736		—		5,924		—
Total	$	187,022	$	51,046	$	160,692	$	47,741

The Company's marketable securities include investments in municipal, corporate and federal debt obligations. Substantially all of the Company's mortgage-backed securities, based on contractual maturity, are due in ten years or more. The mortgage-backed securities have an estimated weighted average maturity which generally range from three years to eight years and reflects anticipated future prepayments. The contractual year for maturity of these available-for-sale securities as of June 30, 2014 is as follows (in thousands):



	Total		2014		2015 through 2018		2019 through 2023		2024 and Beyond
Municipal Debt Obligations	$	30,767	$	401	$	12,787	$	13,939	$	3,640
Corporate Debt Obligations	14,105		—		3,311		6,422		4,372
U.S. Government Bonds	28,829		1,202		14,341		6,524		6,762

The Company recognizes impairment losses on certain of its securities deemed to be other than temporary. In accordance with FASB guidance, these impairment losses are recognized in net income, and a lower cost basis is established for these securities. The Company did not recognize other than temporary impairment losses on its available-for-sale securities in the three, six and twelve month periods ending June 30, 2014. The Company did not recognize other than temporary impairment losses on its available-for-sale securities in the three and six month periods ending June 30, 2013, however for the twelve months ended June 30, 2013 a $0.3 million other than temporary impairment losses was recognized.



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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

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



	Three Months Ended						Six Months Ended						Twelve Months Ended
	June 30,						June 30,						June 30,
	2014			2013			2014			2013			2014			2013
Proceeds from sales or maturities of available-for-sale securities	$	7,547		$	11,455		$	36,374		$	22,362		$	70,160		$	61,391
Gross realized gains included in pre-tax income	$	249		$	342		$	3,263		$	381		$	3,868		$	780
Gross realized losses included in pre-tax income	(147		)	(96		)	(296		)	(293		)	(436		)	(187		)
Gross unrealized losses included in pre-tax income	—			—			—			—			—			(313		)
Net gains in pre-tax income	$	102		$	246		$	2,967		$	88		$	3,432		$	280
Net unrealized holding gains (losses) included in accumulated other comprehensive income	$	6,070		$	(2,232	)	$	7,068		$	4,561		$	20,206		$	8,671
Net gains reclassified out of accumulated other comprehensive income	(102		)	(246		)	(2,967		)	(88		)	(3,432		)	(280		)
Net gains (losses) in other comprehensive income	$	5,968		$	(2,478	)	$	4,101		$	4,473		$	16,774		$	8,391

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


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

•

Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. Financial assets utilizing Level 2 inputs include the nuclear decommissioning trust investments in fixed income securities. The fair value of these financial instruments is based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences. The Common Collective Trusts are valued using the net asset value ("NAV") provided by the administrator of the fund. The NAV price is quoted on a restrictive market although the underlying investments are traded on active markets.


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

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



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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

During the first quarter of 2014, the Company sold its nuclear decommissioning trust investments in equity mutual funds, classified as Level 1, and invested those assets in common collective trusts which are classified as Level 2. The fair value of the Company's decommissioning trust funds and investment in debt securities, at June 30, 2014 and December 31, 2013, and the level within the three levels of the fair value hierarchy defined by FASB guidance are presented in the table below (in thousands):



Description of Securities	Fair Value as of June 30, 2014		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Trading Securities:
Investments in Debt Securities	$	1,621	$	—	$	—	$	1,621
Available for sale:
U.S. Government Bonds	$	28,829	$	28,829	$	—	$	—
Federal Agency Mortgage Backed Securities	17,024		—		17,024		—
Municipal Obligations	30,767		—		30,767		—
Corporate Obligations	14,105		—		14,105		—
Subtotal, Debt Securities	90,725		28,829		61,896		—
Common Stock	112,710		112,710		—		—
Common Collective Trust-Equity Funds	17,542		—		17,542		—
Cash and Cash Equivalents	4,736		4,736		—		—
Total available for sale	$	225,713	$	146,275	$	79,438	$	—



Description of Securities	Fair Value as of December 31, 2013		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Trading Securities:
Investments in Debt Securities	$	1,555	$	—	$	—	$	1,555
Available for sale:
U.S. Government Bonds	$	25,238	$	25,238	$	—	$	—
Federal Agency Mortgage Backed Securities	17,794		—		17,794		—
Municipal Obligations	28,851		—		28,851		—
Corporate Obligations	13,373		—		13,373		—
Subtotal, Debt Securities	85,256		25,238		60,018		—
Common Stock	106,113		106,113		—		—
Equity Mutual Funds	16,802		16,802		—		—
Cash and Cash Equivalents	5,924		5,924		—		—
Total available for sale	$	214,095	$	154,077	$	60,018	$	—

There were no transfers in or out of Level 1 and Level 2 fair value measurements categories due to changes in observable inputs during the three, six and twelve month periods ending June 30, 2014 and 2013. There were no purchases, sales, issuances, and settlements related to the assets in the Level 3 fair value measurement category during the three, six and twelve months ended June 30, 2014 and 2013.



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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

El Paso Electric Company:

We have reviewed the balance sheet of El Paso Electric Company as of June 30, 2014, the related statements of operations, and comprehensive operations, for the three-month, six-month and twelve-month periods ended June 30, 2014 and 2013, and the related statements of cash flows for the six-month periods ended June 30, 2014 and 2013. These 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 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 balance sheet of El Paso Electric Company as of December 31, 2013, and the related statements of operations, comprehensive operations, changes in common stock equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2014, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying balance sheet as of December 31, 2013, is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived.

/s/ KPMG LLP

Kansas City, Missouri

August 7, 2014



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

The information contained in this Item 2 updates, and should be read in conjunction with, the information set forth in Part II, Item 7 of our 2013 Annual Report on Form 10-K.

FORWARD-LOOKING STATEMENTS

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


•	capital expenditures,


•	earnings,


•	liquidity and capital resources,


•	ratemaking/regulatory matters,


•	litigation,


•	accounting matters,


•	possible corporate restructurings, acquisitions and dispositions,


•	compliance with debt and other restrictive covenants,


•	interest rates and dividends,


•	environmental matters,


•	nuclear operations, and


•	the overall economy of our service area.

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


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


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


•	reductions in output at generation plants operated by us,


•	unscheduled outages of generating units including outages at Palo Verde,


•	the size of our construction program and our ability to complete construction on budget,


•	potential delays in our construction schedule due to legal or other reasons,


•	disruptions in our transmission system, and in particular the lines that deliver power from our remote generating facilities,


•	electric utility deregulation or re-regulation,


•	regulated and competitive markets,


•	ongoing municipal, state and federal activities,


•	economic and capital market conditions,


•	changes in accounting requirements and other accounting matters,


•	changing weather trends and the impact of severe weather conditions,


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


•	changes in environmental laws and regulations and the enforcement or interpretation thereof, including those related to air, water or greenhouse gas emissions or other environmental matters,


•	changes in customers' demand for electricity as a result of energy efficiency initiatives and emerging competing services and technologies,


•	cuts in military spending or shutdowns of the federal government that reduce demand for our services from military and governmental customers,


•	political, legislative, judicial and regulatory developments,


•	the impact of lawsuits filed against us,


•	the impact of changes in interest rates,



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


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


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


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


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


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


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


•	other circumstances affecting anticipated operations, sales and costs.

These lists are not all-inclusive because it is not possible to predict all factors. A discussion of some of these factors is included in the 2013 Annual Report on Form 10-K under the headings “Risk Factors” and “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 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 2013 Annual Report on Form 10-K.

Summary

The following is an overview of our results of operations for the three, six and twelve month periods ended June 30, 2014 and 2013. Net income and basic earnings per share for the three, six and twelve month periods ended June 30, 2014 and 2013 are shown below:



	Three Months Ended				Six Months Ended				Twelve Months Ended
	June 30,				June 30,				June 30,
	2014		2013		2014		2013		2014		2013
Net income (in thousands)	$	30,096	$	29,193	$	34,711	$	36,827	$	86,467	$	93,435
Basic earnings per share	0.75		0.73		0.86		0.92		2.15		2.33

The following table and accompanying explanations show the primary factors affecting the after-tax change in net income between the 2014 and 2013 periods presented (in thousands):



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	Three Months Ended			Six Months Ended			Twelve Months Ended
June 30, 2013 net income	$	29,193		$	36,827		$	93,435
Change in (net of tax):
Palo Verde performance rewards, net (a)	1,415			1,415			1,415
Increased allowance for funds used during construction (b)	1,242			1,525			969
Increased miscellaneous income and deductions (c)	1,072			2,107			1,627
Increased deregulated Palo Verde Unit 3 revenues (d)	247			1,152			1,065
Increased investment and interest income (e)	27			2,436			2,851
Increased taxes other than income taxes (f)	(1,128		)	(2,831		)	(4,120		)
Increased depreciation and amortization (g)	(1,005		)	(1,796		)	(3,290		)
Decreased retail non-fuel base revenues (h)	(583		)	(3,746		)	(5,794		)
Decreased transmission revenues (i)	(478		)	(1,219		)	(1,400		)
Other	94			(1,159		)	(291		)
June 30, 2014 net income	$	30,096		$	34,711		$	86,467

______________


(a)	Recognition of the Palo Verde performance rewards in the second quarter of 2014 associated with the 2009 to 2012 performance periods, net of disallowed fuel and purchased power costs related to the resolution of the Texas fuel reconciliation proceeding designated as PUCT Docket No. 41852.


(b)	Allowance for funds used during construction ("AFUDC") increased in the three, six and twelve months ended June 30, 2014 compared to the same periods last year primarily due to higher balances of construction work in progress subject to AFUDC.


(c)	Miscellaneous income and deductions increased for the three, six and twelve months ended June 30, 2014, compared to the same periods last year, primarily due to gains on the sale of assets in 2014 compared to the same periods last year and decreased donations.


(d)	Revenues from retail sales of deregulated Palo Verde Unit 3 power increased for the three, six and twelve months ended June 30, 2014, compared to the same periods last year, due primarily to increased proxy market power prices in the current periods.


(e)	Investment and interest income increased for the six and twelve month periods ended June 30, 2014, compared to the same periods last year, primarily due to increased realized gains on the sale of equity investments in our Palo Verde decommissioning trust funds.

(f)

Taxes other than income taxes increased for the three, six and twelve month periods ended June 30, 2014, compared to the same periods last year, primarily due to an increase in property tax accruals reflecting both increased property values and higher assessment rates. In the first quarter of 2014, the Arizona tax district in which Palo Verde operates adjusted its 2013 property tax rate which resulted in a one-time increase in property taxes of $1.3 million in the six and twelve months ended June 30, 2014.


(g)	Depreciation and amortization increased for the three, six and twelve month periods ended June 30, 2014, compared to the same periods last year, primarily due to an increase in depreciable plant including Rio Grande Unit 9 which began commercial operation in May 2013.

(h)

Retail non-fuel base revenues decreased for the three, six and twelve months ended June 30, 2014, compared to the same periods last year, primarily due to reduced kWh sales to our residential customers. The reduced kWh sales to residential customers was driven by milder weather in the current periods compared to the same periods last year despite a 1.3% increase in the average number of residential customers served. Retail non-fuel base revenues exclude fuel recovered through New Mexico base rates. For a complete discussion of non-fuel base revenues, see page 30.


(i)	Transmission revenues decreased for the three, six and twelve months ended June 30, 2014, compared to the same periods last year, primarily due to the expiration of certain firm transmission contracts in October 2013 and January 2014.



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Historical Results of Operations

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

Operating revenues

We realize revenue from the sale of electricity to retail customers at regulated rates and the sale of energy in the wholesale power market generally at market-based prices. Sales for resale (which are FERC-regulated cost-based wholesale sales within our service territory) accounted for less than 1% of revenues.

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

No retail customer accounted for more than 4% of our non-fuel base revenues. Residential and small commercial customers comprise 75% or more of our non-fuel base revenues. While this customer base is more stable, it is also more sensitive to changes in weather conditions. The current rate structures in New Mexico and Texas reflect higher base rates during the peak summer season of May through October and lower base rates during November through April for our residential and small commercial and industrial customers. As a result, our business is seasonal, with higher kWh sales and revenues during the summer cooling season.

Weather significantly impacts our residential, small commercial and industrial customers, and to a lesser extent, our sales to public authorities. Heating and cooling degree days can be used to evaluate the effect of weather on energy use. For each degree the average outdoor temperature varies from a standard of 65 degrees Fahrenheit a degree day is recorded. For the three, six and twelve months ended June 30, 2014, retail non-fuel base revenues were negatively impacted by milder weather when compared to the same periods in 2013. Cooling degree days in the second quarter of 2014 decreased 3.8% when compared to the same period in 2013 but remained higher than the 10-year average by 4.2%. For the six months ended June 30, 2014, heating degree days decreased 26.6% when compared to the same period last year and were 17.0% below the 10-year average. Cooling degree days for the six months ended June 30, 2014 decreased 4.4% compared to the same period last year but remained higher than the 10-year average by 4.0%. For the twelve months ended June 30, 2014 cooling degree days decreased 6.6% and heating degree days decreased by 7.7% when compared to the same period last year. The table below shows heating and cooling degree days compared to a 10-year average.



	Three Months Ended			Six Months Ended			Twelve Months Ended
	June 30,			June 30,			June 30,
			10-Year			10-Year			10-Year
	2014	2013	Average	2014	2013	Average	2014	2013	Average*
Heating degree days	84	81	69	1,042	1,419	1,255	2,049	2,219	2,247
Cooling degree days	1,095	1,138	1,051	1,120	1,171	1,077	2,644	2,832	2,633

______________

* Calendar year basis.

Customer growth is a key driver of the growth of retail sales. The average number of retail customers grew 1.4% for both the three and six month periods ended June 30, 2014 when compared to the same periods last year and 1.3% for the twelve month period. See the tables presented on pages 33, 34, and 35 which provide detail on the average number of retail customers and the related revenues and kWh sales.

Retail non-fuel base revenues. Retail non-fuel base revenues decreased $0.9 million, or 0.6% for the three months ended June 30, 2014, when compared to the same period last year. The decrease in retail non-fuel base revenues reflected milder weather in the second quarter of 2014 which impacted sales to residential, small commercial, and to a lesser extent public authority customers. Retail non-fuel base revenues from sales to residential customers decreased by $0.8 million reflecting a 1.5% decrease in kWh sales despite a 1.3% increase in the average number of residential customers served. KWh sales to small commercial and industrial customers decreased 1.7% compared to the same quarter in 2013 despite a 1.9% increase in the average number of small commercial and industrial customers served. Retail non-fuel base revenues from sales to public authorities increased sightly primarily due to demand charges, despite a 0.5% decrease in kWh sales to public authorities compared to the same period last year. Retail non-fuel base revenues and kWh sales to large commercial and industrial customers were relatively unchanged for the quarter.



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Retail non-fuel base revenues decreased $5.7 million, or 2.2% for the six months ended June 30, 2014, when compared to the same period last year. The decrease in retail non-fuel base revenues reflected milder weather in the first six months of 2014 which impacted sales to residential, small commercial, and to a lesser extent public authority customers. Retail non-fuel base revenues from sales to residential customers decreased by $4.8 million reflecting a 5.2% decrease in kWh sales despite a 1.3% increase in the average number of residential customers served. KWh sales to small commercial and industrial customers decreased 1.6%, compared to the same period in 2013, despite a 2.0% increase in the average number of small commercial and industrial customers served. KWh sales to large commercial and industrial customers decreased 3.4% and non-fuel base revenues decreased 1.5%. While kWh sales to sales to public authorities in the six months of 2014 decreased approximately 2.3% compared to the same period in 2013, non-fuel base revenues increased sightly primarily due to demand charges.

Retail non-fuel base revenues decreased by $8.8 million, or 1.6%, for the twelve months ended June 30, 2014, when compared to the same period last year, primarily due to a $5.1 million, or 2.1%, reduction in non-fuel base revenues from sales to our residential customers reflecting a 2.4% decrease in kWh sales due to milder winter weather and cooler summer weather during the current period. The decrease for the twelve month period is also due to a $2.1 million, or 1.1% decrease in non-fuel base revenues from sales to small commercial and industrial customers reflecting a 1.5% decrease in kWh sales. Retail non-fuel base revenues decreased $0.9 million, or 2.2%, from sales to large commercial and industrial customers and $0.7 million, or 0.7% from sales to public authorities primarily due to reduced sales to military installations in our service territory.

Fuel revenues. Fuel revenues consist of (i) revenues collected from customers under fuel recovery mechanisms approved by the state commissions and the FERC, (ii) deferred fuel revenues which are comprised of the difference between fuel costs and fuel revenues collected from customers, and (iii) fuel costs recovered in base rates in New Mexico. In New Mexico and with our sales for resale customer, the fuel adjustment clause allows us to recover under-recoveries or refund over-recoveries of current fuel costs above the amount recovered in base rates with a two-month lag. In Texas, fuel costs are recovered through a fixed fuel factor. We can seek to revise our fixed fuel factor based upon an approved formula at least four months after our last revision except in the month of December. In addition, if we materially over-recover fuel costs, we must seek to refund the over-recovery, and if we materially under-recover fuel costs, we may seek a surcharge to recover those costs. Fuel over and under recoveries are considered material when they exceed 4% of the previous twelve months' fuel costs.

On July 10, 2014, the PUCT approved a settlement in the Texas fuel reconciliation proceeding designated as PUCT Docket No. 41852. The three, six and twelve months ended June 30, 2014 fuel revenues were increased by $2.2 million. This amount includes $3.4 million of Palo Verde performance rewards associated with the 2009 to 2012 performance periods net of disallowed fuel and purchased power costs of $1.75 million as determined by the PUCT of which $0.5 million had been reserved. The settlement provides for the reconciliation of fuel costs incurred from July 1, 2009 through March 31, 2013.

In the three, six, and twelve months ended June 30, 2014, we under-recovered our fuel costs by $15.4 million, $13.4 million, and $15.3 million, respectively. In May 2014, we implemented a 6.9% increase in our fixed fuel factor in Texas which was based upon a formula that reflects increases in prices for natural gas. In the three, six, and twelve months ended June 30, 2013, we under-recovered our fuel costs by $12.8 million, $8.9 million, and $6.0 million, respectively. Refunds of $6.9 million were made to our Texas customers in the twelve months ended June 30, 2013. At June 30, 2014, we had a net fuel under-recovery balance of $19.6 million, including an under-recovery balance of $17.2 million in Texas, $2.3 million in New Mexico, and $0.1 million for our FERC customer. The Texas under-recovery is in excess of the materiality threshold and we expect to seek a fuel surcharge to recover the under-recovery balance in August 2014.

Off-system sales. Off-system sales are wholesale sales into markets outside our service territory. Off-system sales are primarily made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations. Beginning April 1, 2014, we share 100% of margins on non-arbitrage sales (as defined by the settlement) and 50% of margins on arbitrage sales with our Texas customers. For the period April 1, 2014 through June 30, 2015, our total share of margins assignable to the Texas retail jurisdiction, on arbitrage and non-arbitrage off-system sales, may not exceed 10% of the total margins assignable to the Texas retail jurisdiction on all off-system sales. Prior to April 1, 2014, we shared 90% of off-system sales margins with our Texas customers, and we retained 10% of off-system sales margins. We are currently sharing 90% of off-system sales margins with our New Mexico customers, and 25% of our off-system sales margins with our sales for resale customer under the terms of their contract.

Typically, we realize a significant portion of our off-system sales margins in the first quarter of each calendar year when our native load is lower than at other times of the year, allowing for the sale in the wholesale market of relatively larger amounts of off-system energy generated from lower cost generating resources. Palo Verde's availability is an important factor in realizing these off-system sales margins.

Off-system sales revenues increased $3.5 million, or 19.7% for the three months ended June 30, 2014, when compared to the same period last year, as a result of higher average market prices for power. Retained margins from off-system sales remained relatively unchanged for the three months ended June 30, 2014, compared to the same period last year. Off-system sales revenues



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increased $11.8 million, or 31.0% for the six months ended June 30, 2014, when compared to the same period last year, as a result of higher average market prices for power. Retained margins from off-system sales increased $0.4 million for the six months ended June 30, 2014, compared to the same period last year. Off-system sales revenues increased $20.9 million, or 28.3% for the twelve months ended June 30, 2014, when compared to the same period last year, as a result of higher average market prices for power partially and a 5.6% increase in kWh sales. Retained margins from off-system sales increased $0.6 million for the twelve months ended June 30, 2014, compared to the same period last year.



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Comparisons of kWh sales and operating revenues are shown below (in thousands):
					Increase (Decrease)
Quarter Ended June 30:	2014		2013		Amount			Percent
kWh sales:
Retail:
Residential	650,003		659,825		(9,822		)	(1.5	)%
Commercial and industrial, small	620,630		631,246		(10,616		)	(1.7	)
Commercial and industrial, large	292,113		292,282		(169		)	(0.1	)
Sales to public authorities	434,930		437,248		(2,318		)	(0.5	)
Total retail sales	1,997,676		2,020,601		(22,925		)	(1.1	)
Wholesale:
Sales for resale	20,328		20,141		187			0.9
Off-system sales	565,853		532,334		33,519			6.3
Total wholesale sales	586,181		552,475		33,706			6.1
Total kWh sales	2,583,857		2,573,076		10,781			0.4
Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	59,828	$	60,631	$	(803	)	(1.3	)%
Commercial and industrial, small	53,675		53,729		(54		)	(0.1	)
Commercial and industrial, large	9,963		10,021		(58		)	(0.6	)
Sales to public authorities	26,915		26,883		32			0.1
Total retail non-fuel base revenues	150,381		151,264		(883		)	(0.6	)
Wholesale:
Sales for resale	680		702		(22		)	(3.1	)
Total non-fuel base revenues	151,061		151,966		(905		)	(0.6	)
Fuel revenues:
Recovered from customers during the period	40,529		32,368		8,161			25.2
Under collection of fuel (1)	15,369		12,788		2,581			20.2
New Mexico fuel in base rates	17,132		17,642		(510		)	(2.9	)
Total fuel revenues (2)	73,030		62,798		10,232			16.3
Off-system sales:
Fuel cost	18,000		14,993		3,007			20.1
Shared margins	2,645		2,246		399			17.8
Retained margins	322		273		49			17.9
Total off-system sales	20,967		17,512		3,455			19.7
Other (3)	6,743		7,838		(1,095		)	(14.0	)
Total operating revenues	$	251,801	$	240,114	$	11,687		4.9
Average number of retail customers (4):
Residential	352,035		347,360		4,675			1.3	%
Commercial and industrial, small	39,482		38,739		743			1.9
Commercial and industrial, large	49		49		—			—
Sales to public authorities	5,108		4,978		130			2.6
Total	396,674		391,126		5,548			1.4

______________


(1)	2014 includes $2.2 million related to Palo Verde performance rewards, net.


(2)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $3.6 million and $3.2 million, respectively.


(3)	Represents revenues with no related kWh sales.


(4)	The number of retail customers presented are based on the number of service locations.



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Comparisons of kWh sales and operating revenues are shown below (in thousands):
					Increase (Decrease)
Six Months Ended June 30:	2014		2013		Amount			Percent
kWh sales:
Retail:
Residential	1,193,033		1,258,331		(65,298		)	(5.2	)%
Commercial and industrial, small	1,114,549		1,132,950		(18,401		)	(1.6	)
Commercial and industrial, large	518,665		536,867		(18,202		)	(3.4	)
Sales to public authorities	777,958		796,332		(18,374		)	(2.3	)
Total retail sales	3,604,205		3,724,480		(120,275		)	(3.2	)
Wholesale:
Sales for resale	32,720		32,140		580			1.8
Off-system sales	1,262,867		1,208,261		54,606			4.5
Total wholesale sales	1,295,587		1,240,401		55,186			4.4
Total kWh sales	4,899,792		4,964,881		(65,089		)	(1.3	)
Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	105,422	$	110,239	$	(4,817	)	(4.4	)%
Commercial and industrial, small	85,796		86,504		(708		)	(0.8	)
Commercial and industrial, large	18,291		18,569		(278		)	(1.5	)
Sales to public authorities	44,571		44,444		127			0.3
Total retail non-fuel base revenues	254,080		259,756		(5,676		)	(2.2	)
Wholesale:
Sales for resale	1,128		1,090		38			3.5
Total non-fuel base revenues	255,208		260,846		(5,638		)	(2.2	)
Fuel revenues:
Recovered from customers during the period	71,702		59,095		12,607			21.3
Under collection of fuel (1)	13,359		8,946		4,413			49.3
New Mexico fuel in base rates	33,227		34,551		(1,324		)	(3.8	)
Total fuel revenues (2)	118,288		102,592		15,696			15.3
Off-system sales:
Fuel cost	39,463		31,156		8,307			26.7
Shared margins	9,389		6,247		3,142			50.3
Retained margins	1,124		749		375			50.1
Total off-system sales	49,976		38,152		11,824			31.0
Other (3)	13,845		15,814		(1,969		)	(12.5	)
Total operating revenues	$	437,317	$	417,404	$	19,913		4.8
Average number of retail customers (4):
Residential	351,183		346,757		4,426			1.3	%
Commercial and industrial, small	39,350		38,571		779			2.0
Commercial and industrial, large	50		49		1			2.0
Sales to public authorities	5,078		4,966		112			2.3
Total	395,661		390,343		5,318			1.4

____________


(1)	2014 includes $2.2 million related to Palo Verde performance rewards, net.


(2)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $8.0 million and $6.2 million, respectively.


(3)	Represents revenues with no related kWh sales.


(4)	The number of retail customers presented are based on the number of service locations.



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Comparisons of kWh sales and operating revenues are shown below (in thousands):
					Increase (Decrease)
Twelve Months Ended June 30:	2014		2013		Amount			Percent
kWh sales:
Retail:
Residential	2,613,964		2,678,417		(64,453		)	(2.4	)%
Commercial and industrial, small	2,330,747		2,366,802		(36,055		)	(1.5	)
Commercial and industrial, large	1,077,177		1,085,680		(8,503		)	(0.8	)
Sales to public authorities	1,604,233		1,630,470		(26,237		)	(1.6	)
Total retail sales	7,626,121		7,761,369		(135,248		)	(1.7	)
Wholesale:
Sales for resale	61,812		63,909		(2,097		)	(3.3	)
Off-system sales	2,527,228		2,392,904		134,324			5.6
Total wholesale sales	2,589,040		2,456,813		132,227			5.4
Total kWh sales	10,215,161		10,218,182		(3,021		)	—
Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	231,834	$	236,921	$	(5,087	)	(2.1	)%
Commercial and industrial, small	183,860		185,998		(2,138		)	(1.1	)
Commercial and industrial, large	39,957		40,857		(900		)	(2.2	)
Sales to public authorities	95,171		95,825		(654		)	(0.7	)
Total retail non-fuel base revenues	550,822		559,601		(8,779		)	(1.6	)
Wholesale:
Sales for resale	2,210		2,234		(24		)	(1.1	)
Total non-fuel base revenues	553,032		561,835		(8,803		)	(1.6	)
Fuel revenues:
Recovered from customers during the period (1)	146,088		125,785		20,303			16.1
Under collection of fuel (2)	15,262		5,997		9,265			—
New Mexico fuel in base rates	71,971		73,998		(2,027		)	(2.7	)
Total fuel revenues (3)	233,321		205,780		27,541			13.4
Off-system sales:
Fuel cost	76,548		61,665		14,883			24.1
Shared margins	16,158		10,795		5,363			49.7
Retained margins	1,924		1,288		636			49.4
Total off-system sales	94,630		73,748		20,882			28.3
Other (4)	29,292		32,092		(2,800		)	(8.7	)
Total operating revenues	$	910,275	$	873,455	$	36,820		4.2
Average number of retail customers (5):
Residential	350,104		345,757		4,347			1.3	%
Commercial and industrial, small	39,226		38,588		638			1.7
Commercial and industrial, large	50		50		—			—
Sales to public authorities	5,053		4,917		136			2.8
Total	394,433		389,312		5,121			1.3

______________


(1)	Excludes $6.9 million of refunds in the twelve month period ended June 30, 2013 related to prior periods' Texas deferred fuel revenues.


(2)	2014 includes $2.2 million related to Palo Verde performance rewards, net.


(3)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $13.2 million and $11.5 million, respectively.


(4)	Represents revenues with no related kWh sales.


(5)	The number of retail customers presented are based on the number of service locations.



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Energy expenses

Our sources of energy include electricity generated from our nuclear, natural gas and coal generating plants and purchased power. Palo Verde represents approximately 34% of our available net generating capacity and approximately 51%, 58% and 54% of our Company-generated energy for the three, six and twelve months ended June 30, 2014, respectively. Fluctuations in the price of natural gas, which also is the primary factor influencing the price of purchased power, have had a significant impact on our cost of energy.

Energy expenses increased $10.5 million or 13.5% for the three months ended June 30, 2014, when compared to the same period in 2013, primarily due to increased natural gas costs of $8.3 million due to a 14.9% increase in the average price of natural gas and a 2.6% increase in MWhs generated with natural gas, and increased costs of total purchased power of $2.2 million due to a 12.2% increase in the average market price for power and a 7.4% increase in the MWhs purchased. Photovoltaic purchased power costs per MWh decreased for the three months ended June 30, 2014, when compared to the same period in 2013 primarily due to the lower priced purchases from Macho Springs solar photovoltaic project which began commercial operation in May 2014. The table below details the sources and costs of energy for the three months ended June 30, 2014 and 2013.



	Three Months Ended June 30,
	2014					2013
Fuel Type	Cost		MWh	Cost per MWh		Cost		MWh	Cost per MWh
	(in thousands)					(in thousands)
Natural gas	$	54,546	1,027,544	$	53.08	$	46,276	1,001,564	$	46.20
Coal	2,925		137,988	21.20		3,222		140,027	23.01
Nuclear	12,201		1,191,898	10.24		11,932		1,219,051	9.79
Total	69,672		2,357,430	29.55		61,430		2,360,642	26.02
Purchased power:
Photovoltaic	6,419		79,385	80.86		4,443		38,363	115.81
Other	11,709		321,504	39.65		11,470		335,019	34.24
Total purchased power	18,128		400,889	47.81		15,913		373,382	42.62
Total energy	$	87,800	2,758,319	31.83		$	77,343	2,734,024	28.29

Our energy expenses increased $22.7 million or 16.9% for the six months ended June 30, 2014, when compared to 2013, primarily due to increased natural gas costs of $16.5 million due to a 23.6% increase in the average price of natural gas and increased purchased power costs of $7.3 million due to a 22.1% increase in the average cost of total purchased power and a 5.5% increase in the MWhs purchased. The increase in energy expenses was partially offset by decreased coal costs of $ 1.1 million due to a 16.0% decrease in the MWhs generated with coal. Photovoltaic purchased power costs per MWh decreased for the six months ended June 30, 2014, when compared to the same period in 2013 primarily due to the lower priced purchases from Macho Springs solar photovoltaic project which began operation in May 2014. The table below details the sources and costs of energy for the six months ended June 30, 2014 and 2013.



	Six Months Ended June 30, 2014
	2014					2013
Fuel Type	Cost		MWh	Cost per MWh		Cost		MWh	Cost per MWh
	(in thousands)					(in thousands)
Natural gas	$	90,123	1,595,288	$	56.49	$	73,601	1,610,927	$	45.69
Coal	5,893		272,224	21.65		7,009		324,070	21.63
Nuclear	25,242		2,555,975	9.88		25,219		2,552,933	9.88
Total	121,258		4,423,487	27.41		105,829		4,487,930	23.58
Purchased power:
Photovoltaic	9,624		108,184	88.96		7,628		66,063	115.47
Other	26,419		653,448	42.02		21,162		656,024	32.26
Total purchased power	36,043		761,632	48.69		28,790		722,087	39.87
Total energy	$	157,301	5,185,119	30.34		$	134,619	5,210,017	25.84



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Our energy expenses increased $41.7 million or 15.5% for the twelve months ended June 30, 2014, when compared to 2013, primarily due to increased natural gas costs of $36.3 million due to an 18.5% increase in the average price of natural gas and increased total purchased power costs of $7.7 million due to a 14.5% increase in the average cost of purchased power. The increase in energy expenses was partially offset by decreased coal costs of $1.6 million due to an 11.2% decrease in the MWhs generated with coal. Photovoltaic purchased power costs per MWh decreased for the twelve months ended June 30, 2014, when compared to the same period in 2013 primarily due to the lower priced purchases from Macho Springs solar photovoltaic project which began commercial operation in May 2014. The table below details the sources and costs of energy for the twelve months ended June 30, 2014 and 2013.



	Twelve Months Ended June 30,
	2014					2013
Fuel Type	Cost		MWh	Cost per MWh		Cost		MWh	Cost per MWh
	(in thousands)					(in thousands)
Natural gas	$	180,661	3,671,184	$	49.21	$	144,400	3,477,812	$	41.52
Coal	12,564		583,871	21.52		14,125		657,481	21.48
Nuclear	48,972		4,969,275	9.85		49,580		5,048,429	9.82
Total	242,197		9,224,330	26.26		208,105		9,183,722	22.66
Purchased power:
Photovoltaic	15,859		163,047	97.27		14,115		123,314	114.46
Other	53,757		1,424,428	38.47		47,845		1,471,176	32.52
Total purchased power	69,616		1,587,475	44.51		61,960		1,594,490	38.86
Total energy	$	311,813	10,811,805	28.84		$	270,065	10,778,212	25.06

Other operations expense

Other operations expense increased $1.3 million, or 2.1%, and $1.4 million, or 1.2% for the three and six months ended June 30, 2014, compared to the same periods last year, primarily due to an increase in administrative and general salaries and employee incentive compensation, increased injuries and damages expense, and an increase in transmission expense primarily related to increased wheeling costs. These increases were partially offset by a decrease in employees pension and benefits expense as a result of changes in actuarial assumptions used to calculate expenses for our pension and other post-retirement employee benefit plans and plan modifications.

Other operations expense remained relatively unchanged for the twelve months ended June 30, 2014, compared to the same period last year and included an increase in transmission expense primarily related to increased wheeling costs, an increase in administrative and general salaries, and an increase in outside consulting and legal services related to the analysis of our future involvement at the Four Corners Generating Station. The increases in operations expense were offset by a decrease in employees pension and benefits expense as a result of changes in actuarial assumptions used to calculate expenses for our pension and other post-retirement employee benefit plans and plan modifications, and decreased power production operation expense at both Palo Verde and our fossil-fuel generating plants.

Maintenance expense

Maintenance expense remained relatively unchanged for the three months ended June 30, 2014 compared to the same period last year. Maintenance expense increased $1.7 million, or 5.9% for the six months ended June 30, 2014, compared to the same period last year primarily due to the timing of planned maintenance at our Newman generating station. Maintenance expense increased $4.7 million, or 8.0%, for the twelve months ended June 30, 2014, compared to the same period last year primarily due to the timing of planned maintenance at our Newman generating station and increased maintenance expense at Palo Verde during refueling outages in the current twelve month period compared to the same period last year.

Depreciation and amortization expense

Depreciation and amortization expense increased $1.5 million or 7.8%, $2.7 million or 7.0%, and $5.0 million or 6.4% for the three, six, and twelve month periods ended June 30, 2014, respectively, compared to the same periods last year primarily due to the increase in depreciable plant balances including Rio Grande Unit 9 which began commercial operation in May 2013.



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Taxes other than income taxes

Taxes other than income taxes increased $1.7 million, or 12.3% for the three months ended June 30, 2014, $4.3 million, or 16.1% for the six months ended June 30, 2014, and $6.2 million, or 11.2% for the twelve months ended June 30, 2014, compared to the same periods in the prior year primarily due to an increase in estimated property taxes and an increase in revenue related taxes. In the first quarter of 2014, the Arizona tax district in which Palo Verde operates adjusted its 2013 property tax rate which resulted in a one-time increase in property taxes of $1.3 million in the six and twelve months ended June 30, 2014.

Other income (deductions)

Other income (deductions) increased $2.7 million for the three months ended June 30, 2014, compared to the same period last year, primarily due to (i) decreased miscellaneous deductions due to decreased donations, (ii) increased allowance for equity funds used during construction ("AEFUDC") resulting from higher balances of construction work in progress, and (iii) a $0.5 million increase in miscellaneous non-operating income due primarily to a gain recognized on the sale of assets in 2014 with no comparable amounts being recorded in 2013.

Other income (deductions) increased $7.5 million and $6.9 million for the six and twelve months ended June 30, 2014, compared to the same periods last year, respectively, primarily due to net realized gains on equity investments in our decommissioning trust and increased miscellaneous non-operating income due primarily to a gain recognized on the sale of assets in 2014 compared to the same period last year.

Interest charges (credits)

Interest charges (credits) decreased by $0.3 million for both the three and six months ended June 30, 2014 compared to the same period last year, respectively, primarily due to increased allowance for borrowed funds used during construction ("ABFUDC") as a result of higher balances of construction work in progress partially offset by an increase in interest on short-term borrowings for financing construction.

Interest charges (credits) increased $1.2 million, or 2.7%, for the twelve months period ended June 30, 2014, compared to the same period last year, primarily due to interest on $150 million of 3.3% senior notes issued in December 2012 partially offset by a decrease in interest on short-term borrowings and increased ABFUDC as a result of higher balances of construction work in progress.

Income tax expense

Income tax expense decreased $1.2 million, or 7.3% for the three months ended June 30, 2014, compared to the same period last year, primarily due to an increase in the allowance for equity funds used during construction and decreased pre-tax income. Income tax expense decreased $3.0 million, or 15.6% for the six months ended June 30, 2014 compared to the same period last year, primarily due to decreased pre-tax income, an increase in the allowance for equity funds used during construction and a lower tax rate on capital gains realized on the sale of investments in the qualified nuclear decommissioning trust in the first quarter of 2014. Income tax expense decreased $8.4 million, or 17.2% for the twelve months ended June 30, 2014, compared to the same period last year, primarily due to an increase in the allowance for equity funds used during construction and decreased pre-tax income.

New Accounting Standards

In July 2013, the Financial Accounting Standards Board ("FASB") issued new guidance (Accounting Standards Update ("ASU") 2013-11, Income Taxes (Topic 740)) to eliminate the diversity in the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 requires an entity to present an unrecognized tax benefit in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except in certain circumstances when it would be reflected as a liability. We implemented ASU 2013-11 in the first quarter of 2014 on a prospective basis. This ASU did not have a significant impact on our statement of operations or statement of cash flows.



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entitled for the transfer of promised goods or services to customers. ASU 2014-09 is effective for annual periods and interim periods within that reporting period beginning after December 15, 2016, for public business entities. Early adoption of ASU 2014-09 is not permitted. We are currently assessing the future impact of this ASU.

Inflation

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



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Liquidity and Capital Resources

We continue to maintain a strong balance of common stock equity in our capital structure which supports our bond ratings, allowing us to obtain financing from the capital markets at a reasonable cost. At June 30, 2014, our capital structure, including common stock, long-term debt, and short-term borrowings under the revolving credit facility ("RCF"), consisted of 47.0% common stock equity and 53.0% debt. At June 30, 2014, we had on hand $12.7 million in cash and cash equivalents. We expect to issue long-term debt in the capital markets in 2014 or early 2015 to repay short-term borrowings and finance capital requirements. Based on current projections, we believe that we will have adequate liquidity through the issuance of long-term debt, our current cash balances, cash from operations, and available borrowings under the RCF to meet all of our anticipated cash requirements for the next twelve months.

Our principal liquidity requirements in the near-term are expected to consist of capital expenditures to expand and support electric service obligations, expenditures for nuclear fuel inventory, interest payments on our indebtedness, cash dividend payments, operating expenses including fuel costs, maintenance costs and taxes.

Capital Requirements. During the six months ended June 30, 2014, our capital requirements primarily consisted of expenditures for the construction and purchase of electric utility plant, cash dividend payments, and purchases of nuclear fuel. Projected utility construction expenditures are to expand and update our transmission and distribution systems, add new generation, and make capital improvements and replacements at Palo Verde and other generating facilities. We are constructing Montana Power Station ("MPS") Units 1 and 2, the first two (of four) natural gas-fired 88 MW simple-cycle aeroderivative combustion turbines that should reach commercial operation before our peak summer season in 2015. As of June 30, 2014, we had expended $148 million, including $39 million during 2014 related to the MPS. These amounts include AFUDC. The total cost for MPS Units 1 and 2 and common plant is estimated to be $220 million. Estimated cash construction expenditures for all capital projects for 2014 are expected to be approximately $316 million. See Part I, Item 1, “Business - Construction Program” in our 2013 Form 10-K. Cash capital expenditures for new electric plant were $106.0 million in the six months ended June 30, 2014 compared to $110.3 million in the six months ended June 30, 2013. Capital requirements for purchases of nuclear fuel were $17.7 million for the six months ended June 30, 2014 compared to $16.9 million for the six months ended June 30, 2013.

On June 30, 2014, we paid a quarterly cash dividend of $0.28 per share or $11.3 million to shareholders of record on June 13, 2014. We have paid a total of $22.0 million in cash dividends during the six months ended June 30, 2014. At the current dividend rate, we would expect to pay cash dividends of approximately $44.6 million during 2014. In addition, while we do not currently anticipate repurchasing shares in 2014, we may repurchase common stock in the future. Under our common stock repurchase program, purchases can be made at open market prices or in private transactions, and repurchased shares are available for issuance under employee benefit and stock incentive plans, or may be retired. No shares of common stock were repurchased during the six months ended June 30, 2014. As of June 30, 2014, a total of 393,816 shares remain eligible for repurchase.

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

Our cash requirements for federal and state income taxes vary from year to year based on taxable income, which is influenced by the timing of revenues and expenses recognized for income tax purposes. Accelerated tax deductions including bonus depreciation resulted in net operating loss carryforwards in 2011 through 2013 and as a result income tax payments are expected to be minimal in 2014.

We continually evaluate our funding requirements related to our retirement plans, other post-retirement benefit plans, and decommissioning trust funds. We contributed $6.9 million of the projected $10.9 million 2014 annual contribution to our retirement plans and $2.3 million of the projected $4.5 million 2014 annual contribution to our decommissioning trust funds during the six months ended June 30, 2014. In the six months ended June 30, 2014, we did not make any contributions to our other post-retirement benefit plans and we do not expect to contribute to our other post-retirement benefits plan in 2014. We are in compliance with the funding requirements of the federal government for our benefit plans. In addition, we are in compliance with the funding requirements of the federal law and the Arizona Nuclear Power Project Participation Agreement for our decommissioning trust.

Capital Resources. Cash from operations was $57.0 million for the six months ended June 30, 2014 and $51.4 million for the six months ended June 30, 2013. The primary factors affecting the increased cash flow from operations were the funding of $17.9 million for employee pension and other post-retirement benefit plans in the six months ending June 30, 2013 compared to $6.9 million in the six months ending June 30, 2014, and a decrease in accounts receivable due to the timing of customer payments. Cash from operations has also been impacted by the timing of the recovery of fuel costs through fuel recovery mechanisms in Texas and New Mexico and our sales for resale customer. We recover actual fuel costs from customers through fuel adjustment



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mechanisms in Texas, New Mexico, and from our sales for resale customer. We record deferred fuel revenues for the under-recovery or over-recovery of fuel costs until they can be recovered from or refunded to customers. In Texas, fuel costs are recovered through a fixed fuel factor. We can seek to revise our fixed fuel factor at least four months after the last revision except in the month of December based upon our approved formula which allows us to adjust fuel rates to reflect changes in costs of natural gas. We are required to request to refund fuel costs in any month when the over-recovery balance exceeds a threshold material amount and we expect fuel costs to continue to be materially over-recovered. We are permitted to seek to surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount that we expect fuel cost recovery to continue to be materially under-recovered. Fuel over and under-recoveries are considered material when they exceed 4% of the previous twelve months' fuel costs. On October 1, 2013, we implemented an increased fixed fuel factor charged to our Texas retail customers which was based upon a formula that reflects projected prices for natural gas. Additionally, on April 15, 2014, we filed a request to increase our Texas fixed fuel factor by 6.9% to reflect increases in prices for natural gas. This increase received final approval on May 28, 2014 and was effective with May 2014 billings. During the six months ended June 30, 2014, we had an under-recovery of fuel costs of $13.4 million compared to an under-recovery of fuel costs of $8.9 million during the six months ended June 30, 2013. At June 30, 2014, we had a net fuel under-recovery balance of $19.6 million, including an under-recovery balance of $17.2 million in Texas, $2.3 million in New Mexico, and $0.1 million for our FERC customer. The Texas under-recovery is in excess of the materiality threshold and we expect to seek a fuel surcharge to recover the under-recovery balance in August 2014.

We maintain a RCF for working capital and general corporate purposes and the financing of nuclear fuel through the Rio Grande Resources Trust (“RGRT”). RGRT is the trust through which we finance our portion of nuclear fuel for Palo Verde and is consolidated in our financial statements. On January 14, 2014, we amended and extended our $300 million RCF, which includes an option to expand the size to $400 million, upon the satisfaction of certain conditions including obtaining commitments from lenders or third party financial institutions. The amended facility extends the maturity from September 2016 to January 2019. In addition, we may extend the January 2019 maturity, subject to lenders' approval, by two additional one year periods. The total amount borrowed for nuclear fuel by RGRT was $126.8 million at June 30, 2014, of which $16.8 million had been borrowed under the RCF and $110 million was borrowed through senior notes. At June 30, 2013, the total amounts borrowed for nuclear fuel by RGRT was $130.3 million of which $20.3 million was borrowed under the RCF and $110 million was borrowed through senior notes. Interest costs on borrowings to finance nuclear fuel are accumulated by RGRT and charged to us as fuel is consumed and recovered from customers through fuel recovery charges. At June 30, 2014, $81.0 million was outstanding under the RCF for working capital or general corporate purposes and at June 30, 2013, $6.0 million was outstanding under the RCF for working capital or general corporate purposes.

We expect to issue long-term debt in the second half of 2014 or early 2015. We believe we have adequate liquidity through the issuance of long-term debt, our current cash balances, cash from operations and our RCF to meet all of our anticipated cash requirements for the next twelve months. In the fourth quarter of 2013, we received approval from the NMPRC and the FERC to incrementally issue up to $300 million of long-term debt and to guarantee the issuance of up to $50 million of new debt by RGRT to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. Obtaining the ability to issue up to $300 million of new long-term debt, from time to time, provides us with the flexibility to access the debt capital markets when needed and when conditions are favorable.

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 2013 Form 10-K, Item 7A, "Quantitative and Qualitative Disclosures About Market Risk," for a complete discussion of the market risks we face and our market risk sensitive assets and liabilities. As of June 30, 2014, there have been no material changes in the market risks we face or the fair values of assets and liabilities disclosed in Item 7A, "Quantitative and Qualitative Disclosures About Market Risk," in our 2013 Annual Report Form 10-K.


Item 4.	Controls and Procedures

Evaluation of disclosure controls and procedures. Under the supervision and with the participation of our management, including our chief executive officer and our chief financial officer, we conducted an evaluation pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934 of our disclosure controls and procedures as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934. Based on that evaluation, our chief executive officer and our chief financial officer concluded that, as of June 30, 2014, our disclosure controls and procedures are effective.



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Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting in connection with the evaluation required by paragraph (d) of the Securities Exchange Act of 1934 Rules 13a-15 or 15d-15, that occurred during the quarter ended June 30, 2014, that materially affected, or that were reasonably likely to materially affect, our internal control over financial reporting.



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PART II. OTHER INFORMATION


Item 1.	Legal Proceedings

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


Item 1A.	Risk Factors

Our 2013 Form 10-K includes a detailed discussion of our risk factors.


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


(c)	Issuer Purchases of Equity Securities.



Period	Total Number of Shares Purchased	Average Price Paid per Share (Including Commissions)		Total Number of Shares Purchased as Part of a Publicly Announced Program	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
April 1 to April 30, 2014	—	$	—	—	393,816
May 1 to May 31, 2014	—	—		—	393,816
June 1 to June 30, 2014	—	—		—	393,816


Item 4.	Mine Safety Disclosures

Not Applicable.


Item 5.	Other Information

Investors should note that we announce material financial information in SEC filings, press releases and public conference calls. Based on new guidance from the SEC, we may also use the Investor Relations section of our website (www.epelectric.com) to communicate with investors about our company. It is possible that the financial and other information we post there could be deemed to be material information. The information on our website is not part of this document.


Item 6.	Exhibits

See Index to Exhibits incorporated herein by reference.



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SIGNATURES

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




	EL PASO ELECTRIC COMPANY

By:	/s/ NATHAN T. HIRSCHI
	Nathan T. Hirschi
	Senior Vice President - Chief Financial Officer
	(Duly Authorized Officer and Principal Financial Officer)

Dated: August 7, 2014



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EL PASO ELECTRIC COMPANY

INDEX TO EXHIBITS




Exhibit Number			Exhibit

10.09			Form of Directors' Restricted Stock Award Agreement between the Company and non-employee 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).

15			Letter re Unaudited Interim Financial Information

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

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

101.INS			XBRL Instance Document

101.SCH			XBRL Taxonomy Extension Schema Linkbase Document

101.CAL			XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF			XBRL Taxonomy Extension Definition Linkbase Document

101.LAB			XBRL Taxonomy Extension Label Linkbase Document

101.PRE			XBRL Taxonomy Extension Presentation Linkbase Document



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