Edgar Filing: EL PASO ELECTRIC CO /TX/

2015 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, 2015



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, 2015, there were 40,424,525 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, 2015 and December 31, 2014		1
Statements of Operations – Three Months, Six Months, and Twelve Months Ended June 30, 2015 and 2014		3
Statements of Comprehensive Operations – Three Months, Six Months, and Twelve Months Ended June 30, 2015 and 2014		5
Statements of Cash Flows – Six Months Ended June 30, 2015 and 2014		6
Notes to Financial Statements		7
Report of Independent Registered Public Accounting Firm		28
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	46
Item 4.	Controls and Procedures	46
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	47
Item 1A.	Risk Factors	47
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 4.	Mine Safety Disclosures	47
Item 5.	Other Information	47
Item 6.	Exhibits	47



	( i)

Table of Contents

PART I. FINANCIAL INFORMATION


Item 1.	Financial Statements

EL PASO ELECTRIC COMPANY

BALANCE SHEETS



	June 30, 2015			December 31, 2014
	(Unaudited)

ASSETS (In thousands)
Utility plant:
Electric plant in service	$	3,557,941		$	3,229,255
Less accumulated depreciation and amortization	(1,303,188		)	(1,266,672		)
Net plant in service	2,254,753			1,962,583
Construction work in progress	232,954			414,284
Nuclear fuel; includes fuel in process of $31,378 and $46,996, respectively	189,926			185,185
Less accumulated amortization	(74,877		)	(73,701		)
Net nuclear fuel	115,049			111,484
Net utility plant	2,602,756			2,488,351
Current assets:
Cash and cash equivalents	10,364			40,504
Accounts receivable, principally trade, net of allowance for doubtful accounts of $1,609 and $2,253, respectively	91,947			71,165
Accumulated deferred income taxes	23,263			13,957
Inventories, at cost	48,702			45,889
Under-collection of fuel revenues	—			10,253
Prepayments and other	16,456			12,213
Total current assets	190,732			193,981
Deferred charges and other assets:
Decommissioning trust funds	237,608			234,286
Regulatory assets	109,186			112,086
Other	31,193			30,597
Total deferred charges and other assets	377,987			376,969
Total assets	$	3,171,475		$	3,059,301

See accompanying notes to financial statements.



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EL PASO ELECTRIC COMPANY

BALANCE SHEETS (Continued)



	June 30, 2015			December 31, 2014
	(Unaudited)
CAPITALIZATION AND LIABILITIES (In thousands except for share data)
Capitalization:
Common stock, stated value $1 per share, 100,000,000 shares authorized, 65,705,078 and 65,725,246 shares issued, and 137,247 and 124,297 restricted shares, respectively	$	65,842		$	65,850
Capital in excess of stated value	318,927			318,515
Retained earnings	1,033,846			1,032,537
Accumulated other comprehensive loss, net of tax	(10,564		)	(8,001		)
	1,408,051			1,408,901
Treasury stock, 25,416,441 and 25,492,919 shares, respectively, at cost	(423,373		)	(424,647		)
Common stock equity	984,678			984,254
Long-term debt, net of current portion	1,134,231			1,134,179
Total capitalization	2,118,909			2,118,433
Current liabilities:
Current maturities of long-term debt	15,000			15,000
Short-term borrowings under the revolving credit facility	128,072			14,532
Accounts payable, principally trade	61,676			78,862
Taxes accrued	23,772			28,210
Interest accrued	12,865			12,758
Over-collection of fuel revenues	1,512			932
Other	27,384			24,715
Total current liabilities	270,281			175,009
Deferred credits and other liabilities:
Accumulated deferred income taxes	491,650			474,154
Accrued pension liability	89,231			94,272
Accrued post-retirement benefit liability	62,092			59,342
Asset retirement obligation	78,003			74,577
Regulatory liabilities	24,125			26,099
Other	37,184			37,415
Total deferred credits and other liabilities	782,285			765,859
Commitments and contingencies
Total capitalization and liabilities	$	3,171,475		$	3,059,301

See accompanying notes to financial statements.



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EL PASO ELECTRIC COMPANY

STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands except for share data)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
Operating revenues	$	219,508		$	251,801		$	383,254		$	437,317
Energy expenses:
Fuel	49,813			69,672			87,542			121,258
Purchased and interchanged power	11,742			18,128			22,917			36,043
	61,555			87,800			110,459			157,301
Operating revenues net of energy expenses	157,953			164,001			272,795			280,016
Other operating expenses:
Other operations	57,656			60,285			113,255			116,423
Maintenance	19,857			15,945			35,417			30,227
Depreciation and amortization	23,135			21,083			44,700			41,651
Taxes other than income taxes	15,433			15,557			29,591			30,919
	116,081			112,870			222,963			219,220
Operating income	41,872			51,131			49,832			60,796
Other income (deductions):
Allowance for equity funds used during construction	2,268			3,461			6,543			6,367
Investment and interest income, net	1,398			1,923			6,652			6,164
Miscellaneous non-operating income	507			590			687			2,107
Miscellaneous non-operating deductions	(1,271		)	(599		)	(1,762		)	(1,018		)
	2,902			5,375			12,120			13,620
Interest charges (credits):
Interest on long-term debt and revolving credit facility	16,495			14,607			32,978			29,186
Other interest	354			288			517			461
Capitalized interest	(1,261		)	(1,281		)	(2,550		)	(2,527		)
Allowance for borrowed funds used during construction	(1,391		)	(1,967		)	(4,012		)	(3,651		)
	14,197			11,647			26,933			23,469
Income before income taxes	30,577			44,859			35,019			50,947
Income tax expense	9,505			14,763			10,489			16,236
Net income	$	21,072		$	30,096		$	24,530		$	34,711

Basic earnings per share	$	0.52		$	0.75		$	0.61		$	0.86

Diluted earnings per share	$	0.52		$	0.75		$	0.61		$	0.86

Dividends declared per share of common stock	$	0.295		$	0.280		$	0.575		$	0.545
Weighted average number of shares outstanding	40,269,885			40,180,569			40,256,615			40,164,913
Weighted average number of shares and dilutive potential shares outstanding	40,302,694			40,212,403			40,284,757			40,180,830

See accompanying notes to financial statements.



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EL PASO ELECTRIC COMPANY

STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands except for share data)



	Twelve Months Ended
	June 30,
	2015			2014
Operating revenues	$	863,462		$	910,275
Energy expenses:
Fuel	217,289			242,197
Purchased and interchanged power	51,678			69,616
	268,967			311,813
Operating revenues net of energy expenses	594,495			598,462
Other operating expenses:
Other operations	235,664			238,578
Maintenance	70,819			62,758
Depreciation and amortization	86,391			82,347
Taxes other than income taxes	61,422			62,037
	454,296			445,720
Operating income	140,199			152,742
Other income (deductions):
Allowance for equity funds used during construction	14,838			11,197
Investment and interest income, net	14,121			10,132
Miscellaneous non-operating income	2,655			3,014
Miscellaneous non-operating deductions	(4,943		)	(2,549		)
	26,671			21,794
Interest charges (credits):
Interest on long-term debt and revolving credit facility	62,820			58,615
Other interest	1,306			589
Capitalized interest	(5,115		)	(5,217		)
Allowance for borrowed funds used during construction	(8,729		)	(6,565		)
	50,282			47,422
Income before income taxes	116,588			127,114
Income tax expense	35,341			40,647
Net income	$	81,247		$	86,467

Basic earnings per share	$	2.01		$	2.15

Diluted earnings per share	$	2.01		$	2.15

Dividends declared per share of common stock	$	1.135		$	1.075
Weighted average number of shares outstanding	40,236,466			40,149,261
Weighted average number of shares and dilutive potential shares outstanding	40,263,304			40,157,220

See accompanying notes to financial statements.



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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,
	2015			2014			2015			2014			2015			2014
Net income	$	21,072		$	30,096		$	24,530		$	34,711		$	81,247		$	86,467
Other comprehensive income (loss):
Unrecognized pension and post-retirement benefit costs:
Net gain (loss) arising during period	—			—			—			19,700			(74,028		)	102,664
Prior service benefit	—			—			—			—			34,200			97
Reclassification adjustments included in net income for amortization of:
Prior service benefit	(1,662		)	(2,070		)	(3,325		)	(3,529		)	(7,455		)	(6,289		)
Net loss	2,250			1,829			4,500			2,952			7,730			8,004
Net unrealized gains/losses on marketable securities:
Net holding gains (losses) arising during period	(1,563		)	6,070			(549		)	7,068			3,210			20,206
Reclassification adjustments for net (gains) losses included in net income	182			(102		)	(3,563		)	(2,967		)	(7,946		)	(3,432		)
Net losses on cash flow hedges:
Reclassification adjustment for interest expense included in net income	116			109			230			216			452			425
Total other comprehensive income (loss) before income taxes	(677		)	5,836			(2,707		)	23,440			(43,837		)	121,675
Income tax benefit (expense) related to items of other comprehensive income (loss):
Unrecognized pension and post-retirement benefit costs	(291		)	90			(622		)	(7,332		)	14,761			(39,817		)
Net unrealized losses (gains) on marketable securities	325			(1,215		)	881			(858		)	979			(3,321		)
Losses on cash flow hedges	(43		)	(40		)	(115		)	(132		)	(197		)	(210		)
Total income tax benefit (expense)	(9		)	(1,165		)	144			(8,322		)	15,543			(43,348		)
Other comprehensive income (loss), net of tax	(686		)	4,671			(2,563		)	15,118			(28,294		)	78,327
Comprehensive income	$	20,386		$	34,767		$	21,967		$	49,829		$	52,953		$	164,794

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,
	2015			2014
Cash flows from operating activities:
Net income	$	24,530		$	34,711
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service	44,700			41,651
Amortization of nuclear fuel	21,379			21,877
Deferred income taxes, net	8,789			15,141
Allowance for equity funds used during construction	(6,543		)	(6,367		)
Other amortization and accretion	8,888			9,145
Gain on sale of property, plant and equipment	—			(2,083		)
Net gains on sale of decommissioning trust funds	(3,563		)	(2,967		)
Other operating activities	243			(64		)
Change in:
Accounts receivable	(20,782		)	(33,585		)
Inventories	(2,813		)	(100		)
Net over-collection (under-collection) of fuel revenues	10,833			(13,369		)
Prepayments and other	(7,476		)	(6,691		)
Accounts payable	(15,528		)	1,983
Other current liabilities	(214		)	428
Deferred charges and credits	(2,068		)	(2,739		)
Net cash provided by operating activities	60,375			56,971
Cash flows from investing activities:
Cash additions to utility property, plant and equipment	(147,040		)	(105,999		)
Cash additions to nuclear fuel	(22,424		)	(17,690		)
Capitalized interest and AFUDC:
Utility property, plant and equipment	(10,555		)	(10,018		)
Nuclear fuel	(2,550		)	(2,527		)
Allowance for equity funds used during construction	6,543			6,367
Decommissioning trust funds:
Purchases, including funding of $2.3 million	(41,029		)	(40,924		)
Sales and maturities	37,158			36,374
Proceeds from sale of property, plant and equipment	—			2,377
Other investing activities	82			1,650
Net cash used for investing activities	(179,815		)	(130,390		)
Cash flows from financing activities:
Dividends paid	(23,220		)	(21,969		)
Borrowings under the revolving credit facility:
Proceeds	167,103			142,951
Payments	(53,563		)	(59,531		)
Other financing activities	(1,020		)	(928		)
Net cash provided by financing activities	89,300			60,523
Net decrease in cash and cash equivalents	(30,140		)	(12,896		)
Cash and cash equivalents at beginning of period	40,504			25,592
Cash and cash equivalents at end of period	$	10,364		$	12,696

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, 2014 (the "2014 Form 10-K"). Capitalized terms used in this report and not defined herein have the meaning ascribed to such terms in the 2014 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, 2015 and December 31, 2014; the results of its operations and comprehensive operations for the three, six and twelve months ended June 30, 2015 and 2014; and its cash flows for the six months ended June 30, 2015 and 2014. The results of operations and comprehensive operations for the three and six months ended June 30, 2015 and the cash flows for the six months ended June 30, 2015 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 $34.1 million at June 30, 2015 and $21.2 million at December 31, 2014. The Company presents revenues net of sales taxes in its statements of operations.



Supplemental Cash Flow Disclosures (in thousands)
		Six Months Ended
		June 30,
		2015			2014
Cash paid for:
	Interest on long-term debt and borrowing under the revolving credit facility	$	30,922		$	27,216
	Income tax paid, net	1,680			2,862
Non-cash investing and financing activities:
	Changes in accrued plant additions	(1,227		)	2,100
	Grants of restricted shares of common stock	1,106			2,930

New Accounting Standards. In May 2014, the Financial Accounting Standards Board ("FASB") issued new guidance (Accounting Standards Update ("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 intended to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. Generally Accepted Accounting Principles ("GAAP") and International Financial 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 was originally intended to be effective for annual periods and interim periods within that reporting period beginning after December 15, 2016, for public business entities. On April 1, 2015, the FASB voted to propose to defer the effective date to December 15, 2017. Early adoption of ASU 2014-09 is permitted after December 15, 2016. The Company is currently assessing the future impact of this ASU.



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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this ASU. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The Company does not expect this ASU will materially impact the Company's results of operations and cash flows.



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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, 2015												Three Months Ended June 30, 2014
		Unrecognized Pension and Post-retirement Benefit Costs			Net Unrealized Gains (Losses) on Marketable Securities			Net Losses on Cash Flow Hedges			Accumulated Other Comprehensive Income (Loss)			Unrecognized Pension and Post-retirement 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		$	(34,628	)	$	36,782		$	(12,032	)	$	(9,878	)	$	(9,388	)	$	34,730		$	(12,283	)	$	13,059
	Other comprehensive income (loss) before reclassifications	—			(1,191		)	—			(1,191		)	—			4,845			—			4,845
	Amounts reclassified from accumulated other comprehensive income (loss)	297			135			73			505			(151		)	(92		)	69			(174		)
Balance at end of period		$	(34,331	)	$	35,726		$	(11,959	)	$	(10,564	)	$	(9,539	)	$	39,483		$	(12,214	)	$	17,730

		Six Months Ended June 30, 2015												Six Months Ended June 30, 2014
		Unrecognized Pension and Post-retirement Benefit Costs			Net Unrealized Gains (Losses) on Marketable Securities			Net Losses on Cash Flow Hedges			Accumulated Other Comprehensive Income (Loss)			Unrecognized Pension and Post-retirement 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		$	(34,884	)	$	38,957		$	(12,074	)	$	(8,001	)	$	(21,330	)	$	36,240		$	(12,298	)	$	2,612
	Other comprehensive income (loss) before reclassifications	—			(369		)	—			(369		)	12,147			5,644			—			17,791
	Amounts reclassified from accumulated other comprehensive income (loss)	553			(2,862		)	115			(2,194		)	(356		)	(2,401		)	84			(2,673		)
Balance at end of period		$	(34,331	)	$	35,726		$	(11,959	)	$	(10,564	)	$	(9,539	)	$	39,483		$	(12,214	)	$	17,730

		Twelve Months Ended June 30, 2015												Twelve Months Ended June 30, 2014
		Unrecognized Pension and Post-retirement Benefit Costs			Net Unrealized Gains (Losses) on Marketable Securities			Net Losses on Cash Flow Hedges			Accumulated Other Comprehensive Income (Loss)			Unrecognized Pension and Post-retirement 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		$	(9,539	)	$	39,483		$	(12,214	)	$	17,730		$	(74,198	)	$	26,030		$	(12,429	)	$	(60,597	)
	Other comprehensive income (loss) before reclassifications	(24,775		)	2,681			—			(22,094		)	63,518			16,206			—			79,724
	Amounts reclassified from accumulated other comprehensive income (loss)	(17		)	(6,438		)	255			(6,200		)	1,141			(2,753		)	215			(1,397		)
Balance at end of period		$	(34,331	)	$	35,726		$	(11,959	)	$	(10,564	)	$	(9,539	)	$	39,483		$	(12,214	)	$	17,730



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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, 2015 and 2014 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
		2015			2014			2015			2014			2015			2014			Affected Line Item in the Statement of Operations

Amortization of pension and post-retirement benefit costs:
	Prior service benefit	$	1,662		2,070			$	3,325		3,529			$	7,455		$	6,289		(a)
	Net loss	(2,250		)	(1,829		)	(4,500		)	(2,952		)	(7,730		)	(8,004		)	(a)
		(588		)	241			(1,175		)	577			(275		)	(1,715		)	(a)
	Income tax effect	291			(90		)	622			(221		)	292			574
		(297		)	151			(553		)	356			17			(1,141		)	(a)

Marketable securities:
	Net realized gain (loss) on sale of securities	(182		)	102			3,563			2,967			7,946			3,432			Investment and interest income, net
		(182		)	102			3,563			2,967			7,946			3,432			Income before income taxes
	Income tax effect	47			(10		)	(701		)	(566		)	(1,508		)	(679		)	Income tax expense
		(135		)	92			2,862			2,401			6,438			2,753			Net income

Loss on cash flow hedge:
	Amortization of loss	(116		)	(109		)	(230		)	(216		)	(452		)	(425		)	Interest on long-term debt and revolving credit facility
		(116		)	(109		)	(230		)	(216		)	(452		)	(425		)	Income before income taxes
	Income tax effect	43			40			115			132			197			210			Income tax expense
		(73		)	(69		)	(115		)	(84		)	(255		)	(215		)	Net income

	Total reclassifications	$	(505	)	$	174		$	2,194		$	2,673		$	6,200		$	1,397

(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"). Municipal orders, ordinances and other agreements regarding rates and services adopted by Texas municipalities are subject to review and approval by the PUCT. 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, the NMPRC and the FERC are subject to judicial review.

Texas Regulatory Matters

2012 Texas Retail Rate Case. 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 discussed below. 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.

Energy Efficiency Cost Recovery Factor. The Company made its annual filing to establish its energy efficiency cost recovery factor for 2015 on May 1, 2014. In addition to projected energy efficiency costs for 2015 and true-up to prior year actual costs, the Company requested approval of a $2.0 million bonus for the 2013 energy efficiency program results in accordance with PUCT rules. The PUCT approved the Company's request at its November 14, 2014 open meeting. The Company recorded the $2.0 million bonus as operating revenue in the fourth quarter of 2014.

On May 1, 2015, the Company made its annual filing to establish its energy efficiency cost recovery factor for 2016. In addition to projected energy efficiency costs for 2016 and true-up to prior year actual costs, the Company requested approval of a $1.0 million bonus for the 2014 energy efficiency program results in accordance with PUCT rules. This case was assigned PUCT Docket No. 44677. A hearing on the merits is currently scheduled for mid August 2015.

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. The Texas Fuel Rule requires the Company to request to refund fuel costs in any month when the over-recovery balance exceeds a threshold material amount and it expects fuel costs to continue to be materially over-recovered. The Texas Fuel Rule also permits the Company to seek to surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount and it expects fuel cost recovery to continue to be materially under-recovered. Fuel over- and under-recoveries are considered material when they exceed 4% of the previous twelve months' fuel costs. All such fuel revenue and expense activities are subject to periodic final review by the PUCT in fuel reconciliation proceedings.

On April 15, 2014, the Company filed a request, which was assigned PUCT Docket No. 42384, to increase its fixed fuel factor by approximately $10.7 million annually or 6.9%, pursuant to its approved formula. The revised fixed fuel factor reflected an expected increase in prices for natural gas over the twelve month period beginning March 2014. The increase in the fixed fuel factor received final approval on May 28, 2014 and was effective with May 2014 billings. On April 15, 2015, the Company filed a request, which was assigned PUCT Docket No. 44633, to reduce its fixed fuel factor by approximately 24% to reflect an expected reduction in fuel expense. The over-recovered balance was below the materiality threshold. The reduction in the fixed fuel factor was effective on an interim basis May 1, 2015 and approved by the PUCT on May 20, 2015. As of June 30, 2015, the Company had over-recovered fuel costs in the amount of $1.1 million for the Texas jurisdiction.

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 PUCT 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



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reached and a final order was issued by the PUCT on July 11, 2014. The PUCT's final order completes the regulatory review and reconciliation of the Company's fuel expenses for the period through March 31, 2013.

The settlement provides that 100% of margins on non-arbitrage off-system sales (as defined by the settlement) and 50% of margins on arbitrage off-system 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 Company also agreed to file with the PUCT a proceeding to address the reasonableness of the Company's decision to not continue to participate in the Four Corners Generating Station ("Four Corners") after July 2016. It is expected that the final coal mine closing and reclamation costs will be addressed in that proceeding as well as other issues related to post-participation events such as the asset retirement obligations related to those two units.

Montana Power Station Approvals. The Company has received a Certificate of Convenience and Necessity ("CCN") from the PUCT to construct four natural gas fired generating units at the Montana Power Station ("the MPS") in El Paso County, Texas. The Company also obtained air permits from the Texas Commission on Environmental Quality ("TCEQ") and the U.S. Environmental Protection Agency ("EPA").

The PUCT has issued final orders approving CCNs for the MPS to Caliente transmission line, MPS In & Out transmission line and the MPS to Montwood transmission line. These transmission lines will connect MPS to the Company’s transmission system for delivery of electricity throughout its service territory. MPS Units 1 and 2 and the MPS to Caliente and MPS In & Out transmission lines became operational in March 2015.

Solar Generation CCN Filing. On April 20, 2015, the Company filed a petition with the PUCT requesting CCN authorization to construct a new 20 MW solar-powered generation facility to be located on Fort Bliss in the Company's service territory in Texas. The new facility will be a Company-owned system resource. The Company has requested a PUCT final order by November 30, 2015 so that the project can be completed before December 31, 2016 to maximize potential tax benefits. This case was assigned PUCT Docket No. 44637. A hearing on the merits is currently scheduled for September 2015.

Community Solar. On June 8, 2015, the Company filed a petition with the PUCT to initiate a community solar program to include construction and ownership of a 3 MW solar photovoltaic system located at the MPS. Participation will be on a voluntary basis, and customers will contract for a set capacity (kW) amount and receive all energy produced. The Company has requested a PUCT final order approving the program so that the project can be completed before December 31, 2016 to maximize potential tax benefits. This case was assigned PUCT Docket No. 44800. No procedural schedule has yet been issued.

Four Corners Generating Station. On June 10, 2015, the Company filed an application requesting reasonableness and public interest findings and certain rate- and accounting- related findings to sell its ownership interest in Four Corners to Arizona Public Service Company ("APS") pursuant to a Purchase and Sale Agreement executed February 17, 2015. The anticipated closing date is July 6, 2016, pending regulatory approval. This case was assigned PUCT Docket No. 44805. The deadline for parties to request hearing is set as November 20, 2015, and the deadline for the PUCT Staff to file a recommendation in the case is November 30, 2015, if no hearing is requested. The Company cannot predict the outcome of the case at this time.

Other Required Approvals. The Company has obtained other required approvals for 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 are updated annually for adjustment to the recovery factors.

2015 New Mexico Rate Case Filing. On May 11, 2015, the Company filed with the NMPRC (NMPRC Case No. 15-00127-UT) for an annual increase in non-fuel base rates of approximately $8.6 million or 7.1%. The filing also requests an annual reduction of $15.4 million, or 21.5%, for fuel and purchased power costs recovered in base rates. The reduction in fuel and purchased power rates reflects reduced fuel prices and improvements in system heat rates due to new generating unit additions. Based on the standard procedural schedule, the Company expects new rates to go into effect early in the second quarter of 2016. A hearing in the case has been set to begin in November 2015. The Company cannot predict the outcome of the case at this time.



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Fuel and Purchased Power Costs. Fuel and purchased power costs are recovered through base rates and a Fuel and Purchased Power Cost Adjustment Clause (the "FPPCAC") that accounts for changes in the costs of fuel relative to the amount included in base rates. On January 8, 2014, the NMPRC approved the continuation of the FPPCAC without modification in NMPRC Case No. 13-00380-UT. Fuel and purchased power costs are reconciled to actual costs on a monthly basis and recovered or refunded to customers the second succeeding month. The Company recovers costs related to Palo Verde Unit 3 capacity and energy in New Mexico through the FPPCAC as purchased power using a proxy market price approved in the 2014 FPPCAC continuation.

Montana Power Station Approvals. The Company has received a CCN from the NMPRC to construct four units at the MPS and associated transmission lines. The Company also obtained all necessary air permits from the TCEQ and EPA. A final order in NMPRC Case No. 13-00297-UT approving the CCN for MPS Units 3 and 4 was issued on June 11, 2014. MPS Units 1 and 2 and the MPS to Caliente and MPS In & Out transmission lines became operational in March 2015.

Solar Generation CCN Filing. On April 20, 2015, the Company filed a petition with the NMPRC requesting CCN authorization to construct a new 20 MW solar-powered generation facility to be located on Fort Bliss in the Company's service territory in Texas. The new facility will be a Company-owned system resource. The Company has requested expedited approval and a NMPRC final order by November 30, 2015 so that the project can be completed before December 31, 2016 to maximize potential tax benefits. This case was assigned NMPRC Case No. 15-00099-UT. Hearings are currently scheduled for late August 2015.

Four Corners Generating Station. On April 27, 2015, the Company filed an application requesting all necessary regulatory approvals to sell its ownership interest in Four Corners to APS pursuant to a Purchase and Sale Agreement executed February 17, 2015. The anticipated closing date is July 6, 2016, pending regulatory approval. This case was assigned NMPRC Case No. 15-00109-UT. Hearings in the case are scheduled for January 2016. The Company cannot predict the outcome of the case at this time.

Expedited Approval for CCN (5 MW Holloman Facility). On June 15, 2015, the Company filed a petition with the NMPRC requesting CCN authorization to construct a 5 MW solar-powered generation facility to be located at Holloman Air Force Base ("HAFB") in the Company's service territory in New Mexico. The new facility will be a dedicated Company-owned resource serving HAFB. The Company has requested approval such that the project can be completed before December 31, 2016 to maximize potential tax benefits. This case was assigned NMPRC Case No. 15-00185-UT. Hearings in the case have been set to begin in September 2015.

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

Four Corners Generating Station. On June 26, 2015, APS filed an application requesting authorization from FERC to purchase 100% of the Company’s ownership interest in Units 4 and 5 of Four Corners and the associated transmission interconnection facilities and rights. APS has requested authorization be granted by FERC on or before December 24, 2015. The Company cannot predict the outcome of the case at this time.

Public Service Company of New Mexico's ("PNM") Transmission Rate Case. On December 31, 2012, PNM filed with FERC to change its method of transmission rate recovery for its transmission delivery services from stated rates to formula rates. The Company takes transmission service from PNM and is among the PNM transmission customers affected by PNM's shift to formula rates. On March 1, 2013, the FERC issued an order rejecting in part PNM's filing, and establishing settlement judge and hearing procedures. On March 20, 2015, PNM filed with FERC a settlement agreement and offer of settlement resolving all issues set for hearing in the proceeding. The Company cannot predict the outcome of the case at this time.

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 U.S. 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, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the DOE. This lawsuit sought to recover damages incurred due to the DOE's failure to accept Palo Verde's spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011. On August 18, 2014, APS and the DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by the DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. On October 8, 2014, the Company received approximately $9.1 million, representing its share of the award. The majority of the award was credited to customers through the applicable fuel adjustment clauses. On October 31, 2014, APS acting on behalf of itself and the participant owners of Palo Verde, submitted to the government an additional request for reimbursement of spent nuclear fuel storage costs for the period July 1, 2011 through June 30, 2014. The accepted claim amount was $42.0 million. On June 1, 2015, the Company received approximately $6.6 million, representing its share of the award. The majority of the award was credited to customers through the applicable fuel adjustment clauses in March 2015.



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E. Common Stock

Dividends. The Company paid $11.9 million and $11.3 million in quarterly cash dividends during the three months ended June 30, 2015 and 2014, respectively. The Company paid a total of $23.2 million and $45.8 million in quarterly cash dividends during the six and twelve months ended June 30, 2015, 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. On July 23, 2015, the Board of Directors declared a quarterly cash dividend of $0.295 per share payable on September 30, 2015 to shareholders of record as of September 16, 2015.



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,
	2015			2014
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	40,269,885			40,180,569
Dilutive effect of unvested performance awards	32,809			31,834
Diluted number of common shares outstanding	40,302,694			40,212,403
Basic net income per common share:
Net income	$	21,072		$	30,096
Income allocated to participating restricted stock	(65		)	(103		)
Net income available to common shareholders	$	21,007		$	29,993
Diluted net income per common share:
Net income	$	21,072		$	30,096
Income reallocated to participating restricted stock	(65		)	(103		)
Net income available to common shareholders	$	21,007		$	29,993
Basic net income per common share:
Distributed earnings	$	0.295		$	0.280
Undistributed earnings	0.225			0.470
Basic net income per common share	$	0.520		$	0.750
Diluted net income per common share:
Distributed earnings	$	0.295		$	0.280
Undistributed earnings	0.225			0.470
Diluted net income per common share	$	0.520		$	0.750



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	Six Months Ended June 30,
	2015			2014
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	40,256,615			40,164,913
Dilutive effect of unvested performance awards	28,142			15,917
Diluted number of common shares outstanding	40,284,757			40,180,830
Basic net income per common share:
Net income	$	24,530		$	34,711
Income allocated to participating restricted stock	(71		)	(115		)
Net income available to common shareholders	$	24,459		$	34,596
Diluted net income per common share:
Net income	$	24,530		$	34,711
Income reallocated to participating restricted stock	(71		)	(115		)
Net income available to common shareholders	$	24,459		$	34,596
Basic net income per common share:
Distributed earnings	$	0.575		$	0.545
Undistributed earnings	0.035			0.315
Basic net income per common share	$	0.610		$	0.860
Diluted net income per common share:
Distributed earnings	$	0.575		$	0.545
Undistributed earnings	0.035			0.315
Diluted net income per common share	$	0.610		$	0.860



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	Twelve Months Ended June 30,
	2015			2014
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	40,236,466			40,149,261
Dilutive effect of unvested performance awards	26,838			7,959
Diluted number of common shares outstanding	40,263,304			40,157,220
Basic net income per common share:
Net income	$	81,247		$	86,467
Income allocated to participating restricted stock	(253		)	(273		)
Net income available to common shareholders	$	80,994		$	86,194
Diluted net income per common share:
Net income	$	81,247		$	86,467
Income reallocated to participating restricted stock	(253		)	(273		)
Net income available to common shareholders	$	80,994		$	86,194
Basic net income per common share:
Distributed earnings	$	1.135		$	1.075
Undistributed earnings	0.875			1.075
Basic net income per common share	$	2.010		$	2.150
Diluted net income per common share:
Distributed earnings	$	1.135		$	1.075
Undistributed earnings	0.875			1.075
Diluted net income per common share	$	2.010		$	2.150



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,
	2015	2014	2015	2014	2015	2014
Restricted stock awards	48,669	41,753	58,432	60,583	59,380	57,945
Performance shares (a)	59,898	86,110	59,898	107,309	48,136	99,128


(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 2010. The Company is currently under audit in Texas for tax years 2007 through 2011 and in Arizona for tax years 2009 through 2012.

For the three months ended June 30, 2015 and 2014, the Company’s effective tax rate was 31.1% and 32.9%, respectively. For the six months ended June 30, 2015 and 2014, the Company’s effective tax rate was 30.0% and 31.9%, respectively. For the twelve months ended June 30, 2015 and 2014, the Company's effective tax rate was 30.3% and 32.0%, respectively. The Company's effective tax rate for all time periods 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, 2015 also differs from the federal statutory tax rate of 35.0% due to capital gains in the qualified decommissioning trust realized in the first quarter of 2015, which are taxed at a federal tax rate of 20.0%.

In June 2015, legislation was approved in Texas which permanently reduced the Texas Franchise Tax rate to 0.75% tax on taxable margins down from an interim rate of 0.95%. The rate reduction is applicable to tax reports originally due on or after January 1, 2016 and is retroactive to January 1, 2015 tax accruals. The implementation of this rate change in June 2015 did not have a material impact on the financial statements of the Company.

G. Commitments, Contingencies and Uncertainties

For a full discussion of commitments and contingencies, see Note K of Notes to Financial Statements in the 2014 Annual Report on Form 10-K. In addition, see Notes C and D above and Notes C and E of Notes to Financial Statements in the 2014 Annual Report on 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 2014 Form 10-K.

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 more detailed discussion of certain key environmental issues, laws and regulations facing the Company see Note K of Notes to Financial Statements in the 2014 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, and on October 23, 2014, the D.C Circuit lifted its stay of CSAPR. On July 28, 2015, the D.C. Circuit ruled that the



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EPA's emissions budgets for 13 states including Texas are invalid but leaves the rule in place on remand. While we are unable to determine the full impact of this decision until EPA takes further action, the Company believes it is currently positioned to comply with CSAPR.

National Ambient Air Quality Standards. Under the Clean Air Act ("CAA"), the EPA sets National Ambient Air Quality Standards ("NAAQS") for six criteria pollutants considered harmful to public health and the environment, including particulate matter ("PM"), NOx, carbon monoxide ("CO"), ozone and SO2. NAAQS must be reviewed by the EPA at five-year intervals. In 2010, the EPA tightened the NAAQS for both NOx and SO2. The EPA is considering a 1-hour secondary NAAQS for NOx and SO2. In January 2013, the EPA tightened the NAAQS for fine PM. On November 26, 2014, the EPA announced a proposal to tighten the 2008 primary and secondary ground-level ozone NAAQS. Ozone is the main component of smog. While not directly emitted into the air, it forms from precursors, including NOx and volatile organic compounds, in combination with sunlight. EPA proposes to tighten the current 8-hour primary (health-based) standard of 75 parts per billion ("ppb") to a level within its preferred range of 65 to 70 ppb, while also taking comment on a potential standard as low as 60 ppb and on retaining the current standard. The EPA is expected to issue a final rule by November 2015 and make attainment/nonattainment designations for any revised standards by November 2017. The Company continues to evaluate what impact these final and proposed NAAQS could have on its operations. If the Company is required to install additional equipment to control emissions at its facilities, the revised NAAQS could have a material impact on its operations and financial results.

Utility MACT. The operation of coal-fired power plants, such as the Company's Four Corners plant, results in emissions of mercury and other air toxics. In December 2011, the EPA finalized Mercury and Air Toxics Standards (known as the "Utility MACT", or "MATS Rule") for oil-and coal-fired power plants, which requires significant reductions in emissions of mercury and other air toxics. Several judicial and other challenges were made to this rule, and on June 29, 2015, the U.S. Supreme Court remanded the rule to the D.C. Circuit Court, which rule remains in effect until the D.C. Circuit Court and the EPA take action. The legal status of the MATS Rule notwithstanding, the Four Corners plant operator, APS, believes Units 4 and 5 will require no additional modifications to achieve compliance with the MATS Rule, as currently written. We cannot currently predict, however, what additional modifications or costs may be incurred if the EPA rewrites the MATS Rule on remand.

Other Laws and Regulations and Risks. The Company has entered into an agreement to sell its interest in Four Corners to APS 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. By ceasing its participation in Four Corners, the Company will avoid the significant cost required to install expensive pollution control equipment in order to continue operation of the plant as well as the risks of water availability that might adversely affect the amount of power available, or the price thereof, from Four Corners in the future. The closing of the transaction is subject to the receipt of regulatory approvals.

Coal Combustion Waste. On April 17, 2015 the EPA published a final rule regulating the disposal of coal combustion residuals (the “CCR Rule”) from electric utilities as solid waste. The Company has a 7% ownership interest in Units 4 and 5 of Four Corners, the only coal-fired generating facility for which the Company has an ownership interest subject to the CCR Rule. The Company entered into a Purchase and Sale Agreement with APS in February 2015 to sell the Company’s entire ownership interest in Four Corners. For a discussion on the Purchase and Sale Agreement see Note E of the Notes to the Financial Statements in the 2014 Annual Report on Form 10-K. The CCR Rule essentially will require plant owners to treat coal combustion residuals as Subtitle D (as opposed to a more costly Subtitle C) waste. The Four Corners plant operator, APS, is reviewing the requirements of the CCR Rule and expects to be in material compliance with the rule by the effective date, October 14, 2015. In general, the Company would be liable for only 7% of costs to comply with the CCR Rule (consistent with our ownership percentage). The Company, however, believes under the terms of the Four Corners Purchase Agreement and after the pending sale, as a former owner, that the Company would not be responsible for a significant portion of the costs under the CCR Rule, such as ongoing operational costs. Accordingly, the Company does not expect the CCR Rule to have a significant impact on our financial condition or results of operations.

In 2012, several environmental groups filed a lawsuit in federal district court against the Office of Surface Mining Reclamation and Enforcement ("OSM") of the U.S. Department of the Interior challenging OSM’s 2012 approval of a permit revision which allowed for the expansion of mining operations into a new area of the mine that serves Four Corners ("Area IV North"). In April 2015, the court issued an order invalidating the permit revision, thereby prohibiting mining in Area IV North until OSM takes action to cure the defect in its permitting process identified by the court. Navajo Transitional Energy Company, the owner of the mine and supplier of coal to Four Corners, has indicated that it does not anticipate any near-term interruption of coal supply to the plant as a result of the suspension of mining in Area IV North. The Company cannot predict the time period that will be required



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(Unaudited)

for OSM’s further permitting process to be completed or whether the outcome of the process will be sufficient to allow the permit to be reinstated.

Climate Change. The U.S. federal government has either considered, proposed and/or finalized legislation or regulations limiting greenhouse gas ("GHG") emissions, including carbon dioxide ("CO2"). In particular, the U.S. Congress has considered legislation to restrict or regulate GHG emissions. In the past few years, the EPA began using the CAA to regulate CO2 and other GHG emissions, such as the 2009 GHG Reporting Rule and the EPA's sulfur hexafluoride ("SF6") reporting rule, both of which apply to the Company, as well as the EPA's 2010 actions to impose permitting requirements on new and modified sources of GHG emissions. After announcing his plan to address climate change in 2013, the President directed the EPA to issue proposals for GHG rulemaking addressing power plants. In August 2015, the EPA issued a final rule establishing new source performance standards limiting CO2 emissions from new, modified and reconstructed electric generating units. In August 2015, the EPA also issued a rule establishing guidelines for states to regulate CO2 emissions from existing power plants. The standards for existing plants are known as the Clean Power Plan ("CPP"), under which rule interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates by 2030. Legal challenges to the CPP are expected. We are evaluating the CPP and cannot at this time determine the impact of the CPP on our financial position, results of operations or cash flows.

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 certain of 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 CAA to reduce SO2, NOx, and PM, and that defendants failed to obtain an operating permit under Title V of the CAA that reflects applicable requirements imposed by law. In November 2014, 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. On June 24, 2015, the parties filed with the U.S. District Court for New Mexico a settlement agreement ("CAA Settlement Agreement") resolving this matter. The CAA Settlement Agreement, which is subject to final court approval, if finalized as currently written, would impose a total civil penalty payable by the co-owners of Four Corners collectively in the amount of $1.5 million, and it requires the co-owners to pay $6.7 million for environmental mitigation projects. The Company has accrued a total of $0.6 million as its estimated share of the loss contingency related to this matter.

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. Based on the CAA Settlement Agreement, it is anticipated that the parties will file motions to dismiss this matter in the event the court approves such settlement agreement. The Company does not expect the outcome of this matter to have a material impact on its financial position, results of operations or cash flows.

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 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. On June 30, 2015, the court ruled that the Assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statue. The New Mexico Taxation and Revenue Department has indicated it intends to appeal the decision. The Company cannot predict the timing, results, or potential impacts of the outcome of this litigation.



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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

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. The Company expenses legal costs, including expenses related to loss contingencies, as they are incurred.

See Notes C and G above and Notes C and K of the Notes to Financial Statements in the 2014 Annual Report on Form 10-K for discussion of the effects of government legislation and regulation on the Company.



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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

I. Employee Benefits

Retirement Plans

The net periodic benefit cost recognized for the three, six and twelve months ended June 30, 2015 and 2014 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,
	2015			2014			2015			2014			2015			2014
Components of net periodic benefit cost:
Service cost	$	2,100		$	2,189		$	4,200		$	4,362		$	8,425		$	8,859
Interest cost	3,625			3,790			7,250			7,660			14,632			14,474
Expected return on plan assets	(4,948		)	(4,656		)	(9,895		)	(9,336		)	(19,258		)	(17,894		)
Amortization of:
Net loss	2,750			2,515			5,500			4,288			10,065			9,966
Prior service benefit	(887		)	(894		)	(1,775		)	(1,153		)	(3,528		)	(1,106		)
Net periodic benefit cost	$	2,640		$	2,944		$	5,280		$	5,821		$	10,336		$	14,299

During the six months ended June 30, 2015, the Company contributed $6.6 million of its projected $11.1 million 2015 annual contribution to its retirement plans.

Other Postretirement Benefits

The net periodic benefit cost recognized for the three, six and twelve months ended June 30, 2015 and 2014 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,
	2015			2014			2015			2014			2015			2014
Components of net periodic benefit cost:
Service cost	$	875		$	722		$	1,750		$	1,422		$	3,173		$	3,065
Interest cost	1,025			1,107			2,050			2,232			4,281			4,638
Expected return on plan assets	(525		)	(533		)	(1,050		)	(1,058		)	(2,108		)	(2,059		)
Amortization of:
Prior service benefit	(775		)	(1,176		)	(1,550		)	(2,376		)	(3,927		)	(5,183		)
Net gain	(500		)	(686		)	(1,000		)	(1,336		)	(2,335		)	(1,962		)
Net periodic benefit cost (benefit)	$	100		$	(566	)	$	200		$	(1,116	)	$	(916	)	$	(1,501	)

The Company has not contributed to its other postretirement benefits plan during the six months ended June 30, 2015 and does not expect to contribute to its other postretirement benefit plan in 2015.

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 Revolving Credit Facility ("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.



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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

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, 2015				December 31, 2014
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Pollution Control Bonds	$	193,135	$	209,499	$	193,135	$	213,083
Senior Notes	846,096		973,648		846,044		968,728
RGRT Senior Notes (1)	110,000		117,005		110,000		117,215
RCF (1)	128,072		128,072		14,532		14,532
Total	$	1,277,303	$	1,428,224	$	1,163,711	$	1,313,558

_______________

(1)

Nuclear fuel financing as of June 30, 2015 and December 31, 2014 is funded through the $110 million RGRT Senior Notes and $18.1 million and $14.5 million, respectively under the RCF. As of June 30, 2015, $110.0 million was outstanding under the RCF for working capital or general corporate purposes. As of December 31, 2014, 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 $237.6 million and $234.3 million at June 30, 2015 and December 31, 2014, respectively. These securities are classified as available for sale under FASB guidance for certain investments in debt and equity securities and are valued using prices and other relevant information generated by market transactions involving identical or comparable securities. The reported fair values include gross unrealized losses on marketable securities whose impairment the Company has deemed to be temporary. The tables below present the gross unrealized losses and the fair value of these securities, aggregated by investment category and length of time that individual securities have been in a continuous unrealized loss position (in thousands):



	June 30, 2015
	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	$	5,420	$	(223	)	$	2,230	$	(81	)	$	7,650	$	(304	)
U.S. Government Bonds	9,910		(95		)	16,405		(604		)	26,315		(699		)
Municipal Obligations	14,691		(404		)	8,632		(517		)	23,323		(921		)
Corporate Obligations	4,938		(64		)	3,694		(173		)	8,632		(237		)
Total Debt Securities	34,959		(786		)	30,961		(1,375		)	65,920		(2,161		)
Common Stock	4,159		(234		)	—		—			4,159		(234		)
Total Temporarily Impaired Securities	$	39,118	$	(1,020	)	$	30,961	$	(1,375	)	$	70,079	$	(2,395	)

_________________


(1)	Includes 151 securities.



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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)



	December 31, 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 (2):
Federal Agency Mortgage Backed Securities	$	—	$	—		$	2,383	$	(57	)	$	2,383	$	(57	)
U.S. Government Bonds	1,552		(2		)	20,060		(573		)	21,612		(575		)
Municipal Obligations	6,433		(65		)	8,570		(410		)	15,003		(475		)
Corporate Obligations	2,455		(24		)	2,461		(111		)	4,916		(135		)
Total Debt Securities	10,440		(91		)	33,474		(1,151		)	43,914		(1,242		)
Common Stock	1,475		(229		)	—		—			1,475		(229		)
Common Collective Trust-Equity Funds	22,736		(821		)	—		—			22,736		(821		)
Total Temporarily Impaired Securities	$	34,651	$	(1,141	)	$	33,474	$	(1,151	)	$	68,125	$	(2,292	)

_________________


(2)	Includes 106 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 is expected or is scheduled to decommission Palo Verde.

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, 2015				December 31, 2014
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
Description of Securities:
Federal Agency Mortgage Backed Securities	$	11,484	$	521	$	15,388	$	665
U.S. Government Bonds	17,082		261		20,016		567
Municipal Obligations	6,832		325		11,642		595
Corporate Obligations	11,542		436		13,762		850
Total Debt Securities	46,940		1,543		60,808		2,677
Common Stock	90,241		44,636		99,160		48,253
Common Collective Trust-Equity Funds	24,043		1,382		—		—
Cash and Cash Equivalents	6,305		—		6,193		—
Total	$	167,529	$	47,561	$	166,161	$	50,930



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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

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 two years to six years and reflects anticipated future prepayments. The contractual year for maturity of these available-for-sale securities as of June 30, 2015 is as follows (in thousands):



	Total		2015		2016 through 2019		2020 through 2024		2025 and Beyond
Municipal Debt Obligations	$	30,155	$	515	$	10,772	$	13,095	$	5,773
Corporate Debt Obligations	20,174		705		5,763		7,530		6,176
U.S. Government Bonds	43,397		3,052		17,460		13,612		9,273

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, 2015 and 2014, respectively.

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,
	2015			2014			2015			2014			2015			2014
Proceeds from sales or maturities of available-for-sale securities	$	12,516		$	7,547		$	37,158		$	36,374		$	109,095		$	70,160
Gross realized gains included in pre-tax income	$	33		$	249		$	3,815		$	3,263		$	8,410		$	3,868
Gross realized losses included in pre-tax income	(215		)	(147		)	(252		)	(296		)	(464		)	(436		)
Net gains (losses) in pre-tax income	$	(182	)	$	102		$	3,563		$	2,967		$	7,946		$	3,432
Net unrealized holding gains (losses) included in accumulated other comprehensive income	$	(1,563	)	$	6,070		$	(549	)	$	7,068		$	3,210		$	20,206
Net (gains) losses reclassified out of accumulated other comprehensive income	182			(102		)	(3,563		)	(2,967		)	(7,946		)	(3,432		)
Net gains (losses) in other comprehensive income	$	(1,381	)	$	5,968		$	(4,112	)	$	4,101		$	(4,736	)	$	16,774

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



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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

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 analysis. 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.

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, 2015 and December 31, 2014, 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, 2015		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	$	1,591	$	—	$	—	$	1,591
Available for sale:
U.S. Government Bonds	$	43,397	$	43,397	$	—	$	—
Federal Agency Mortgage Backed Securities	19,134		—		19,134		—
Municipal Obligations	30,155		—		30,155		—
Corporate Obligations	20,174		—		20,174		—
Subtotal, Debt Securities	112,860		43,397		69,463		—
Common Stock	94,400		94,400		—		—
Common Collective Trust-Equity Funds	24,043		—		24,043		—
Cash and Cash Equivalents	6,305		6,305		—		—
Total available for sale	$	237,608	$	144,102	$	93,506	$	—



Description of Securities	Fair Value as of December 31, 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	$	1,653	$	—	$	—	$	1,653
Available for sale:
U.S. Government Bonds	$	41,628	$	41,628	$	—	$	—
Federal Agency Mortgage Backed Securities	17,771		—		17,771		—
Municipal Obligations	26,645		—		26,645		—
Corporate Obligations	18,678		—		18,678		—
Subtotal, Debt Securities	104,722		41,628		63,094		—
Common Stock	100,635		100,635		—		—
Common Collective Trust-Equity Funds	22,736		—		22,736		—
Cash and Cash Equivalents	6,193		6,193		—		—
Total available for sale	$	234,286	$	148,456	$	85,830	$	—



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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

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, 2015 and 2014. 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, 2015 and 2014.



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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 condensed balance sheet of El Paso Electric Company (the "Company") as of June 30, 2015, the related condensed statements of operations, and comprehensive operations, for the three-month, six-month, and twelve-month periods ended June 30, 2015 and 2014, and the related condensed statements of cash flows for the six-month periods ended June 30, 2015 and 2014. 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 condensed 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, 2014, 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 27, 2015, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying condensed balance sheet as of December 31, 2014 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, 2015



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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 2014 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 fully and timely 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 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,


•	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 U.S. health care reform legislation,


•	the impact of changing cost escalation and other assumptions on our nuclear decommissioning liability for Palo Verde, as well as actual and assumed investment returns on decommissioning trust fund assets,


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


•	possible physical or cyber attacks, intrusions or other catastrophic events,


•	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,


•	loss of key personnel, our ability to recruit and retain qualified employees and our ability to successfully implement succession planning, 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 2014 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

Our financial statements have been prepared in conformity with GAAP. We believe that of our significant accounting policies, the following are noteworthy because they are based on estimates and assumptions that require complex, subjective assumptions by management, which can materially impact reported results. Changes in these estimates or assumptions, or actual results that are different, could materially impact our financial condition and results of operation.

Regulatory Accounting

We apply accounting standards that recognize the economic effects of rate regulation in our Texas, New Mexico and FERC jurisdictions. As a result, we record certain costs or obligations as either assets or liabilities on our balance sheet and amortize them in subsequent periods as they are reflected in regulated rates. The deferral of costs as regulatory assets is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific regulatory orders, regulatory precedent and the current regulatory environment. As of June 30, 2015, we had recorded regulatory assets currently subject to recovery in future rates of approximately $109.2 million and regulatory liabilities of approximately $24.1 million. Included in regulatory assets are regulatory tax assets of approximately $64.6 million primarily related to the regulatory treatment of the equity portion of allowance for funds used during construction ("AFUDC") and state deferred income taxes.

In the event we determine that we can no longer apply the FASB guidance for regulated operations to all or a portion of our operations or to the individual regulatory assets recorded, based on regulatory action, we could be required to record a charge against income in the amount of the unamortized balance of the related regulatory assets. Such an action could materially reduce our total assets, specifically our total deferred charges and other assets, and shareholders' equity.

Collection of Fuel Expense

In general, by law and regulation, our actual fuel and purchased power expenses are recovered from our customers. In times of rising fuel prices, we experience a lag in recovery of higher fuel costs. These costs are subject to reconciliation by the PUCT on a periodic basis not to exceed three years and a minimum of one year. The NMPRC, in its discretion, may order that a prudence review be conducted to assure that fuel and purchased power costs recovered from customers are prudently incurred. Prior to the completion of a reconciliation proceeding or audit, we record fuel transactions such that fuel revenues, including fuel costs recovered through base rates in New Mexico, equal fuel expense. In the event that a disallowance of fuel cost recovery occurs during a reconciliation proceeding or an audit, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we could incur a loss to the extent of the disallowance.

The Company’s Texas fuel and purchased power costs through March 31, 2013 were reconciled in PUCT Docket No. 41852. As of June 30, 2015, Texas jurisdictional fuel and purchased power costs subject to a future Texas fuel reconciliation are approximately $342.2 million. The NMPRC approved the continuation of its use of the Fuel and Purchase Power Cost Adjustment Clause without modification and the Company’s application requesting reconciliation of fuel and purchased power costs through



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December 2012 in Case No. 13-00380-UT. New Mexico jurisdictional costs subject to prudence review are for costs from January 2013 through June 30, 2015 and are approximately $164.8 million.

The Company recovers fuel and purchased power costs from the Rio Grande Electric Cooperative ("RGEC") pursuant to an ongoing contract with a two-year notice to terminate provision. The contract includes a fuel adjustment clause designed to recover all eligible fuel and purchased power costs allocable to the RGEC and is updated on an annual basis. This update is reviewed and approved by the RGEC annually in February following the prior calendar year. As of June 30, 2015, the RGEC fuel costs subject to review are approximately $0.7 million.

Decommissioning Costs and Estimated Asset Retirement Obligation

Pursuant to the Arizona Nuclear Power Project Participation Agreement (the "ANPP Participation Agreement"), the rules and regulations of the Nuclear Regulatory Commission and federal law, we must fund our share of the estimated costs to decommission Palo Verde Units 1, 2, 3 and associated common areas. The determination of the estimated liability is based on site-specific estimates, which are updated every three years and involve numerous judgments and assumptions, including estimates of future decommissioning costs at current price levels, escalation rates, and discount rates. The Palo Verde Asset Retirement Obligation ("ARO") is approximately $69.7 million and represents approximately 89% of our total ARO balance of $78.0 million at June 30, 2015. A 10% increase in the estimates of future Palo Verde decommissioning costs at current price levels would have increased the ARO liability by $6.1 million at June 30, 2015.

We are required to fund estimated nuclear decommissioning costs monthly over the life of the generating facilities through the use of external trust funds pursuant to rules of the Nuclear Regulatory Commission and PUCT and the ANPP Participation Agreement. Historically, we have been permitted to collect in rates in Texas and New Mexico the funding requirements for our nuclear decommissioning trusts, except for a portion of Palo Verde Unit 3, which is deregulated in the New Mexico jurisdiction.

The funding amounts are based on assumptions about future investment returns and future decommissioning cost escalations. If the rates of return earned by the trusts fail to meet expectations or if estimated costs to decommission the nuclear plant increase, we could be required to increase our funding to the nuclear decommissioning trusts.

Our decommissioning trust funds consist of equity securities and fixed income instruments and are carried at fair value. We face interest rate risk on the fixed income instruments, which consist primarily of municipal, federal and corporate bonds and which were valued at $112.9 million as of June 30, 2015. A hypothetical 10% increase in interest rates would reduce the fair values of these funds by $1.4 million on their fair values at June 30, 2015. Our decommissioning trust funds also include marketable equity securities of approximately $118.4 million at June 30, 2015. A hypothetical 20% decrease in equity prices would reduce the fair values of these funds by $23.7 million based on their fair values at June 30, 2015. Declines in market prices could require that additional amounts be contributed to our nuclear decommissioning trusts to maintain minimum funding requirements.

We do not anticipate expending monies held in the nuclear decommissioning trusts before 2044 or a later period when we begin to decommission Palo Verde.

Future Pension and Other Post-retirement Obligations

We maintain a qualified noncontributory defined benefit pension plan, which covers substantially all employees, and two non-funded nonqualified supplement plans which provide benefits in excess of amounts permitted under the provisions of the tax law for certain participants in the qualified plan. We also sponsor a plan which provides other post-retirement benefits, such as health and life insurance benefits to retired employees. Our obligations under these various benefit plans at June 30, 2015 totaled $153.6 million and are recorded as liabilities on our balance sheet. The net periodic benefit costs for these plans totaled $9.4 million for the twelve months ended June 30, 2015.

Our pension and other post-retirement benefit liabilities and the related net periodic benefit costs are calculated on the basis of a number of actuarial assumptions regarding discount rates, expected return on plan assets, rate of compensation increase, life expectancy of retirees and health care cost inflation. The discount rates used to measure our liabilities are based on a spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. Accordingly, the discount rates range from 3.4% to 4.1% depending upon the benefit plan.

Our overall expected long-term rate of return on assets for the pension trust fund is 7.5% effective January 1, 2015, which is both a pre-tax and after-tax rate as pension funds are generally not subject to income tax. Our overall expected long-term rate of return on assets for the other post-retirement benefits trust, on an after-tax basis, is 5.2% effective January 1, 2015. Both expected long-term rates of return are based on the after-tax weighted average of the expected returns on investments. The expected returns on investments in the pension trust and the other post-retirement benefits trust are based upon the target asset allocations for the two trusts.



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Our accrued post-retirement benefit liability and the service and interest components of the related net periodic benefit costs are calculated using an actuarial assumption regarding health care cost inflation. For measurement purposes, a 7.25% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2015. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan.

The estimated rate of compensation increase used in our Retirement Plans is 4.5% and is based on recent trends for all non-union employees and the amounts we are contractually obligated for union employees.

The following table reflects the sensitivities that a change in certain actuarial assumptions would have had on the June 30, 2015 reported pension liabilities and our 2015 reported pension expense (in thousands):



	Increase (Decrease)
Actuarial Assumption	Impact on Pension Liability			Impact on Pension Expense
Discount rate:
Increase 1%	$	(43,407	)	$	(3,928	)
Decrease 1%		53,825			4,752
Expected long-term rate of return on plan assets:
Increase 1%		N/A			(2,600	)
Decrease 1%		N/A			2,600
Compensation rate:
Increase 1%		7,428			1,578
Decrease 1%		(6,641	)		(1,264	)

The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the June 30, 2015 other postretirement benefit obligations and our 2015 reported other postretirement benefit expense (in thousands):



	Increase (Decrease)
Actuarial Assumption	Impact on Other Post-retirement Benefit Obligation			Impact on Other Post-retirement Benefit Expense
Discount rate:
Increase 1%	$	(13,622	)	$	(1,700	)
Decrease 1%		17,282			2,200
Healthcare cost trend rate:
Increase 1%		1,629			3,300
Decrease 1%		(12,940	)		(2,600	)
Expected long-term rate of return on plan assets-post-tax:
Increase 1%		N/A			(400	)
Decrease 1%		N/A			400

Tax Accruals

We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The application of income tax law and regulations is complex and we must make judgments regarding income tax exposures. Changes in these judgments, due to changes in law, regulation, interpretation, or audit adjustments can materially affect amounts we recognize in our financial statements.

When appropriate, we record a valuation allowance against deferred tax assets to reflect that these tax assets may not be realized. In assessing the likelihood of the realization of deferred tax assets, management considers the estimated amount and character of future taxable income. Significant changes in these judgments and estimates could have a material impact on the



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results of operations and financial position of the Company. There were no valuation allowances for deferred tax assets at June 30, 2015.

We recognize tax benefits that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon settlement. The unrecognized tax benefits that do not meet the recognition and measurement standards are $5.2 million at June 30, 2015.

Summary

The following is an overview of our results of operations for the three, six and twelve month periods ended June 30, 2015 and 2014. Net income and basic earnings per share for the three, six and twelve month periods ended June 30, 2015 and 2014 are shown below:



	Three Months Ended				Six Months Ended				Twelve Months Ended
	June 30,				June 30,				June 30,
	2015		2014		2015		2014		2015		2014
Net income (in thousands)	$	21,072	$	30,096	$	24,530	$	34,711	$	81,247	$	86,467
Basic earnings per share	0.52		0.75		0.61		0.86		2.01		2.15

Regulatory Lag

Our results of operations for the three, six, and twelve months ended June 30, 2015 compared to the same periods in 2014 have been negatively impacted as a result of the completion and the placement in service of MPS Units 1 & 2 (including common plant, transmission lines and substation) and the Eastside Operations Center ("EOC") in the first quarter of 2015, without a corresponding increase in revenues. The primary impact from these assets being placed in service include a reduction in amounts capitalized for AFUDC, and increases in depreciation, operation and maintenance expense, property taxes, and interest cost during the three and six month periods.

The following table and accompanying explanations show the primary factors affecting the after-tax change in net income between the 2015 and 2014 periods presented (in thousands):



	Three Months Ended			Six Months Ended			Twelve Months Ended
June 30, 2014 net income	$	30,096		$	34,711		$	86,467
Change in (net of tax):
Increased operations and maintenance at fossil fuel generating plants (a)	(2,711		)	(2,782		)	(4,630		)
(Decreased) increased allowance for funds used during construction (b)	(1,567		)	411			5,048
Palo Verde performance rewards, net (c)	(1,415		)	(1,415		)	(1,415		)
Increased depreciation and amortization (d)	(1,333		)	(1,981		)	(2,627		)
Decreased retail non-fuel base revenues (e)	(1,234		)	(768		)	(611		)
Increased interest on long-term debt (f)	(1,227		)	(2,465		)	(2,733		)
Deregulated Palo Verde unit 3 (g)	(1,086		)	(1,919		)	(721		)
Decreased (increased) Palo Verde operations and maintenance expense (h)	1,533			1,212			(360		)
Decreased (increased) pensions and benefits (i)	351			(209		)	1,893
Other	(335		)	(265		)	936
June 30, 2015 net income	$	21,072		$	24,530		$	81,247

______________



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(a)	Operations and maintenance at our fossil fuel generating plants increased for the three, six and twelve month periods ended June 30, 2015 compared to the same periods last year, primarily due to maintenance at the Newman and Four Corners power stations and increased operations and maintenance at the MPS in 2015 with no comparable amount in the same periods last year.

(b)

AFUDC decreased for the three months ended June 30, 2015 due to lower balances of construction work in progress ("CWIP"), primarily due to MPS Units 1 and 2, and the EOC being placed in service during the first quarter of 2015. AFUDC increased for the twelve months ended June 30, 2015 due to higher balances of CWIP that existed prior to MPS Units 1 and 2, and the EOC being placed in service during the first quarter of 2015.


(c)	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.


(d)	Depreciation and amortization increased for the three, six and twelve month periods ended June 30, 2015, compared to the same periods last year primarily due to an increase in depreciable plant, primarily due to MPS Units 1 and 2, and the EOC being placed in service during the first quarter of 2015.

(e)

Retail non-fuel base revenues decreased for the three, six and twelve months ended June 30, 2015 compared to the same periods last year primarily due to a reduction in revenues from sales to public authorities which was partially caused by the use of an interruptible rate at a military installation in our service territory. The decrease for the six and twelve month periods were partially offset by increased non-fuel base revenues from our residential customers reflecting a 1.3% increase in the average number of residential customers served. Retail non-fuel revenues exclude fuel recovered through New Mexico base rates. For a complete discussion of non-fuel base revenues, see page 35.


(f)	Interest on long-term debt increased for the three, six and twelve month periods ended June 30, 2015 compared to the same periods last year due to interest on the $150 million of 5.00% senior notes issued in December 2014.

(g)

Decreased deregulated Palo Verde Unit 3 revenues reflecting a decrease in proxy market prices for the three, six and twelve month periods of 13%, 26% and 18%, respectively, due to a decline in the price of natural gas as well as decreased generation for the three and six month periods in 2015 due to a scheduled 2015 spring refueling outage that was completed in May 2015 with no comparable outage in 2014.


(h)	Palo Verde operations and maintenance expenses decreased for the three and six months ended June 30, 2015 compared to the same periods last year primarily due to decreased administrative and general expenses.

(i)

Pensions and benefits decreased for the three and twelve months ended June 30, 2015 compared to the same periods last year due to a reduction in medical claims and changes in actuarial assumptions used to calculate expenses for our pension plan. The twelve months ended was partially offset by increased Company 401k contributions. The increase for the six months ended June 30, 2015 is due to changes in actuarial assumptions used to calculate expense for our other post-retirement employee benefit and pension plans, and increased Company 401k contributions.



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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, 2015, retail non-fuel base revenues were negatively impacted by milder weather when compared to the same periods in 2014. Cooling degree days in the second quarter of 2015 decreased 15.2% when compared to the same period in 2014 and were 11.5% below the 10-year average. Cooling degree days for the six months ended June 30, 2015 decreased 14.0% compared to the same period last year and were 10.7% below the 10-year average. For the twelve months ended June 30, 2015, cooling degree days decreased 4.9%, when compared to the same period last year and were 5.7% below the 10-year average. For the six months ended June 30, 2015, heating degree days increased 15.7% when compared to the same period last year, but were 3.2% below than the 10-year average. Heating degree days for the twelve months ended June 30, 2015 were relatively unchanged when compared to the same period last year, but were 5.4% below than the 10-year average. 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
	2015	2014	Average	2015	2014	Average	2015	2014	Average*
Heating degree days	53	84	66	1,206	1,042	1,246	2,064	2,049	2,182
Cooling degree days	929	1,095	1,050	963	1,120	1,078	2,514	2,644	2,667

______________

* 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, 2015 when compared to the same periods last year and 1.3% for the twelve month period. See the tables presented on pages 37, 38 and 39 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 $1.9 million, or 1.3% for the three months ended June 30, 2015, when compared to the same period last year. The decrease in retail non-fuel base revenues includes a $1.6 million decrease from sales to public authorities reflecting a military installation moving a portion of their load to an interruptible rate as well as a 3.5% decrease in kWh sales reflecting energy savings from energy conservation and efficiency programs and use of solar distributed generation at military installations. Retail non-fuel base revenues from residential customers decreased by $0.4 million due to a 1.4% decrease in kWh sales reflecting milder weather during the quarter compared to the same period in 2014, despite a 1.3% increase in the average number of residential customers served.

Retail non-fuel base revenues decreased $1.2 million, or 0.5% for the six months ended June 30, 2015, when compared to the same period last year. The decrease includes a $2.0 million decrease from sales to public authorities reflecting a military installation



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moving a portion of their load to an interruptible rate as well as a 1.9% decrease in kWh sales reflecting energy savings from energy conservation and efficiency programs and use of solar distributed generation at military installations. The decrease in retail non-fuel base revenues was partially offset by a $0.9 million increase in non-fuel base revenues from sales to residential customers due to a 1.3% increase in the average number of residential customers served partially offset by milder weather during 2015.

Retail non-fuel base revenues decreased $0.9 million, or 0.2% for the twelve months ended June 30, 2015, when compared to the same period last year. The decrease includes a $5.1 million decrease from sales to public authorities reflecting a military installation moving a portion of their load to an interruptible rate as well as a 3.5% decrease in kWh sales reflecting energy savings from energy conservation and efficiency programs and use of solar distributed generation at military installations. Retail non-fuel base revenues from sales to residential customers increased by $3.5 million due to a 1.4% increase in kWh sales reflecting a 1.3% increase in the average number of residential customers served. Retail non-fuel base revenues from sales to small commercial and industrial customers increased $1.6 million when compared to the same period in 2014 due to a 1.3% increase in kWh sales reflecting a 1.9% increase in the average number of small commercial and industrial customers served.

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 defined as material when they exceed 4% of the previous twelve months' fuel costs.

In the three months ended June 30, 2015, we under-recovered our fuel costs by $4.9 million. In the six and twelve months ended June 30, 2015, we over-recovered our fuel costs by $10.8 million and $21.1 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 July 2014, the PUCT approved a settlement in the Texas fuel reconciliation proceeding designated as PUCT Docket No. 41852 and financial implications of the settlement were recorded in the second quarter of 2014 increasing fuel revenues by $2.2 million. In September 2014 and March 2015 , $7.9 million and $5.8 million, respectively, were credited to customers through the applicable fuel adjustment clauses as the result of a reimbursement from the DOE related to spent nuclear fuel storage. At June 30, 2015, we had a net fuel over-recovery balance of $1.5 million, including $1.1 million in Texas and $0.4 million in New Mexico.

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. Palo Verde's availability is an important factor in realizing these off-system sales margins.

Off-system sales revenues decreased $8.1 million, or 38.5% for the three months ended June 30, 2015, when compared to the same period last year, as a result of lower average market prices for power and an 8.5% decrease in kWh sales. Retained margins from off-system sales decreased $0.2 million, or 49.1% for the three months ended June 30, 2015, compared to the same period last year. Off-system sales revenues decreased $19.9 million, or 39.9% for the six months ended June 30, 2015, when compared to the same period last year, as a result of lower average market prices for power and a 4.9% decrease in kWh sales. Retained margins from off-system sales decreased $0.6 million for the six months ended June 30, 2015, compared to the same period last year. Off-system sales revenues decreased $16.6 million, or 17.5% for the twelve months ended June 30, 2015, when compared to the same period last year, as a result of lower average market prices for power. Retained margins from off-system sales decreased $0.4 million for the twelve months ended June 30, 2015, 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:	2015		2014		Amount			Percent
kWh sales:
Retail:
Residential	640,940		650,003		(9,063		)	(1.4	)%
Commercial and industrial, small	626,968		620,630		6,338			1.0
Commercial and industrial, large	278,822		292,113		(13,291		)	(4.5	)
Sales to public authorities	419,882		434,930		(15,048		)	(3.5	)
Total retail sales	1,966,612		1,997,676		(31,064		)	(1.6	)
Wholesale:
Sales for resale	20,504		20,328		176			0.9
Off-system sales	517,752		565,853		(48,101		)	(8.5	)
Total wholesale sales	538,256		586,181		(47,925		)	(8.2	)
Total kWh sales	2,504,868		2,583,857		(78,989		)	(3.1	)
Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	59,422	$	59,828	$	(406	)	(0.7	)%
Commercial and industrial, small	53,864		53,675		189			0.4
Commercial and industrial, large	9,879		9,963		(84		)	(0.8	)
Sales to public authorities	25,317		26,915		(1,598		)	(5.9	)
Total retail non-fuel base revenues	148,482		150,381		(1,899		)	(1.3	)
Wholesale:
Sales for resale	689		680		9			1.3
Total non-fuel base revenues	149,171		151,061		(1,890		)	(1.3	)
Fuel revenues:
Recovered from customers during the period	28,949		40,529		(11,580		)	(28.6	)
Under collection of fuel (1)	4,855		15,369		(10,514		)	(68.4	)
New Mexico fuel in base rates	16,437		17,132		(695		)	(4.1	)
Total fuel revenues (2)	50,241		73,030		(22,789		)	(31.2	)
Off-system sales:
Fuel cost	10,419		18,000		(7,581		)	(42.1	)
Shared margins	2,316		2,645		(329		)	(12.4	)
Retained margins	164		322		(158		)	(49.1	)
Total off-system sales	12,899		20,967		(8,068		)	(38.5	)
Other (3)	7,197		6,743		454			6.7
Total operating revenues	$	219,508	$	251,801	$	(32,293	)	(12.8	)
Average number of retail customers (4):
Residential	356,495		352,035		4,460			1.3	%
Commercial and industrial, small	40,213		39,482		731			1.9
Commercial and industrial, large	50		49		1			2.0
Sales to public authorities	5,273		5,108		165			3.2
Total	402,031		396,674		5,357			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 $1.9 million and $3.6 million, respectively.


(3)	Represents revenues with no related kWh sales.


(4)	The number of retail customers is 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:	2015			2014		Amount			Percent
kWh sales:
Retail:
Residential	1,202,593			1,193,033		9,560			0.8	%
Commercial and industrial, small	1,117,034			1,114,549		2,485			0.2
Commercial and industrial, large	531,942			518,665		13,277			2.6
Sales to public authorities	762,975			777,958		(14,983		)	(1.9	)
Total retail sales	3,614,544			3,604,205		10,339			0.3
Wholesale:
Sales for resale	32,449			32,720		(271		)	(0.8	)
Off-system sales	1,201,281			1,262,867		(61,586		)	(4.9	)
Total wholesale sales	1,233,730			1,295,587		(61,857		)	(4.8	)
Total kWh sales	4,848,274			4,899,792		(51,518		)	(1.1	)
Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	106,362		$	105,422	$	940		0.9	%
Commercial and industrial, small	85,834			85,796		38			—
Commercial and industrial, large	18,128			18,291		(163		)	(0.9	)
Sales to public authorities	42,575			44,571		(1,996		)	(4.5	)
Total retail non-fuel base revenues	252,899			254,080		(1,181		)	(0.5	)
Wholesale:
Sales for resale	1,129			1,128		1			0.1
Total non-fuel base revenues	254,028			255,208		(1,180		)	(0.5	)
Fuel revenues:
Recovered from customers during the period	63,371			71,702		(8,331		)	(11.6	)
Under (over) collection of fuel (1)	(10,832		)	13,359		(24,191		)	—
New Mexico fuel in base rates	32,550			33,227		(677		)	(2.0	)
Total fuel revenues (2)	85,089			118,288		(33,199		)	(28.1	)
Off-system sales:
Fuel cost	23,284			39,463		(16,179		)	(41.0	)
Shared margins	6,252			9,389		(3,137		)	(33.4	)
Retained margins	520			1,124		(604		)	(53.7	)
Total off-system sales	30,056			49,976		(19,920		)	(39.9	)
Other (3)	14,081			13,845		236			1.7
Total operating revenues	$	383,254		$	437,317	$	(54,063	)	(12.4	)
Average number of retail customers (4):
Residential	355,625			351,183		4,442			1.3	%
Commercial and industrial, small	40,127			39,350		777			2.0
Commercial and industrial, large	50			50		—			—
Sales to public authorities	5,245			5,078		167			3.3
Total	401,047			395,661		5,386			1.4

____________


(1)	2015 includes a DOE refund related to spent fuel storage of $5.8 million and 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 $5.0 million and $8.0 million, respectively.


(3)	Represents revenues with no related kWh sales.


(4)	The number of retail customers presented is 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:	2015			2014		Amount			Percent
kWh sales:
Retail:
Residential	2,650,095			2,613,964		36,131			1.4	%
Commercial and industrial, small	2,360,331			2,330,747		29,584			1.3
Commercial and industrial, large	1,077,752			1,077,177		575			0.1
Sales to public authorities	1,547,801			1,604,233		(56,432		)	(3.5	)
Total retail sales	7,635,979			7,626,121		9,858			0.1
Wholesale:
Sales for resale	61,458			61,812		(354		)	(0.6	)
Off-system sales	2,548,183			2,527,228		20,955			0.8
Total wholesale sales	2,609,641			2,589,040		20,601			0.8
Total kWh sales	10,245,620			10,215,161		30,459			0.3
Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	235,311		$	231,834	$	3,477		1.5	%
Commercial and industrial, small	185,426			183,860		1,566			0.9
Commercial and industrial, large	39,076			39,957		(881		)	(2.2	)
Sales to public authorities	90,070			95,171		(5,101		)	(5.4	)
Total retail non-fuel base revenues	549,883			550,822		(939		)	(0.2	)
Wholesale:
Sales for resale	2,278			2,210		68			3.1
Total non-fuel base revenues	552,161			553,032		(871		)	(0.2	)
Fuel revenues:
Recovered from customers during the period	152,721			146,088		6,633			4.5
Under (over) collection of fuel (1)	(21,081		)	15,262		(36,343		)	—
New Mexico fuel in base rates	70,937			71,971		(1,034		)	(1.4	)
Total fuel revenues (2)	202,577			233,321		(30,744		)	(13.2	)
Off-system sales:
Fuel cost	58,537			76,548		(18,011		)	(23.5	)
Shared margins	17,980			16,158		1,822			11.3
Retained margins	1,543			1,924		(381		)	(19.8	)
Total off-system sales	78,060			94,630		(16,570		)	(17.5	)
Other (3) (4)	30,664			29,292		1,372			4.7
Total operating revenues	$	863,462		$	910,275	$	(46,813	)	(5.1	)
Average number of retail customers (5):
Residential	354,497			350,104		4,393			1.3	%
Commercial and industrial, small	39,988			39,226		762			1.9
Commercial and industrial, large	49			50		(1		)	(2.0	)
Sales to public authorities	5,173			5,053		120			2.4
Total	399,707			394,433		5,274			1.3

______________


(1)	2015 includes two DOE refunds related to spent fuel storage which total $13.7 million offset in part by $2.2 million related to Palo

Verde performance rewards, net.

(2) Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $12.0 million and $13.2 million, respectively.

(3) Includes an Energy Efficiency Bonus of $2.0 million and $0.3 million in 2015 and 2014, respectively.

(4) Represents revenues with no related kWh sales.

(5) The number of retail customers presented is 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. After adding the new natural gas generating units into the Company's system generation resources, Palo Verde represents approximately 31% of our net dependable generating capacity and approximately 50%, 56% and 53% of our Company-generated energy for the three, six and twelve months ended June 30, 2015, 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 decreased $26.2 million or 29.9% for the three months ended June 30, 2015, when compared to the same period in 2014, primarily due to (i) decreased natural gas costs of $19.2 million due to a 35.1% decrease in the average price of natural gas, (ii) decreased total purchased power costs of $6.4 million due to a 37.0% decrease in the MWhs purchased and a 2.8% decrease in the average cost of purchased power, and (iii) decreased nuclear fuel expense of $1.3 million due to an 11.9% decrease in the average cost of nuclear fuel consumed. The decrease in energy expenses was partially offset by increased coal costs of $0.7 million due to a 25.7% increase in the MWhs generated with coal.



	Three Months Ended June 30,
	2015					2014
Fuel Type	Cost		MWh	Cost per MWh		Cost		MWh	Cost per MWh
	(in thousands)					(in thousands)
Natural gas	$	35,349	1,025,980	$	34.45	$	54,546	1,027,544	$	53.08
Coal	3,600		173,427	20.76		2,925		137,988	21.20
Nuclear	10,864		1,203,902	9.02		12,201		1,191,898	10.24
Total	49,813		2,403,309	20.73		69,672		2,357,430	29.55
Purchased power:
Photovoltaic	7,126		87,655	81.30		6,419		79,385	80.86
Other	4,616		164,194	28.11		11,709		320,130	39.83
Total purchased power	11,742		251,849	46.62		18,128		399,515	47.98
Total energy	$	61,555	2,655,158	23.18		$	87,800	2,756,945	32.23

Energy expenses decreased $46.8 million or 29.8% for the six months ended June 30, 2015, when compared to the same period in 2014, primarily due to (i) decreased natural gas costs of $26.0 million due to a 33.0% decrease in the average price of natural gas, (ii) decreased total purchased power of $13.1 million due to a 27.4% decrease in the MWhs purchased and a 14.8% decrease in the average price of total purchased power, and (iii) decreased nuclear fuel expense of $8.5 million as a result of a $6.4 million settlement with the DOE for reimbursement of spent fuel storage recorded in 2015 and an 8.8% decrease in the average cost of nuclear fuel consumed. The decrease in energy expenses was partially offset by increased coal costs of $0.8 million due to a 14.1% increase in the MWhs generated with coal.



	Six Months Ended June 30,
	2015					2014
Fuel Type	Cost		MWh	Cost per MWh		Cost		MWh	Cost per MWh
	(in thousands)					(in thousands)
Natural gas	$	64,097	1,694,555	$	37.83	$	90,123	1,595,288	$	56.49
Coal	6,716		310,645	21.62		5,893		272,224	21.65
Nuclear (a)	16,729		2,566,096	9.01		25,242		2,555,975	9.88
Total	87,542		4,571,296	20.55		121,258		4,423,487	27.41
Purchased power:
Photovoltaic	11,929		146,714	81.31		9,624		108,184	88.96
Other	10,988		405,907	27.07		26,419		653,448	42.02
Total purchased power	22,917		552,621	41.47		36,043		761,632	48.69
Total energy	$	110,459	5,123,917	22.81		$	157,301	5,185,119	30.54

_______________

(a) Cost includes a DOE settlement of $6.4 million recorded in March 2015. Cost per MWh excludes this settlement.



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Energy expenses decreased $42.8 million or 13.7% for the twelve months ended June 30, 2015, when compared to the same period in 2014, primarily due to (i) decreased total purchased power of $17.9 million due to a 25.6% decrease in the MWhs purchased, (ii) decreased nuclear fuel expense of $16.2 million as a result of an $8.5 million and a $6.4 million settlement with the DOE for reimbursement of spent fuel storage recorded in third quarter of 2014 and first quarter of 2015, respectively and (iii) decreased natural gas costs of $9.9 million due to a 10.4% decrease in the average price of natural gas. The decrease in energy expenses was partially offset by increased coal costs of $1.1 million due to a 8.7% increase in the MWhs generated with coal.



	Twelve Months Ended June 30,
	2015					2014
Fuel Type	Cost		MWh	Cost per MWh		Cost		MWh	Cost per MWh
	(in thousands)					(in thousands)
Natural gas	$	170,807	3,873,476	$	44.10	$	180,661	3,671,184	$	49.21
Coal	13,706		634,673	21.60		12,564		583,871	21.52
Nuclear (a)	32,776		5,116,789	9.33		48,972		4,969,275	9.85
Total	217,289		9,624,938	24.13		242,197		9,224,330	26.26
Purchased power:
Photovoltaic	21,880		266,509	82.10		15,859		163,047	97.27
Other	29,798		914,970	32.57		53,757		1,424,428	38.47
Total purchased power	51,678		1,181,479	43.74		69,616		1,587,475	44.51
Total energy	$	268,967	10,806,417	26.27		$	311,813	10,811,805	28.94

_______________

(a) Cost includes DOE settlements of $6.4 million and $8.5 million recorded in first quarter of 2015 and third quarter of 2014, respectively. Cost per MWh excludes these settlements.

Other operations expense

Other operations expense decreased $2.6 million, or 4.4% for the three months ended June 30, 2015, compared to the same period last year, primarily due to a $2.1 million decrease in operation costs at Palo Verde and a $2.2 million decrease in administrative and general expense, reflecting reductions in costs related to injuries and damages, regulatory expenses, and employee 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. These decreases were partially offset by increased operation expenses related to our fossil-fuel generating plants and operation expenses at our MPS with no comparable expenses during the same period last year.

Other operations expense decreased $3.2 million, or 2.7% for the six months ended June 30, 2015, compared to the same period last year, primarily due to a $3.6 million decrease in administrative and general expense, reflecting reductions in costs related to legal and consulting services and regulatory expenses as well as a $2.3 million decrease in operation costs at Palo Verde. These decreases were partially offset by increased operation expenses related to our fossil-fuel generating plants and operation expenses at our MPS with no comparable expenses during the same period last year.

Other operations expense decreased $2.9 million, or 1.2% for the twelve months ended June 30, 2015, compared to the same period last year, primarily due to a $8.5 million decrease in administrative and general expense reflecting reductions in costs related to legal and consulting services, employee pension and benefits expense as a result of changes in actuarial assumptions used to calculate expenses for our pension plan and plan modifications, and regulatory expenses. These decreases were partially offset by increased operation expenses related to our fossil-fuel generating plants.

Maintenance expense

Maintenance expense increased $3.9 million or 24.5%, $5.2 million or 17.2%, and $8.1 million or 12.8% for the three, six and twelve months ended June 30, 2015, respectively, compared to the same period last year, primarily related to our fossil-fuel generating plants due to an increased level of maintenance activity at our Newman and Four Corners plants and maintenance expenses at MPS with no comparable expense during the same period last year.



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Depreciation and amortization expense

Depreciation and amortization expense increased $2.1 million or 9.7%, $3.0 million or 7.3%, and $4.0 million or 4.9% for the three, six, and twelve month periods ended June 30, 2015, respectively, compared to the same periods last year primarily due to the increase in depreciable plant balances including MPS Units 1 & 2 and the EOC which were placed in service during the first quarter of 2015.

Taxes other than income taxes

Taxes other than income taxes for the three and twelve months ended June 30, 2015 were comparable to the same period in the prior year. Taxes other than income taxes decreased $1.3 million, or 4.3% for the six months ended June 30, 2015 compared to the same period in the prior year primarily due to decreased property 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 months ended June 30, 2014.

Other income (deductions)

Other income (deductions) decreased $2.5 million, or 46.0% for the three months ended June 30, 2015, compared to the same period last year, primarily due to decreased allowance for equity funds used during construction ("AEFUDC") resulting from lower average balances of CWIP, increased miscellaneous deductions due to timing of charitable donations, and decreased investment and interest income due to realized gains on equity investments in our decommissioning trusts in 2014 with no comparable activities in the current period.

Other income (deductions) decreased $1.5 million, or 11.0% for the six months ended June 30, 2015, compared to the same period last year, primarily due to decreased miscellaneous other income due to gains recognized on the sales of land and vehicles in 2014 with no comparable amounts in 2015 and increased miscellaneous deductions due to timing of charitable donations. These decreases were partially offset by increased investment and interest income due to realized gains on equity investments in our decommissioning trusts.

Other income (deductions) increased $4.9 million, or 22.4% for the twelve months ended June 30, 2015, compared to the same period last year, primarily due to increased investment and interest income due to realized gains on equity investments in our decommissioning trusts and increased AEFUDC resulting from higher average balances of CWIP. These increases were partially offset by decreased gains recognized on the sales of land and vehicles in 2014 with no comparable amounts in 2015

Interest charges (credits)

Interest charges (credits) increased by $2.6 million, or 21.9%, for the three months ended June 30, 2015 compared to the same period last year, primarily due to interest expense on the $150 million of 5.00% Senior Notes due 2044 issued in December 2014 and decreased allowance for borrowed funds used during construction ("ABFUDC") as a result of lower average balances of CWIP.

Interest charges (credits) increased by $3.5 million and $2.9 million, or 14.8% and 6.0%, for the six and twelve months ended June 30, 2015 compared to the same period last year, primarily due to interest expense on the $150 million of 5.00% Senior Notes due 2044 issued in December 2014 and increased interest on short-term borrowing for working capital purposes. These increases were partially offset by an increase in ABFUDC as a result of higher average balances of CWIP that existed prior to MPS 1 and 2, and the EOC being placed in service during the first quarter of 2015.

Income tax expense

Income tax expense decreased $5.3 million or 35.6% for the three months ended June 30, 2015, compared to the same period last year, primarily due to decreased pre-tax income, and a decrease in the AEFUDC. Income tax expense decreased $5.7 million or 35.4% for the six months ended June 30, 2015, compared to the same period last year, primarily due to decreased pre-tax income. Income tax expense decreased $5.3 million or 13.1% for the twelve months ended June 30, 2015, compared to the same period last year, primarily due to decreased pre-tax income and an increase in domestic production activities deduction earned in the third quarter of 2014.

New Accounting Standards

In May 2014, the FASB issued new guidance (Accounting Standards Update ("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 intended to clarify the principles for recognizing



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revenue and to develop a common revenue standard for U.S. GAAP and International Financial 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 was originally intended to be effective for annual periods and interim periods within that reporting period beginning after December 15, 2016, for public business entities. On April 1, 2015, the FASB voted to propose to defer the effective date to December 15, 2017. Early adoption of ASU 2014-09 is permitted after December 15, 2016. We are currently assessing the future impact of this ASU.

In April 2015, the FASB issued new guidance (ASU 2015-03, Interest - Imputation of Interest (Topic 715)) to simplify the presentation of debt issuance costs. ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this ASU. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. We do not expect this ASU will materially impact our balance sheet.

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, 2015, our capital structure, including common stock, long-term debt, current maturities of long-term debt, and short-term borrowings under the revolving credit facility ("RCF"), consisted of 43.5% common stock equity and 56.5% debt. At June 30, 2015, we had a balance of $10.4 million in cash and cash equivalents. Based on current projections, we believe that we will have adequate liquidity through our current cash balances, cash from operations, and available borrowings under the RCF to meet all of our anticipated cash requirements for the next twelve months. We may issue long-term debt in the capital markets to finance future capital requirements in late 2015 or early 2016.

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, taxes, and payment of our $15 million Series A 3.67% Senior Note which matures in August 2015.

Capital Requirements. During the six months ended June 30, 2015, 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 the MPS. Units 1 and 2, the first two (of four) natural gas-fired 88 MW simple-cycle aeroderivative combustion turbines, were completed and placed in service during the first quarter of 2015. The total cost for these two units and the related common facilities and transmission systems, including AFUDC, was approximately $227.2 million. Units 3 and 4 are projected to be completed in 2016. In 2015 we incurred approximately $67.1 million in cost for the MPS, including AFUDC. Estimated cash construction expenditures for the MPS in 2015 are approximately $110.2 million and estimated construction expenditures for all capital projects for 2015 are approximately $276.3 million. See Part I, Item 1, “Business - Construction Program” in our 2014 Form 10-K. Cash capital expenditures for new electric plant were $147.0 million in the six months ended June 30, 2015 compared to $106.0 million in the six months ended June 30, 2014. Capital requirements for purchases of nuclear fuel were $22.4 million for the six months ended June 30, 2015 compared to $17.7 million for the six months ended June 30, 2014.

On June 30, 2015, we paid a quarterly cash dividend of $0.295 per share or $11.9 million to shareholders of record as of June 16, 2015. We have paid a total of $23.2 million in cash dividends during the six months ended June 30, 2015. On July 23, 2015, the Board of Directors declared a quarterly cash dividend of $0.295 per share payable on September 30, 2015 to shareholders of record as of September 16, 2015. At the current payout rate, we would expect to pay total cash dividends of approximately $47.1 million during 2015. In addition, while we do not currently anticipate repurchasing shares in 2015, we may repurchase common stock in the future. Under our program, purchases can be made at open market prices or in private transactions, and repurchased shares are available for issuance under employee benefit and stock incentive plans, or may be retired. No shares of common stock were repurchased during the six months ended June 30, 2015. As of June 30, 2015, 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. We primarily utilize the distribution of dividends to maintain a balanced capital structure and supplement this effort with 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.

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. Income tax payments are expected to be minimal in 2015 due to accelerated tax deductions, including bonus depreciation, available in 2015.

We continually evaluate our funding requirements related to our retirement plans, other post-retirement benefit plans, and decommissioning trust funds. We contributed $6.6 million of the projected $11.1 million 2015 annual contribution to our retirement plans and $2.3 million of the projected $4.5 million 2015 annual contribution to our nuclear decommissioning trust funds during the six months ended June 30, 2015. In the six months ended June 30, 2015, 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 2015. 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 ANPP Participation Agreement for our nuclear decommissioning trust.

In 2010, the Company and Rio Grande Resources Trust (“RGRT”), a Texas grantor trust through which we finance our portion of fuel for Palo Verde, entered into a note purchase agreement with various institutional purchasers. Under the terms of the agreement, RGRT sold to the purchasers $110.0 million aggregate principal amount of senior notes. In August 2015, $15.0 million of these senior notes will mature.



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Capital Resources. Cash provided by operations, $60.4 million for the six months ended June 30, 2015 and $57.0 million for the six months ended June 30, 2014, is a significant source for funding capital requirements. Cash from operations has been impacted by the timing of the recovery of fuel costs through fuel recovery mechanisms in Texas and New Mexico and our sales for resale customer. We recover actual fuel costs from customers through fuel adjustment mechanisms in Texas, New Mexico, and from our sales for resale customer. We record deferred fuel revenues for the under-recovery or over-recovery of fuel costs until they can be recovered from or refunded to customers. In Texas, fuel costs are recovered through a fixed fuel factor. 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 May 1, 2015, we reduced our fixed fuel factor charged to our Texas retail customers by approximately 24% to reflect reduced fuel expense. During the six months ended June 30, 2015, we had an over-recovery of fuel costs of $10.8 million compared to an under-recovery of fuel costs of $13.4 million during the six months ended June 30, 2014. At June 30, 2015, we had a net fuel over-recovery balance of $1.5 million, including $1.1 million in Texas, and $0.4 million in New Mexico.

The Company expects 2015 earnings to be adversely impacted by the regulatory lag resulting from placing into service during the first quarter, the first two generating units at MPS together with the related transmission lines and substation as well as the EOC. We incurred approximately $267.7 million in construction costs of these facilities. With the introduction of these facilities into service, we have begun to incur increased expenses related to depreciation, operations and maintenance, property taxes, and interest cost. Furthermore, we have ceased recognizing AFUDC on these facilities. We have filed for an increase in base rates for our New Mexico service territory on May 11, 2015. We also plan to file for a base rate increase in our Texas territory in early August 2015; and we expect new rates to become effective early in the second quarter of 2016 in both jurisdictions.

We maintain a RCF for working capital and general corporate purposes and the financing of nuclear fuel through the 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 $128.1 million at June 30, 2015, of which $18.1 million had been borrowed under the RCF and $110.0 million was borrowed through senior notes. As of June 30, 2015, the amount available for borrowing under our $300 million RCF is $171.5 million. At June 30, 2014, the total amounts borrowed for nuclear fuel by RGRT was $126.8 million of which $16.8 million was borrowed under the RCF and $110.0 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, 2015, $110.0 million was outstanding under the RCF for working capital or general corporate purposes and at June 30, 2014, $81.0 million was outstanding under the RCF for working capital or general corporate purposes.

We believe that we have adequate liquidity through our current cash balances, cash from operations, available borrowings under the RCF, and our favorable access to capital markets 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. The FERC approval was effective on November 15, 2013 and terminates two years thereafter. The NMPRC approval was effective on October 30, 2013 and remains in effect until the debt is issued. In December 2014, we issued $150 million of 5.00% Senior Notes pursuant to these approvals. The authorizations to issue up to an additional $150 million of long-term debt and up to $50 million of new long-term debt by RGRT provides us with the flexibility to access the debt capital markets prior to the termination of the FERC approval on November 15, 2015. Additionally, we could request approval from the FERC to issue additional debt after November 15, 2015. We may decide to issue long-term debt in the capital markets to finance capital requirements in late 2015 or early 2016.

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.



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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 2014 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, 2015, 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 2014 Form 10-K Annual Report.


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, 2015, our disclosure controls and procedures are effective.

Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting in connection with the evaluation required by paragraph (d) of the Securities Exchange Act of 1934 Rules 13a-15 or 15d-15, that occurred during the quarter ended June 30, 2015, 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 2014 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, 2015	—	—	—	393,816
May 1 to May 31, 2015	—	—	—	393,816
June 1 to June 30, 2015	—	—	—	393,816


Item 4.	Mine Safety Disclosures

Not Applicable.


Item 5.	Other Information

Franchises

The Company operates under franchise agreements with several cities in its service territory, including one with El Paso, the largest city it serves. The franchise agreement allows the Company to utilize public rights-of-way necessary to serve its customers within El Paso. Pursuant to the franchise agreement, the Company pays to the city of El Paso, on a quarterly basis, a fee equal to 4.00% of gross revenues the Company receives for the generation, transmission and distribution of electrical energy and other services within the city. The 2005 El Paso franchise agreement set the franchise fee at 3.25% of gross revenues, but the 2010 Amendment added an incremental fee equal to 0.75% of gross revenues to be placed in a restricted fund to be used by the city solely for economic development and renewable energy purposes. Any assignment of the franchise agreement, including a deemed assignment as a result of a change in control of the Company, requires the consent of El Paso. The term of the El Paso franchise agreement is set to expire on July 31, 2030.

The Company does not have a written franchise agreement with the city of Las Cruces, the second largest city in its service territory. The Company provides electric distribution service to Las Cruces under an implied franchise by satisfying all obligations under the franchise agreement that expired on April 30, 2009.

Additional 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, 2015



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EL PASO ELECTRIC COMPANY

INDEX TO EXHIBITS




Exhibit Number			Exhibit


4.01			Seventh Supplemental Indenture, dated as of April 11, 2006 to General Mortgage Indenture and Deed of Trust dated as of February 1, 1996 between the Company and U.S. Bank National Association as trustee.

4.02			Eighth Supplemental Indenture, dated as of July 7, 2015 to General Mortgage Indenture and Deed of Trust dated as of February 1, 1996 between the Company and U.S. Bank National Association as trustee.

10.04			Form of Directors' Restricted Stock Award Agreement between the Company and certain directors of the Company. (Identical in all material respects to Exhibit 10.07 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999).

10.05			Franchise Agreement, dated July 12, 2005, between the Company and the City of El Paso. (Previously filed as an exhibit to Exhibit 10.05 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2005).

10.06			Amendment dated November 16, 2010, to the Franchise Agreement between the Company and the City of El Paso, dated July 12, 2005.

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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