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, ~~2016~~2017



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~~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 has 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 or an emerging growth company. See the definitions of “large accelerated ~~filer”,~~filer,” “accelerated ~~filer” and~~filer,” “smaller reporting ~~company”~~company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.



Large accelerated filer	x	Accelerated filer	o

Non-accelerated filer	o	Smaller reporting company	o

		Emerging growth company	o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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, ~~2016,~~2017, there were ~~40,520,871~~40,591,704 shares of the Company’s no par value common stock outstanding.

EL PASO ELECTRIC COMPANY

INDEX TO FORM 10-Q



		Page No.
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Balance Sheets –- June 30, ~~2016~~2017 and December 31, ~~2015~~2016	1
	Statements of Operations – Three Months, Six Months, and Twelve Months Ended June 30, ~~2016~~2017 and ~~2015~~2016	3
	~~Statements~~Statement of Comprehensive Operations –- Three Months, Six Months, and Twelve Months Ended June 30, ~~2016~~2017 and ~~2015~~2016	5
	~~Statements~~Statement of Cash Flows –- Six Months Ended June 30, ~~2016~~2017 and ~~2015~~2016	6
	Notes to Financial Statements	7
	Report of Independent Registered Public Accounting Firm	2927
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3028
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4644
Item 4.	Controls and Procedures	4644
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	4745
Item 1A.	Risk Factors	4745
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47
~~Item 4.~~	~~Mine Safety Disclosures~~	4745
Item 5.	Other Information	4745
Item 6.	Exhibits	4745



	( i)

Table of Contents

PART I. FINANCIAL INFORMATION


Item 1.	Financial Statements

EL PASO ELECTRIC COMPANY

BALANCE SHEETS


	June 30, 2016			December 31, 2015			June 30, 2017			December 31, 2016
	(Unaudited)						(Unaudited)

ASSETS (In thousands)
Utility plant:
Electric plant in service	$	3,783,907		$	3,616,301		$	3,893,461		$	3,791,566
Less accumulated depreciation and amortization	(1,369,646		)	(1,329,843		)	(1,282,795		)	(1,244,332		)
Net plant in service	2,414,261			2,286,458			2,610,666			2,547,234
Construction work in progress	221,607			293,796			146,615			154,738
Nuclear fuel; includes fuel in process of $54,224 and $51,854, respectively	191,925			190,282
Nuclear fuel; includes fuel in process of $59,954 and $57,315, respectively							196,054			194,842
Less accumulated amortization	(75,546		)	(75,031		)	(74,566		)	(75,602		)
Net nuclear fuel	116,379			115,251			121,488			119,240
Net utility plant	2,752,247			2,695,505			2,878,769			2,821,212
Current assets:
Cash and cash equivalents	9,607			8,149			11,275			8,420
Accounts receivable, principally trade, net of allowance for doubtful accounts of $1,570 and $2,046, respectively	105,443			66,326
Accounts receivable, principally trade, net of allowance for doubtful accounts of $1,682 and $2,156, respectively							124,616			88,452
Inventories, at cost	47,376			48,697			50,929			47,216
Under-collection of fuel revenues	30			—			8,515			11,123
Prepayments and other	15,062			9,872			13,727			8,988
Total current assets	177,518			133,044			209,062			164,199
Deferred charges and other assets:
Decommissioning trust funds	248,240			239,035			271,315			255,708
Regulatory assets	116,617			115,127			115,245			118,861
Other	17,640			17,896			17,002			16,298
Total deferred charges and other assets	382,497			372,058			403,562			390,867
Total assets	$	3,312,262		$	3,200,607		$	3,491,393		$	3,376,278

See accompanying notes to financial statements.



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Table of Contents

EL PASO ELECTRIC COMPANY

BALANCE SHEETS (Continued)


	June 30, 2016			December 31, 2015			June 30, 2017			December 31, 2016
	(Unaudited)						(Unaudited)
CAPITALIZATION AND LIABILITIES (In thousands except for share data)
Capitalization:
Common stock, stated value $1 per share, 100,000,000 shares authorized, 65,670,835 and 65,709,819 shares issued, and 157,520 and 118,834 restricted shares, respectively	$	65,828		$	65,829
Common stock, stated value $1 per share, 100,000,000 shares authorized, 65,659,869 and 65,685,615 shares issued, and 169,565 and 137,017 restricted shares, respectively							$	65,829		$	65,823
Capital in excess of stated value	320,572			320,073			323,779			322,643
Retained earnings	1,059,398			1,067,396			1,120,664			1,114,561
Accumulated other comprehensive loss, net of tax	(13,300		)	(13,914		)	(4,133		)	(7,116		)
	1,432,498			1,439,384			1,506,139			1,495,911
Treasury stock, 25,307,484 and 25,384,834 shares, respectively, at cost	(421,558		)	(422,846		)
Treasury stock, 25,232,769 and 25,304,914 shares, respectively, at cost							(420,313		)	(421,515		)
Common stock equity	1,010,940			1,016,538			1,085,826			1,074,396
Long-term debt, net of current portion	1,278,301			1,122,660			1,195,748			1,195,513
Total capitalization	2,289,241			2,139,198			2,281,574			2,269,909
Current liabilities:
Current maturities of long-term debt							83,268			83,143
Short-term borrowings under the revolving credit facility	101,614			141,738			178,884			81,574
Accounts payable, principally trade	44,162			59,978			52,586			62,953
Taxes accrued	25,318			30,351			27,772			32,488
Interest accrued	13,267			12,649			13,373			13,287
Over-collection of fuel revenues	2,063			4,023			314			255
Other	41,950			28,325			33,239			29,709
Total current liabilities	228,374			277,064			389,436			303,409
Deferred credits and other liabilities:
Accumulated deferred income taxes	502,677			495,237			564,377			555,066
Accrued pension liability	87,728			90,527			87,460			92,768
Accrued post-retirement benefit liability	55,677			54,553			35,703			34,400
Asset retirement obligation	85,363			81,621			89,199			81,800
Regulatory liabilities	23,930			24,303			22,253			18,435
Other	39,272			38,104			21,391			20,491
Total deferred credits and other liabilities	794,647			784,345			820,383			802,960
Commitments and contingencies
Total capitalization and liabilities	$	3,312,262		$	3,200,607		$	3,491,393		$	3,376,278

See accompanying notes to financial statements.



	2

Table of Contents

EL PASO ELECTRIC COMPANY

STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands except for share data)


	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
	2016			2015			2016			2015			2017			2016			2017			2016
Operating revenues	$	217,865		$	219,508		$	375,674		$	383,254		$	251,843		$	217,865		$	423,178		$	375,674
Energy expenses:
Fuel	43,143			49,813			77,462			87,542			49,173			43,143			85,779			77,462
Purchased and interchanged power	13,610			11,742			23,256			22,917			16,721			13,610			30,394			23,256
	56,753			61,555			100,718			110,459			65,894			56,753			116,173			100,718
Operating revenues net of energy expenses	161,112			157,953			274,956			272,795			185,949			161,112			307,005			274,956
Other operating expenses:
Other operations	56,817			57,656			115,204			113,255			59,835			56,817			115,958			115,204
Maintenance	20,426			19,857			37,941			35,417			20,415			20,426			41,405			37,941
Depreciation and amortization	23,852			23,135			47,145			44,700			22,495			23,852			44,429			47,145
Taxes other than income taxes	15,320			15,433			30,132			29,591			17,265			15,320			32,995			30,132
	116,415			116,081			230,422			222,963			120,010			116,415			234,787			230,422
Operating income	44,697			41,872			44,534			49,832			65,939			44,697			72,218			44,534
Other income (deductions):
Allowance for equity funds used during construction	2,133			2,268			4,469			6,543			726			2,133			1,541			4,469
Investment and interest income, net	3,591			1,398			6,520			6,652			6,786			3,591			10,772			6,520
Miscellaneous non-operating income	145			507			801			687			39			145			124			801
Miscellaneous non-operating deductions	(890		)	(1,271		)	(1,356		)	(1,762		)	(530		)	(890		)	(1,270		)	(1,356		)
	4,979			2,902			10,434			12,120			7,021			4,979			11,167			10,434
Interest charges (credits):
Interest on long-term debt and revolving credit facility	18,298			16,495			34,897			32,978			18,407			18,298			36,774			34,897
Other interest	272			354			834			517			762			272			1,182			834
Capitalized interest	(1,253		)	(1,261		)	(2,495		)	(2,550		)	(1,344		)	(1,253		)	(2,638		)	(2,495		)
Allowance for borrowed funds used during construction	(1,375		)	(1,391		)	(3,033		)	(4,012		)	(711		)	(1,375		)	(1,502		)	(3,033		)
	15,942			14,197			30,203			26,933			17,114			15,942			33,816			30,203
Income before income taxes	33,734			30,577			24,765			35,019			55,846			33,734			49,569			24,765
Income tax expense	11,450			9,505			8,289			10,489			19,780			11,450			17,492			8,289
Net income	$	22,284		$	21,072		$	16,476		$	24,530		$	36,066		$	22,284		$	32,077		$	16,476

Basic earnings per share	$	0.55		$	0.52		$	0.41		$	0.61		$	0.89		$	0.55		$	0.79		$	0.41

Diluted earnings per share	$	0.55		$	0.52		$	0.41		$	0.61		$	0.89		$	0.55		$	0.79		$	0.41

Dividends declared per share of common stock	$	0.310		$	0.295		$	0.605		$	0.575		$	0.335		$	0.310		$	0.645		$	0.605
Weighted average number of shares outstanding	40,345,150			40,269,885			40,335,236			40,256,615			40,409,030			40,345,150			40,398,192			40,335,236
Weighted average number of shares and dilutive potential shares outstanding	40,399,491			40,302,694			40,380,640			40,284,757			40,525,585			40,399,491			40,499,344			40,380,640

See accompanying notes to financial statements.



	3

Table of Contents

EL PASO ELECTRIC COMPANY

STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands except for share data)


	Twelve Months Ended						Twelve Months Ended
	June 30,						June 30,
	2016			2015			2017			2016
Operating revenues	$	842,289		$	863,462		$	934,440		$	842,289
Energy expenses:
Fuel	178,320			217,289			182,055			178,320
Purchased and interchanged power	53,884			51,678			66,865			53,884
	232,204			268,967			248,920			232,204
Operating revenues net of energy expenses	610,085			594,495			685,520			610,085
Other operating expenses:
Other operations	244,899			235,664			242,768			244,899
Maintenance	67,747			70,819			70,210			67,747
Depreciation and amortization	92,269			86,391			81,601			92,269
Taxes other than income taxes	64,277			61,422			68,396			64,277
	469,192			454,296			462,975			469,192
Operating income	140,893			140,199			222,545			140,893
Other income (deductions):
Allowance for equity funds used during construction	8,565			14,838			4,095			8,565
Investment and interest income, net	17,376			14,121			18,335			17,376
Miscellaneous non-operating income	2,176			2,655			615			2,176
Miscellaneous non-operating deductions	(3,922		)	(4,943		)	(3,613		)	(3,922		)
	24,195			26,671			19,432			24,195
Interest charges (credits):
Interest on long-term debt and revolving credit facility	67,770			62,820			73,421			67,770
Other interest	1,630			1,306			1,651			1,630
Capitalized interest	(4,913		)	(5,115		)	(5,133		)	(4,913		)
Allowance for borrowed funds used during construction	(5,958		)	(8,729		)	(3,452		)	(5,958		)
	58,529			50,282			66,487			58,529
Income before income taxes	106,559			116,588			175,490			106,559
Income tax expense	32,695			35,341			63,121			32,695
Net income	$	73,864		$	81,247		$	112,369		$	73,864

Basic earnings per share	$	1.83		$	2.01		$	2.77		$	1.83

Diluted earnings per share	$	1.83		$	2.01		$	2.77		$	1.83

Dividends declared per share of common stock	$	1.195		$	1.135		$	1.265		$	1.195
Weighted average number of shares outstanding	40,314,032			40,236,466			40,381,776			40,314,032
Weighted average number of shares and dilutive potential shares outstanding	40,356,239			40,263,304			40,466,995			40,356,239

See accompanying notes to financial statements.



	4

Table of Contents

EL PASO ELECTRIC COMPANY

STATEMENTS OF COMPREHENSIVE OPERATIONS

(Unaudited)

(In thousands)


	Three Months Ended						Six Months Ended						Twelve Months Ended						Three Months Ended						Six Months Ended						Twelve Months Ended
	June 30,						June 30,						June 30,						June 30,						June 30,						June 30,
	2016			2015			2016			2015			2016			2015			2017			2016			2017			2016			2017			2016
Net income	$	22,284		$	21,072		$	16,476		$	24,530		$	73,864		$	81,247		$	36,066		$	22,284		$	32,077		$	16,476		$	112,369		$	73,864
Other comprehensive income (loss):
Unrecognized pension and post-retirement benefit costs:
Net gain (loss) arising during period	—			—			—			—			5,429			(74,028		)
Net (loss) gain arising during period																			—			—			—			—			(20,053		)	5,429
Prior service benefit	—			—			—			—			824			34,200			—			—			—			—			32,697			824
Reclassification adjustments included in net income for amortization of:
Prior service benefit	(1,664		)	(1,662		)	(3,330		)	(3,325		)	(6,579		)	(7,455		)	(2,413		)	(1,664		)	(4,829		)	(3,330		)	(8,906		)	(6,579		)
Net loss	1,222			2,250			2,445			4,500			6,567			7,730			1,694			1,222			3,388			2,445			5,908			6,567
Net unrealized gains/losses on marketable securities:
Net holding gains (losses) arising during period	2,790			(1,563		)	4,980			(549		)	2,623			3,210
Reclassification adjustments for net (gains) losses included in net income	(2,110		)	182			(3,498		)	(3,563		)	(11,049		)	(7,946		)
Net unrealized gains on marketable securities:
Net holding gains arising during period																			4,458			2,790			12,179			4,980			15,643			2,623
Reclassification adjustments for net gains included in net income																			(5,166		)	(2,110		)	(7,357		)	(3,498		)	(11,499		)	(11,049		)
Net losses on cash flow hedges:
Reclassification adjustment for interest expense included in net income	123			116			245			230			482			452			132			123			262			245			515			482
Total other comprehensive income (loss) before income taxes	361			(677		)	842			(2,707		)	(1,703		)	(43,837		)
Income tax benefit (expense) related to items of other comprehensive income (loss):
Total other comprehensive (loss) income before income taxes																			(1,295		)	361			3,643			842			14,305			(1,703		)
Income tax benefit (expense) related to items of other comprehensive (loss) income:
Unrecognized pension and post-retirement benefit costs	166			(291		)	222			(622		)	(2,442		)	14,761			261			166			454			222			(4,029		)	(2,442		)
Net unrealized losses (gains) on marketable securities	(149		)	325			(322		)	881			1,625			979			132			(149		)	(989		)	(322		)	(773		)	1,625
Losses on cash flow hedges	(46		)	(43		)	(128		)	(115		)	(216		)	(197		)	(47		)	(46		)	(125		)	(128		)	(336		)	(216		)
Total income tax benefit (expense)	(29		)	(9		)	(228		)	144			(1,033		)	15,543			346			(29		)	(660		)	(228		)	(5,138		)	(1,033		)
Other comprehensive income (loss), net of tax	332			(686		)	614			(2,563		)	(2,736		)	(28,294		)
Other comprehensive (loss) income, net of tax																			(949		)	332			2,983			614			9,167			(2,736		)
Comprehensive income	$	22,616		$	20,386		$	17,090		$	21,967		$	71,128		$	52,953		$	35,117		$	22,616		$	35,060		$	17,090		$	121,536		$	71,128

See accompanying notes to financial statements.



	5

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EL PASO ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)


	Six Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2017			2016
Cash flows from operating activities:
Net income	$	16,476		$	24,530		$	32,077		$	16,476
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service	47,145			44,700			44,429			47,145
Amortization of nuclear fuel	21,957			21,379			21,100			21,957
Deferred income taxes, net	6,695			8,789			15,339			6,695
Allowance for equity funds used during construction	(4,469		)	(6,543		)	(1,541		)	(4,469		)
Other amortization and accretion	8,715			8,888			9,991			8,715
Gain on sale of land	(545		)	—
Gain on sale of property, plant and equipment							—			(545		)
Net gains on sale of decommissioning trust funds	(3,498		)	(3,563		)	(7,357		)	(3,498		)
Other operating activities	721			243			(641		)	721
Change in:
Accounts receivable	(39,117		)	(20,782		)	(32,684		)	(39,117		)
Inventories	1,315			(2,813		)	(2,791		)	1,315
Net over-collection (under-collection) of fuel revenues	(1,990		)	10,833
Net under/over-collection of fuel revenues							2,667			(1,990		)
Prepayments and other	(6,273		)	(7,476		)	(6,294		)	(6,273		)
Accounts payable	(9,345		)	(15,528		)	(1,262		)	(9,345		)
Taxes accrued	(5,437		)	(2,990		)	(4,014		)	(5,437		)
Interest accrued	618			107			86			618
Other current liabilities	13,625			2,669			3,530			13,625
Deferred charges and credits	(5,900		)	(2,068		)	(4,644		)	(5,900		)
Net cash provided by operating activities	40,693			60,375			67,991			40,693
Cash flows from investing activities:
Cash additions to utility property, plant and equipment	(102,785		)	(147,040		)	(108,113		)	(102,785		)
Cash additions to nuclear fuel	(20,478		)	(22,424		)	(20,647		)	(20,478		)
Capitalized interest and AFUDC:
Utility property, plant and equipment	(7,502		)	(10,555		)	(3,043		)	(7,502		)
Nuclear fuel	(2,495		)	(2,550		)
Nuclear fuel and other							(2,638		)	(2,495		)
Allowance for equity funds used during construction	4,469			6,543			1,541			4,469
Decommissioning trust funds:
Purchases, including funding of $2.2 million and $2.3 million, respectively	(44,937		)	(41,029		)
Purchases, including funding of $2.3 million and $2.2 million, respectively							(65,960		)	(44,937		)
Sales and maturities	40,712			37,158			62,531			40,712
Proceeds from sale of land	596			—
Proceeds from sale of property, plant and equipment							—			596
Other investing activities	2,771			82			797			2,771
Net cash used for investing activities	(129,649		)	(179,815		)	(135,532		)	(129,649		)
Cash flows from financing activities:
Dividends paid	(24,474		)	(23,220		)	(26,157		)	(24,474		)
Borrowings under the revolving credit facility:
Proceeds	172,125			167,103			292,404			172,125
Payments	(212,249		)	(53,563		)	(195,094		)	(212,249		)
Proceeds from issuance of senior notes	157,052			—			—			157,052
Other financing activities	(2,040		)	(1,020		)	(757		)	(2,040		)
Net cash provided by financing activities	90,414			89,300			70,396			90,414
Net increase (decrease) in cash and cash equivalents	1,458			(30,140		)
Net increase in cash and cash equivalents							2,855			1,458
Cash and cash equivalents at beginning of period	8,149			40,504			8,420			8,149
Cash and cash equivalents at end of period	$	9,607		$	10,364		$	11,275		$	9,607

See accompanying notes to financial statements.



	6

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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 fiscal year ended December 31, ~~2015~~2016 ~~(the "~~("~~2015~~2016 Form 10-K"). Capitalized terms used in this report and not defined herein have the meaning ascribed to such terms in the ~~2015~~2016 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, ~~2016~~2017 and December 31, ~~2015~~2016; the results of its operations and comprehensive operations for the three, six and twelve months ended June 30, ~~2016~~2017 and ~~2015~~2016; and its cash flows for the six months ended June 30, ~~2016~~2017 and ~~2015~~2016. The results of operations and comprehensive operations for the three and six months ended June 30, ~~2016~~2017 and 2016, and the cash flows for the six months ended June 30, ~~2016~~2017 and 2016, 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 ~~(the "SEC"~~("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.~~Generally Accepted Accounting Principles ("GAAP").

Use of Estimates. The preparation of financial statements in conformity with ~~generally accepted accounting principles~~GAAP 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. The Company evaluates its estimates on an on-going basis, including those related to depreciation, unbilled revenue, income taxes, fuel costs, pension and other post-retirement obligations and asset retirement obligations ("ARO"). Actual results could differ from those estimates.

Revenues. Revenues related to the sale of electricity are generally recorded when service is provided 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 recorded for estimated amounts of energy delivered in the period following the customer's billing cycle to the end of 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 $~~36.5~~36.1 million at June 30, ~~2016~~2017 and $~~21.7~~21.0 million at December 31, ~~2015~~2016. The Company presents revenues net of sales taxes in its statements of operations.

Depreciation. The Company routinely evaluates the depreciable service lives, cost of removal and salvage values of its property, plant and equipment. Depreciation is provided on a straight-line basis over the estimated remaining lives of the assets (ranging in average from 5 to 48 years). When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized.

Supplemental Cash Flow Disclosures (in thousands)
Six Months Ended
June 30,
2016 2015
Cash paid (received) for:
Interest on long-term debt and borrowings under the revolving credit facility $ 35,252
$ 30,922
Income tax paid, net 2,703
1,680
Non-cash investing and financing activities:
Changes in accrued plant additions (6,966 ) (1,227 )
Grants of restricted shares of common stock 1,236
1,106

New Accounting ~~Standards.~~ Standards

In ~~April 2015,~~March 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") ~~2015-03, Interest~~2016-09, Compensation - ~~Imputation of Interest~~Stock Compensation (Topic ~~715)~~718) Improvements to Employee Share-Based Payment Accounting to simplify the ~~presentation~~accounting for share-based payment transactions, including the income tax consequences, classification of ~~debt issuance costs. ASU 2015-03 requires that debt issuance costs related~~awards either as equity or liabilities, and classification on the statements of cash flows. The Company adopted the new standard effective January 1, 2017. The adoption of the new standard did not have a material impact on the Company’s financial condition, results of operations or cash flows. The cumulative effect of the adoption of the new standard was 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~~increase net operating loss carryforward deferred tax assets and ~~measurement guidance for debt issuance costs are not affected~~retained earnings 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.~~ $0.2 million on January 1, 2017.

In ~~August 2015,~~May 2014, the FASB issued ASU ~~2015-15, Interest - Imputation of Interest (Subtopic 835-30),~~2014-09, Revenue from Contracts with Customers (Topic 606) to provide ~~further clarification~~a framework that replaces the existing revenue recognition guidance, and has since modified the standard with several ASUs. The standard provides that an entity should recognize the amount of revenue to ~~ASU 2015-03 as~~which it ~~relates~~expects to be entitled for the transfer of promised goods or services to customers. More specifically, the standard requires entities to recognize revenue through the application of a five-step model, which includes the: (i) identification of the contract; (ii) identification of the performance obligations; (iii) determination of the transaction price; (iv) allocation of the transaction price to the ~~presentation~~performance obligations; and ~~subsequent measurement~~(v) the recognition of debt issuance costs associated with line of credit arrangements. The Company implemented ASU 2015-03 and ASU 2015-15 in the first quarter of 2016, retrospectively to all prior periods presented in the Company's financialrevenue



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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

~~statements. The implementation of ASU 2015-03 did not have a material impact on~~as the ~~Company's results of operations. See Note J.~~

~~In May 2015,~~entity satisfies the FASB issued ASU 2015-07, Fair Value Measurement (Topic 820) to eliminate the requirement to categorize investments in the fair value hierarchy if the fair value is measured at net asset value ("NAV") per share (or its equivalent) using the practical expedient in the FASB’s fair value measurement gui~~dance~~. Reporting entities must still provide sufficient information to enable users to reconcile total investments in the fair value hierarchy and total investments measured at fair value in the financial statements. Additionally, the scope of current disclosure requirements for investments eligible to be measured at NAV will be limited to investments to which the practical expedient is applied. This ASU is effective in fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The ASU requires retrospective application.performance obligations. The Company ~~implemented ASU 2015-07 in~~plans to adopt the first quarter of 2016, retrospectively to all prior periods presented in the Company's fair value disclosures. This guidance required a revision of the fair value disclosures but did not impact the Company's financial statements. The implementation of ASU 2015-07 did not have a material impact on the Company's results of operations. See Note J.

In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes to simplify the presentation of deferred income taxes. ASU 2015-17 requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. ASU 2015-17 can be applied prospectively or retrospectively and is effective for financial statements issued for annual periods beginning after December 15, 2016 and interim periods within those annual periods and early adoption is permitted. The Company elected to early adopt ASU 2015-17 retrospectively in the first quarter of 2016. The implementation of ASU 2015-17 did not have a material impact on the Company's results of operations. See Note F.

The Company is currently in the process of evaluating the impact of the new standard on its various revenue and ~~interim periods within that reporting period. In March 2016,~~cash flow streams, including the ~~FASB issued ASU 2016-08~~evaluation of the impact, if any, on changes to ~~clarify~~business processes, systems and controls to support recognition and disclosure under the ~~implementation guidance on principal versus agent consideration. In April 2016,~~new guidance. Tariff sales to customers are determined to be in the FASB issued ASU 2016-10 to clarify the implementation guidance on identifying performance obligations and licensing. In May 2016, the FASB issued ASU 2016-11, which rescinds certain SEC Staff Observer comments that are codified in FASB ASC Topic 605 (Revenue Recognition), effective upon adoptionscope of ~~Topic 606. In May 2016, the FASB issued ASU 2016-12, which makes narrow-scope amendments to ASU 2014-09, and provides practical expedients to simplify the transition to~~ the new standard and ~~to clarify certain aspects~~represent a significant portion of the ~~standard. Early adoption of ASU 2014-09 is permitted after December 15, 2016.~~Company’s total operating revenues. The Company ~~has~~currently expects that the timing or pattern of revenue recognition from tariff sales will not ~~selected a transition method~~significantly change. The Company's evaluation of other revenue streams is ongoing. The Company's initial assessments may change as it executes its implementation plan and new guidance is ~~currently assessing~~provided by the ~~future~~American Institute of Certified Public Accountants Power and Utilities Industry Task Force. The completion of these assessments could impact ~~of this ASU.~~ current accounting policies, revenue recognition and disclosures in the notes to the financial statements.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Liabilities to enhance the reporting model for financial instruments by addressing certain aspects of recognition, measurement, presentation, and disclosure. ASU 2016-01 generally requires entities to measure equity investments that do not result in consolidation and are not accounted for under the equity method at fair value and recognize any changes in fair value in net income. The guidance for classifying and measuring investments in debt securities and loans is not changed by this ASU, but requires entities to record changes in other comprehensive income. Financial assets and financial liabilities must be separately presented by measurement category on the balance sheet or in the accompanying notes to the financial statements. ASU 2016-01 clarifies the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity's other deferred tax assets. The standard includes a requirement that businesses must report changes in the fair value of their own liabilities in other comprehensive income instead of earnings, and this is the only provision of the update for which the FASB is permitting early adoption. The remaining provisions of this ASU become effective for ~~public companies for fiscal years~~reporting periods beginning after December 15, ~~2017, including interim periods within those fiscal years.~~2017. Upon adoption of the new standard, the Company expects to record the cumulative effects as of January 1, 2018 which will result in an adjustment to accumulated other comprehensive income (losses) and retained earnings for unrealized gains (losses) related to equity securities owned by the Company. The Company is ~~currently assessing~~continuing to assess the future impact of this ASU.



	8

~~Table of Contents~~

~~EL PASO ELECTRIC COMPANY~~

~~NOTES TO FINANCIAL STATEMENTS~~

~~(Unaudited)~~

in the statement of financial position, by the lessee, of a liability to make lease payments ~~(the lease~~(lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. How leases are recorded in regard to financial position represents a significant change from previous ~~GAAP.~~GAAP guidance. The lessee is permitted to make an accounting policy election to not recognize lease assets and lease liabilities for short-term leases. Implementation of the standard ~~for public companies~~ will be required for ~~annual~~ reporting periods beginning after December 15, ~~2018 and interim periods within that reporting period. Early adoption of ASU 2016-02 is permitted for all entities.~~2018. Adoption of the new lease accounting standard will require the Company to apply the new standard to the earliest period using a modified retrospective approach. The Company is currently ~~assessing~~in the ~~future~~process of evaluating the impact of ~~this ASU.~~

~~In March 2016,~~ the ~~FASB issued ASU 2016-09, Compensation – Stock Compensation (Topic 718) Improvements to Employee Share-Based Payment Accounting to simplify the accounting for share-based payment transactions,~~new standard, including the ~~income tax consequences, classification~~evaluation of ~~awards either as equity or liabilities,~~the impact, if any, on changes to business processes, systems and ~~classification~~controls to support recognition and disclosure under the new guidance, however, at this time is unable to determine the impact this standard will have on the financial statements ~~of cash flows. This ASU is effective for annual periods beginning after December 15, 2016,~~ and ~~interim periods within those annual periods. Early adoption is permitted. The Company is currently assessing the future impact of this ASU.~~related disclosures.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326). ASU 2016-13 ~~significantly~~ changes how companies measure and recognize credit impairment for many financial assets. The new current expected credit loss model will require companies to immediately recognize an estimate of credit losses expected to occur over the remaining life of the financial assets that are in the scope of the standard. The ASU also makes targeted amendments to the current impairment model for available-for-sale debt securities. ~~For public business entities, the~~The provisions ofin ASU 2016-13 ~~are effective~~will be required for ~~fiscal years and interim~~reporting periods ~~within that reporting period~~ beginning after December 15, 2019. ~~Early implementation is permitted as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years.~~ ASU 2016-13 will be applied in a modified-retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is implemented. The Company is currently assessing the future impact of ~~this ASU.~~ASU 2016-13.

~~Reclassification.~~ In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) Classification of Certain ~~amounts~~Cash Receipts and Cash Payments to reduce diversity in practice in how certain cash receipts and cash payments are classified in the ~~financial statements~~statement of cash flows. The provisions in ASU 2016-15 will be required for ~~2015 have been reclassified~~reporting periods beginning after December 15, 2017. ASU 2016-15 will be applied using a retrospective transition method to ~~conform~~each period presented. If it is impracticable to apply ASU 2016-15 retrospectively for some of the issues, the amendments for those issues may be applied prospectively as of the earliest date practicable. 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 March 2017, the FASB issued ASU 2017-07, Compensation-Retirement Benefits (Topic 715) Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. ASU 2017-07 amends Accounting Standards Codification 715, Compensation - Retirement Benefits, to require companies to present the service cost component of net benefit cost in the income statement line items where compensation cost is reported. Companies will present all other components of net benefit cost separately from the line item(s) that includes the service cost and outside of any subtotal of operating income. In addition, only the service cost component will be eligible for capitalization in assets. The amendments in ASU 2017-07 will be required for reporting periods beginning after December 15, 2017. The amendments in ASU 2017-07 should be applied retrospectively for the income statement presentation of the service cost component and the other components of net benefit costs and prospectively, on and after the effective date, for the capitalization of the service cost component. The Company is currently assessing the future impact of this ASU.

In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718), Scope of Modification Accounting, to provide guidance about when to account for a change to the ~~2016 presentation.~~terms or conditions of a share-based payment award as a modification. Under ASU 2017-09, modification accounting is required only if the fair value, the vesting conditions, or the classification of the award (as equity or liability) changes as a result of the change in terms or conditions. The amendments of ASU 2017-09 will be required for reporting periods beginning after December 15, 2017. ASU 2017-09 should be applied prospectively to an award modified on or after the adoption date. The Company ~~implemented~~is assessing the future impact of ASU ~~2015-03 and~~2017-09; however, it currently does not expect the impact of this ASU ~~2015-17 in the first quarter of 2016, retrospectively~~ to ~~all periods presented in the Company's financial statements. See Note J and Note F, respectively.~~be significant.



Supplemental Cash Flow Disclosures (in thousands)
		Six Months Ended
		June 30,
		2017			2016
Cash paid (received) for:
	Interest on long-term debt and borrowings under the revolving credit facility	$	35,304		$	35,252
	Income tax paid, net	2,251			2,703
Non-cash investing and financing activities:
	Changes in accrued plant additions	(9,105		)	(6,966		)
	Plant additions to be reimbursed by insurance	3,525			—
	Grants of restricted shares of common stock	1,171			1,236
	Issuance of performance shares	932			—



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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, 2016												Three Months Ended June 30, 2015													Three Months Ended June 30, 2017												Three Months Ended June 30, 2016
		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)				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	Balance at beginning of period	$	(30,256	)	$	28,394		$	(11,770	)	$	(13,632	)	$	(34,628	)	$	36,782		$	(12,032	)	$	(9,878	)	Balance at beginning of period	$	(24,457	)	$	32,872		$	(11,599	)	$	(3,184	)	$	(30,256	)	$	28,394		$	(11,770	)	$	(13,632	)
	Other comprehensive income (loss) before reclassifications	—			2,224			—			2,224			—			(1,191		)	—			(1,191		)	Other comprehensive income before reclassifications	—			3,558			—			3,558			—			2,224			—			2,224
	Amounts reclassified from accumulated other comprehensive income (loss)	(276		)	(1,693		)	77			(1,892		)	297			135			73			505			Amounts reclassified from accumulated other comprehensive income (loss)	(458		)	(4,134		)	85			(4,507		)	(276		)	(1,693		)	77			(1,892		)
Balance at end of period	Balance at end of period	$	(30,532	)	$	28,925		$	(11,693	)	$	(13,300	)	$	(34,331	)	$	35,726		$	(11,959	)	$	(10,564	)	Balance at end of period	$	(24,915	)	$	32,296		$	(11,514	)	$	(4,133	)	$	(30,532	)	$	28,925		$	(11,693	)	$	(13,300	)

		Six Months Ended June 30, 2016												Six Months Ended June 30, 2015													Six Months Ended June 30, 2017												Six Months Ended June 30, 2016
		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)				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	Balance at beginning of period	$	(29,869	)	$	27,765		$	(11,810	)	$	(13,914	)	$	(34,884	)	$	38,957		$	(12,074	)	$	(8,001	)	Balance at beginning of period	$	(23,928	)	$	28,463		$	(11,651	)	$	(7,116	)	$	(29,869	)	$	27,765		$	(11,810	)	$	(13,914	)
	Other comprehensive income (loss) before reclassifications	—			3,966			—			3,966			—			(369		)	—			(369		)	Other comprehensive income before reclassifications	—			9,723			—			9,723			—			3,966			—			3,966
	Amounts reclassified from accumulated other comprehensive income (loss)	(663		)	(2,806		)	117			(3,352		)	553			(2,862		)	115			(2,194		)	Amounts reclassified from accumulated other comprehensive income (loss)	(987		)	(5,890		)	137			(6,740		)	(663		)	(2,806		)	117			(3,352		)
Balance at end of period	Balance at end of period	$	(30,532	)	$	28,925		$	(11,693	)	$	(13,300	)	$	(34,331	)	$	35,726		$	(11,959	)	$	(10,564	)	Balance at end of period	$	(24,915	)	$	32,296		$	(11,514	)	$	(4,133	)	$	(30,532	)	$	28,925		$	(11,693	)	$	(13,300	)

		Twelve Months Ended June 30, 2016												Twelve Months Ended June 30, 2015													Twelve Months Ended June 30, 2017												Twelve Months Ended June 30, 2016
		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)				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	Balance at beginning of period	$	(34,331	)	$	35,726		$	(11,959	)	$	(10,564	)	$	(9,539	)	$	39,483		$	(12,214	)	$	17,730		Balance at beginning of period	$	(30,532	)	$	28,925		$	(11,693	)	$	(13,300	)	$	(34,331	)	$	35,726		$	(11,959	)	$	(10,564	)
	Other comprehensive income (loss) before reclassifications	3,777			2,080			—			5,857			(24,775		)	2,681			—			(22,094		)	Other comprehensive income before reclassifications	7,363			12,661			—			20,024			3,777			2,080			—			5,857
	Amounts reclassified from accumulated other comprehensive income (loss)	22			(8,881		)	266			(8,593		)	(17		)	(6,438		)	255			(6,200		)	Amounts reclassified from accumulated other comprehensive income (loss)	(1,746		)	(9,290		)	179			(10,857		)	22			(8,881		)	266			(8,593		)
Balance at end of period	Balance at end of period	$	(30,532	)	$	28,925		$	(11,693	)	$	(13,300	)	$	(34,331	)	$	35,726		$	(11,959	)	$	(10,564	)	Balance at end of period	$	(24,915	)	$	32,296		$	(11,514	)	$	(4,133	)	$	(30,532	)	$	28,925		$	(11,693	)	$	(13,300	)



	10

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

Amounts reclassified from ~~accumulated other comprehensive income (loss)~~Accumulated Other Comprehensive Income (Loss) for the three, six and twelve months ended June 30, ~~2016~~2017 and ~~2015~~2016 are as follows (in thousands):


Details about Accumulated Other Comprehensive Income (Loss) Components	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	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
		2016			2015			2016			2015			2016			2015					2017			2016			2017			2016			2017			2016

Amortization of pension and post-retirement benefit costs:	Amortization of pension and post-retirement benefit costs:																				Amortization of pension and post-retirement benefit costs:
	Prior service benefit	$	1,664		$	1,662		$	3,330		$	3,325		$	6,579		$	7,455		(a)	Prior service benefit	$	2,413		$	1,664		$	4,829		$	3,330		$	8,906		$	6,579		(a)
	Net loss	(1,222		)	(2,250		)	(2,445		)	(4,500		)	(6,567		)	(7,730		)	(a)	Net loss	(1,694		)	(1,222		)	(3,388		)	(2,445		)	(5,908		)	(6,567		)	(a)
		442			(588		)	885			(1,175		)	12			(275		)	(a)		719			442			1,441			885			2,998			12			(a)
	Income tax effect	(166		)	291			(222		)	622			(34		)	292			Income tax expense	Income tax effect	(261		)	(166		)	(454		)	(222		)	(1,252		)	(34		)	Income tax benefit
		276			(297		)	663			(553		)	(22		)	17			(a)		458			276			987			663			1,746			(22		)	Net income (loss)

Marketable securities:	Marketable securities:																				Marketable securities:
	Net realized gain (loss) on sale of securities	2,110			(182		)	3,498			3,563			11,049			7,946			Investment and interest income, net	Net realized gain on sale of securities	5,166			2,110			7,357			3,498			11,499			11,049			Investment and interest income, net
		2,110			(182		)	3,498			3,563			11,049			7,946			Income before income taxes		5,166			2,110			7,357			3,498			11,499			11,049			Income before income taxes
	Income tax effect	(417		)	47			(692		)	(701		)	(2,168		)	(1,508		)	Income tax expense	Income tax effect	(1,032		)	(417		)	(1,467		)	(692		)	(2,209		)	(2,168		)	Income tax benefit
		1,693			(135		)	2,806			2,862			8,881			6,438			Net income		4,134			1,693			5,890			2,806			9,290			8,881			Net income

Loss on cash flow hedge:	Loss on cash flow hedge:																				Loss on cash flow hedge:
	Amortization of loss	(123		)	(116		)	(245		)	(230		)	(482		)	(452		)	Interest on long-term debt and revolving credit facility	Amortization of loss	(132		)	(123		)	(262		)	(245		)	(515		)	(482		)	Interest on long-term debt and revolving credit facility
		(123		)	(116		)	(245		)	(230		)	(482		)	(452		)	Income before income taxes		(132		)	(123		)	(262		)	(245		)	(515		)	(482		)	Loss before income taxes
	Income tax effect	46			43			128			115			216			197			Income tax expense	Income tax effect	47			46			125			128			336			216			Income tax expense
		(77		)	(73		)	(117		)	(115		)	(266		)	(255		)	Net income		(85		)	(77		)	(137		)	(117		)	(179		)	(266		)	Net loss

	Total reclassifications	$	1,892		$	(505	)	$	3,352		$	2,194		$	8,593		$	6,200			Total reclassifications	$	4,507		$	1,892		$	6,740		$	3,352		$	10,857		$	8,593

(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.

2015 Texas Retail Rate Case Filing. On August 10, 2015, the Company filed with the City of El Paso, other municipalities incorporated in its Texas service territory, and the PUCT in Docket No. 44941, a request for an annual increase in non-fuel base revenues ~~of approximately $71.5 million.~~ ("2015 Texas Retail Rate Case").

On January 15, 2016, the Company filed its rebuttal testimony modifying the requested increase to $63.3 million. The Company invoked its statutory right to have its new rates relate back for consumption on and after January 12, 2016, which is the 155th day after the filing. The difference in rates that would have been billed will be surcharged or refunded to customers after the PUCT's final order in Docket No. 44941. The PUCT has the authority to require the Company to surcharge or refund such difference over a period not to exceed 18 months. On JanuaryJuly 21, 2016, the Company, the City of El Paso, the PUCT Staff, the Office of Public Utility Counsel and Texas Industrial Energy Consumers filed a joint motion to abate the procedural schedule to facilitate settlement talks. This motion was granted.

~~On March 29, 2016, the Company and other settling~~ parties to PUCT Docket No. 44941 filed ~~a Non-Unanimous Stipulation and Agreement and motion to approve interim rates (the "Non-Unanimous Settlement") with~~ the PUCT. Four parties to the rate case opposed the Non-Unanimous Settlement but not the interim rates. Interim rates reflecting an annual non-fuel base rate increase of $37 million were approved by the Administrative Law Judges ("ALJs") effective April 1, 2016 subject to refund or surcharge. Subsequent to filing the Non-Unanimous Settlement, the rate case was subject to numerous procedural matters, including a May 19, 2016 ruling by the PUCT that the Company’s initial notice did not adequately contemplate the treatment of residential customers with solar generation contained in the Non-Unanimous Settlement.

~~Settlement discussions continued, and on July 21, 2016, the Company filed a~~ Joint Motion to Implement Uncontested Amended and Restated Stipulation and Agreement ~~with the PUCT,~~ which was unopposed by the parties to("Unopposed Settlement"). On August 25, 2016, the ~~rate case~~PUCT approved the Unopposed Settlement and issued its final order in Docket No. 44941 ~~(the "Unopposed Settlement"~~("PUCT Final Order")., as proposed. The ~~terms of the Unopposed Settlement include:~~PUCT Final Order provided for: (i) an annual non-fuel base rate increase, ~~of $37 million,~~ lower annual depreciation expense, ~~of approximately $8.5 million,~~ a revised return on equity ~~of 9.7%~~ for ~~AFUDC~~allowance for funds used during construction ("AFUDC") purposes, and ~~including~~the inclusion of substantially all new plant in service in rate base; (ii) an additional annual non-fuel base rate increase of $3.7 million related to Four Corners Generating Station ~~costs;~~("Four Corners") costs, which will be collected through a surcharge terminating on July 11, 2017; (iii) removing the separate rate treatment for residential customers with solar ~~generation; and~~systems that the Company had proposed in its August 10, 2015 filing; (iv) allowing the Company to recover ~~most~~$3.1 million in rate case expenses through a separate surcharge and (v) allowing the Company to recover revenues associated with the relate back of rates to consumption on and after January 12, 2016 through March 31, 2016 through a separate surcharge.

Interim rates associated with the annual non-fuel base rate increase, became effective on April 1, 2016. The additional surcharges associated with the incremental Four Corners costs, rate case expenses and the relate back of rates to consumption on and after January 12, 2016 through March 31, 2016 were implemented on October 1, 2016.

For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2015 Texas Retail Rate Case until it received the PUCT Final Order on August 25, 2016. Accordingly, it reported in the third quarter of 2016 the cumulative effect of the PUCT Final Order which related back to January 12, 2016.

2017 Texas Retail Rate Case Filing.On February 13, 2017, the Company filed with the City of El Paso, other municipalities incorporated in the Company's Texas service territory and the PUCT in Docket No. 46831, a request for an increase in non-fuel base revenues of approximately $42.5 million. On May 16, 2017, the Company filed a motion to sever rate case expense issues from the main rate case. The request was approved by the Administrative Law Judges, initiating Docket No. 47228, on June 5, 2017.

On July 21, 2017, the Company filed its rebuttal testimony modifying the requested increase to $39.2 million. The decrease from the original request related primarily to the transfer of the recovery of $3.0 million of the rate case expenses up to a ~~date certain.~~separate proceeding as noted above. Hearings on the merits of the rate case are scheduled to begin on August 21, 2017. The ~~Unopposed Settlement~~Company requested, pursuant to its statutory right, to have its new rates relate back for consumption on and after July 18, 2017, which is ~~subject to approval by~~ the ~~PUCT.~~155th day after the filing of the rate case. The ~~settlement documents were filed with ALJs assigned to oversee the Company's Texas Rate case, who~~difference in rates that would have ~~returned the settled case to the PUCT for approval. It is anticipated that the Unopposed Settlement~~been billed will be ~~considered by~~surcharged or refunded to customers after the PUCT's final order in Docket No. 46831. The PUCT ~~at its meeting scheduled for August~~has the authority to require the Company to surcharge or refund such difference over a period not to exceed 18 ~~2016.~~months. The ~~costs of serving residential customers with solar generation will be addressed in a future proceeding.~~

~~Given~~Company cannot predict the ~~uncertainties regarding~~outcome or the ~~ultimate resolution~~timing of this rate case at this time.

Energy Efficiency Cost Recovery Factor. On May 1, 2017, the Company ~~did not recognize~~filed its annual application, which was assigned PUCT Docket No. 47125, to establish its energy efficiency cost recovery factor for 2018. In addition to projected energy efficiency costs for 2018 and a true-up to prior year actual costs, the ~~impacts~~Company requested approval of ~~the Unopposed Settlement in the Statements of Operations~~a $1.0 million bonus for the ~~second quarter of 2016. The additional revenues resulting from the implementation of the interim rates~~2016 energy efficiency program results in ~~the amount of $10.8 million were deferred and included in other current liabilities~~accordance with PUCT rules. A hearing on the ~~Company's Balance Sheet~~merits of this case is scheduled to begin on August 15, 2017. The Company cannot predict the outcome of this matter at ~~June 30, 2016. At~~ this ~~time, the Company believes the revenue and other impacts of the Unopposed~~time.



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Settlement for financial reporting purposes will be recognized during the second half of 2016. Regardless of the ultimate timing and amounts, new rates will relate back to consumption on and after January 12, 2016.

~~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 a 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 stipulation and settlement agreement was filed September 24, 2015 and the PUCT approved the settlement on November 5, 2015. The settlement approved by the PUCT includes a performance bonus of $1.0 million. The Company recorded the performance bonus as operating revenue in the fourth quarter of 2015.

~~On April 29, 2016,~~ the Company made its annual filing to establish its energy efficiency cost recovery factor for 2017. In addition to projected energy efficiency costs for 2017 and true-up to prior year actual costs, the Company requested approval of a $668 thousand bonus for the 2015 energy efficiency program results in accordance with PUCT rules. This case was assigned PUCT Docket No. 45855. The Company expects the Commission will make a final decision in the proceeding before the end of 2016.

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, 2015,~~November 30, 2016, the Company filed a request, which was assigned PUCT Docket No. ~~44633,~~46610, to ~~reduce~~increase its fixed fuel factor by approximately ~~24%~~28.8% to reflect ~~reduced~~increased fuel expenses primarily related to ~~a reduction~~an increase in the price of natural gas used to generate power. The ~~over-recovered balance was below the PUCT's materiality threshold. The reduction~~increase in the fixed fuel factor was effective on an interim basis ~~May~~January 1, ~~2015~~2017 and approved by the PUCT on ~~May 20, 2015.~~January 10, 2017. As of June 30, ~~2016,~~2017, the Company had ~~over-recovered~~under-recovered fuel costs in the amount of ~~$1.0~~$8.5 million for the Texas jurisdiction.

Fuel Reconciliation Proceeding. ~~Pursuant to the 2012 Texas retail rate settlement discussed above, on~~On September 27, ~~2013,~~2016, the Company filed an application with the PUCT, designated as PUCT Docket No. ~~41852,~~46308, to reconcile ~~$545.3~~$436.6 million of Texas fuel and purchased power expenses incurred during the ~~45-month~~ period ~~from July~~of April 1, ~~2009~~2013 through March 31, ~~2013. A settlement was reached and a final order was issued by~~2016. On June 29, 2017, the PUCT ~~on July 11, 2014 with no significant adjustments.~~approved a settlement in this proceeding. The ~~PUCT's final order completes~~settlement provides for the ~~regulatory review and~~ reconciliation of ~~the Company's~~ fuel ~~expenses for the period~~and purchased power costs incurred from April 1, 2013 through March 31, ~~2013.~~2016. Additionally, the settlement modifies and tightens the Palo Verde performance rewards measurement bands beginning with the 2018 performance period. The ~~Company is required~~financial results for the three months ended June 30, 2017 include a $5.0 million, pre-tax increase to ~~file an application by~~income reflecting the ~~end~~settlement of ~~September 2016 for~~the Texas fuel reconciliation proceeding. This amount includes Palo Verde performance rewards associated with the 2013 to 2015 performance periods net of disallowed fuel and purchased power costs as approved in the ~~Company's~~settlement. As of June 30, 2017, Texas jurisdictional fuel ~~expenses for the period through March 31, 2016.~~

~~Montana Power Station ("MPS") Approvals. The Company has received~~and purchased power costs subject to a ~~Certificate of Convenience and Necessity ("CCN") from the PUCT to construct four natural gas fired generating units at MPS in El Paso County, Texas. The Company also obtained air permits from the~~future Texas Commission on Environmental Quality (the "TCEQ") and the U.S. Environmental Protection Agency (the "EPA"). MPS Units 1 and 2 and associated transmission lines and common facilities were completed and placed into service in March 2015. MPS Unit 3 was completed and placed into service on May 3, 2016.fuel reconciliation are approximately $181.4 million.

Community Solar. On June 8, 2015, the Company filed a petition with the PUCT to initiate a community solar program ~~to include~~that includes the construction and ownership of a 3 MW solar photovoltaic system located at ~~MPS.~~Montana Power Station. Participation will be on a voluntary basis, and customers will contract for a set capacity (kW) amount and receive all energy produced. This case was assigned PUCT Docket No. 44800. The Company filed a settlement agreement among all parties on July 1, 2016 ~~which would approve~~approving the program, and the ~~Company expects an order from the~~ PUCT ~~on or about August 18, 2016 approving~~approved the settlement ~~agreement.~~agreement and program on September 1, 2016. On April 19, 2017, the Company announced that the entire 3 MW program was fully subscribed by approximately 1,500 Texas customers. The Community Solar facility began commercial operation on May 31, 2017.



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~~(Unaudited)~~

Four Corners Generating ~~Station ("Four Corners").~~Station. On February 17, 2015, the Company and Arizona Public Service Company ("APS") entered into an asset purchase agreement ~~(the "Purchase~~("Purchase and Sale Agreement") providing for the ~~purchase by APS~~sale of the Company's ~~interests~~interest in Four ~~Corners.~~Corners to APS. The sale of the Company's interest in Four Corners ~~transaction~~ closed on July 6, 2016. ~~See Note D for further details on the sale of Four Corners.~~

On June 10, 2015, the Company filed an application in Texas requesting reasonableness and public interest findings and certain rate and accounting findings related to the Purchase and Sale Agreement. This case was assigned PUCT Docket No. 44805. Subsequent to the filing of the application, the case has been subject to numerous procedural matters, including a March 23, 2016 order in which the PUCT determined not to dismiss the reasonableness and public interest issues in this docket but to consider the requested rate and accounting findings, including coal mine reclamation costs, in a rate case proceeding. On September 1, 2016, a motion by parties in the proceeding to suspend the procedural schedule in order to pursue settlement was approved. On March 3, 2017, the Company filed a Joint Motion to Implement Stipulation and Agreement ("Stipulation and Agreement"), and PUCT Staff filed its recommendation that the Company’s disposition of its interest in Four Corners was reasonable and consistent with the public interest. Additionally, the signatories of the Stipulation and Agreement agreed to support the recovery of the Company's next rate case, which is expected to be filed in early 2017. The procedural schedule related to the public interest issues calls for a hearing to be held on October 6-7, 2016. At June 30, 2016, the regulatory asset associated with mine reclamation costs for our Texas jurisdiction approximated $7.7 million.

~~The Company currently continues to recover its mine reclamation~~Four Corners decommissioning costs in the ongoing Texas ~~under previous orders~~rate case. A final order approving the Stipulation and ~~decisions of~~Agreement was adopted by the PUCT. If any future determinations made by our regulators result in changes to how existing regulatory assets or previously incurred costs for Four Corners are recovered in rates, any such changes would be recognized only when it becomes probable future cash flows will change as a result of such regulatory actions.PUCT on March 30, 2017.

Other Required Approvals. The Company has obtained other required approvals for tariffs and approvals as required by the Public Utility Regulatory Act ~~(the "PURA"~~("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 a request with the NMPRC, in 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 requested an annual reduction of $15.4 million, or 21.5%, for fuel and purchased power costs. Subsequently, the Company reduced its requested increase in non-fuel base rates to approximately $6.4 million.rates. On June 8, 2016, the NMPRC issued its final order ~~approving~~in Case No. 15-00127-UT ("NMPRC Final Order"), which approved an annual increase in non-fuel base rates of approximately ~~$1.1~~$0.6 million, an increase of approximately $0.5 million in other service fees and a decrease in the Company's allowed return on equity to 9.48%. The ~~final order concludes~~NMPRC Final Order concluded that all of the Company's new plant ~~additions are~~ in service was reasonable and ~~used and useful, and that the costs were prudently incurred,~~necessary and therefore would be recoverable ~~and included~~ in ~~rate base.~~rates. The Company's rates were approved by the NMPRC effective July 1, 2016 and implemented at such time.

Future New Mexico Rate Case Filing. NMPRC Case No. 15-00109-UT required the Company to make a rate filing in New Mexico in the second quarter of 2017 using a historical test year ended December 31, 2016. On March 24, 2017, the Company, NMPRC Utility Division Staff and the New Mexico Attorney General filed a Joint Motion to Modify Filing Date Stated in Final



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Order requesting that the rate filing date be changed to no later than July 31, 2019, using the appropriate historical test year period. The joint request was approved by the NMPRC on April 12, 2017.

Fuel and Purchased Power Costs. ~~On January 8, 2014, the NMPRC approved the continuation of the Fuel and Purchased Power Cost Adjustment Clause (the "FPPCAC") without modification in NMPRC Case No. 13-00380-UT.~~ Historically, fuel and purchased power costs were recovered through base rates and a ~~FPPCAC~~Fuel and Purchased Power Cost Adjustment Clause ("FPPCAC") that accounts for changes in the costs of fuel relative to the amount included in base rates. Effective July 1, 2016, with the implementation of the final order ofin Case No. 15-00127-UT, fuel and ~~purchase~~purchased power costs ~~will~~are no longer be recovered through base rates but ~~will be completely~~are recovered through the FPPCAC. ~~Fuel~~The Company's request to reconcile its fuel and purchased power costs ~~are reconciled to actual costs on a monthly basis and recovered or refunded to customers~~for the ~~second succeeding month. The Company recovers costs related to Palo Verde Unit 3 capacity and energy in New Mexico~~period January 1, 2013 through ~~the FPPCAC as purchased power using a proxy market price~~December 31, 2014 was approved in Case No. ~~13-00380-UT.~~15-00127-UT. New Mexico jurisdictional costs subject to prudence review are costs from January 1, 2015 through June 30, 2017 that total approximately $144.1 million. At June 30, ~~2016,~~2017, the Company had a net fuel over-recovery balance of ~~$1.1~~approximately $0.3 million in New Mexico.

~~Montana Power Station Approvals.~~ The Company has received a CCN from the NMPRC to construct four units at MPS and the associated transmission lines. The Company also obtained all necessary air permits from the TCEQ and the 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 MPS to Caliente and MPS In & Out transmission lines were completed and placed into service in March 2015.~~ ~~MPS Unit 3 was completed and placed into service on May 3, 2016.~~

~~Four Corners.~~ On February 17, 2015, the Company and APS entered into the Purchase and Sale Agreement providing for the purchase by APS of the Company's interests in Four Corners. On April 27, 2015, the Company filed an application in NMPRC Case No. 15-00109-UT requesting all necessary regulatory approvals to sell its ownership interest in Four Corners. On February



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2, 2016, the Company filed a joint stipulation with the NMPRC reflecting a settlement agreement among the NMPRC's Utility Division Staff, the Company and the New Mexico Attorney General proposing approval of abandonment and sale of its seven percent minority ownership interest in Four Corners Units 4 and 5 and common facilities to APS. An addendum to the joint stipulation was subsequently filed and the joint stipulation was unopposed. A hearing in the case was held on February 16, 2016, and the Hearing Examiner issued a Certification of Stipulation on April 22, 2016 recommending approval of the joint stipulation without modification. On June 15, 2016, the NMPRC issued its final order approving the stipulation. See Note D for further details on the sale of Four Corners.

5 MW Holloman Air Force Base ("HAFB") Facility ~~CCN~~Certificate of Convenience and Necessity ("CCN"). On ~~June 15,~~October 7, 2015, ~~the Company filed a petition with~~in NMPRC Case No. 15-00185-UT, the NMPRC ~~requesting~~issued a final order approving a CCN ~~authorization to construct~~for a 5 MW ~~solar-powered~~solar power generation facility ~~to be~~ located aton HAFB in the Company's service territory in New Mexico. The new facility will be a dedicated Company-owned resource serving HAFB. This case was assigned NMPRC Case No. 15-00185-UT. On October 7, 2015, the NMPRC issued a final order accepting the Hearing Examiner’s Recommended Decision to approve the CCN, as modified. The Company and HAFB ~~are in discussions for~~negotiated a retail contract, which includes power sales agreement for the facility, to replace the existing load retention ~~agreement.~~

~~Issuance of Long-Term Debt and Guarantee of Debt.~~ Onagreement which was approved by final order issued October ~~7, 2015, the Company received approval~~5, 2016 in NMPRC Case No. ~~15-00280-UT~~16-00224-UT. Construction of the solar generation facility is expected to ~~issue up to $310 million~~be completed in ~~new long-term debt; and to guarantee~~ the ~~issuance~~first half of ~~up to $65 million~~2018.

New Mexico Efficient Use of new debt by Rio Grande Resources Trust ("RGRT") to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. This approval supersedes prior approvals. Under this authorization, on March 24,Energy Recovery Factor. On July 1, 2016, the Company filed its annual application requesting approval of its 2017 Energy Efficiency and Load Management Plan and to establish energy efficiency cost recovery factors for 2017. In addition to projected energy efficiency costs for 2017, the Company requested approval of a $0.4 million incentive for 2017 energy efficiency programs in accordance with NMPRC rules. This case was assigned Case No. 16-00185-UT. On February 22, 2017, the NMPRC issued ~~$150~~a Final Order approving the Company’s 2017 Energy Efficiency and Load Management Plan and authorizing recovery in 2017 of a base incentive of $0.4 million. The Company’s energy efficiency cost recovery factors were approved and effective in customer bills beginning on March 1, 2017.

On July 1, 2016, the Company filed its 2015 Annual Report for Energy Efficiency Programs, which included an incentive for verified 2015 program performance of $0.3 million, which was approved in ~~aggregate principal amount~~Case No. 13-00176-UT. The Company recorded the $0.3 million approved incentive in operating revenues in the first quarter of ~~5.00% Senior Notes due December 1, 2044. The net proceeds from~~2017. In addition, on June 30, 2017, the ~~issuance~~Company filed its 2016 Annual Report for Energy Efficiency Programs, which included an incentive for verified 2016 program performance of ~~these senior notes, after deducting the underwriters' commission, were $158.1 million. These proceeds include accrued interest of $2.4~~$0.4 million ~~and a $7.1 million premium before expenses. These senior notes constitute an additional issuance of the Company's 5.00% Senior Notes due 2044, of~~ which ~~$150 million~~ was ~~previously issued on December 1, 2014, for a total principal amount outstanding of $300 million.~~approved in Case No. 13-00176-UT.

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

Federal Regulatory Matters

~~Four Corners.~~ 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. On December 22, 2015, FERC issued an order approving the proposed transaction. The Four Corners transaction closed on July 6, 2016. See Note D for further details on the sale of Four Corners.

~~Public Service Company of New Mexico (~~"~~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. On March 25, 2015, the Chief Judge issued an order granting PNM's motion to implement the settled rates. On March 17, 2016, FERC issued an order approving the settlement.

~~Revolving Credit Facility; Issuance of Long-Term Debt and Guarantee of Debt.~~ On October 19, 2015, the FERC issued an order in Docket No. ES15-66-000 approving the Company’s filing to issue short-term debt under its existing revolving credit facility ("RCF") up to $400 million outstanding at any time, to issue up to $310 million in long-term debt, and to guarantee the issuance of up to $65 million of new long-term debt by RGRT to finance future nuclear fuel purchases. The authorization is effective from November 15, 2015 through November 15, 2017. This approval supersedes prior approvals. Under this authorization, on March 24, 2016, the Company issued $150 million in aggregate principal amount of 5.00% Senior Notes due December 1, 2044. The net proceeds from the issuance of these senior notes, after deducting the underwriters' commission, were $158.1 million. These proceeds include accrued interest of $2.4 million and a $7.1 million premium before expenses. These senior notes constitute an additional issuance of the Company's 5.00% Senior Notes due 2044, of which $150 million was previously issued on December 1, 2014, for a total principal amount outstanding of $300 million.

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

D. Palo Verde

Decommissioning. Pursuant to the Arizona Nuclear Power Project ("ANPP") Participation Agreement and federal law, the Company funds its share of the estimated costs to decommission Palo Verde Nuclear Generating Station ("Palo Verde") Units 1, 2 and 3, including the Common Facilities, through the term of their respective operating licenses and is required to maintain a minimum accumulation and funding level in its decommissioning account at the end of each annual reporting period during the life of the plant. The Company has established external trusts with an independent trustee, which enables the Company to record a current deduction for federal income tax purposes for most of the amounts funded. At June 30, 2017, the Company’s decommissioning trust fund had a balance of $271.3 million, which is above its minimum funding level. The Company monitors the status of its decommissioning funds and adjusts its deposits, if necessary.

Decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers retained by APS. In April 2017, the Palo Verde Participants approved the 2016 Palo Verde decommissioning study (“2016 Study”). The 2016 Study estimated that the Company must fund approximately $432.8 million (stated in 2016 dollars) to cover its share of decommissioning costs which was an increase in decommissioning costs of $52.1 million (stated in 2016 dollars) from the 2013 Palo Verde decommissioning study. The effect of this change increased the ARO by $3.5 million, which was recorded during the



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NOTES TO FINANCIAL STATEMENTS

(Unaudited)

~~D. Palo Verde~~six months ended June 30, 2017, and ~~Four Corners~~will increase annual expenses starting in April 2017. Although the 2016 Study was based on the latest available information, there can be no assurance that decommissioning cost estimates will not increase in the future or that regulatory requirements will not change. In addition, until a new low-level radioactive waste repository opens and operates for a number of years, estimates of the cost to dispose of low-level radioactive waste are subject to uncertainty. As provided in the ANPP Participation Agreement, the participants are required to conduct a new decommissioning study every three years. While the Company attempts to seek amounts in rates to meet its decommissioning obligations, it is not able to conclude given the evidence available to it now that it is probable these costs will continue to be collected over the period until decommissioning begins in 2044. The Company is ultimately responsible for these costs and its future actions combined with future decisions from regulators will determine how successful the Company is in this effort.

Spent Nuclear Fuel and Waste Disposal. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 ~~(the "NWPA"~~("NWPA"), the U.S. Department of Energy ~~(the "DOE"~~("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~~("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 Palo Verde Participants, 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 Participants 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 Palo Verde Participants, submitted to the government ~~an additional~~a 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~~award, of ~~the award~~which $5.8 million was credited to customers through the applicable fuel adjustment clauses in March 2015. ~~Thereafter~~After June 2015, APS will file annual claims for the period July 1 of the then-previous year to June 30 of the then-current year.

On November 2, 2015, APS filed a $12.0 million claim for the period July 1, 2014 through June 30, 2015. In February 2016, the DOE notified APS of the approval of the claim. ~~Funds related to this claim were~~In March 2016, the Company received ~~in the first quarter of 2016. The Company's~~its share of this claim isof approximately $1.9 ~~million. The majority~~million, of ~~the award~~which $1.6 million was credited to customers through the applicable fuel adjustment ~~clauses in March~~clauses.

On October 31, 2016, APS filed an $11.3 million claim for the period July 1, 2015 through June 30, 2016. ~~APS's next claim pursuant to the terms of the August 18, 2014 settlement agreement will be submitted to~~On February 1, 2017, the DOE ~~in the fourth quarter of 2016, and payment is expected in the second quarter of 2017.~~

~~Four Corners.~~ ~~On February 17, 2015, the Company and APS entered into the Purchase and Sale Agreement providing for the purchase by~~notified APS of the Company’s interests in Four Corners. Four Corners continued to provide energy to serve the Company's native load up to the closing date, and is classified as held for use in the Company's June 30, 2016 financial statements. The net book valueapproval of the utility plant related to Four Corners was $31.9 million at June 30, 2016. Included in the Company's Balance Sheet at June 30, 2016 are obligations of $7.0 million and $19.5 million for plant decommissioning and mine reclamation costs, respectively, which were assumed by APS as part of the sale.

The Four Corners transaction closed on July 6, 2016. The sales price was $32.0 million based on the net book value as defined in the Purchase and Sale Agreement. The sales price was adjusted downward by $7.0 million and $19.5 million, respectively, to reflect APS's assumption of the Company's obligation to pay for future plant decommissioning and mine reclamation expenses. The sales price was also adjusted downward by approximately $1.3 million for closing adjustments and other assets and liabilities assumed by APS. At the closing,claim. On March 10, 2017, the Company received approximately ~~$4.2~~$1.8 million, ~~in cash, subject to post-closing adjustments. No significant gain or loss was recorded upon the closing~~representing its share of the ~~sale. APS will assume responsibility for all capital expenditures made after July 6, 2016. In addition, APS will indemnify~~award, of which $1.4 million was credited to customers through the ~~Company against liabilities~~applicable fuel adjustment clauses.

Palo Verde Operations and ~~costs related to the future operation of Four Corners. See Note C for a discussion of regulatory filings~~Maintenance Expense. Included in other operations and maintenance expenses are expenses associated with ~~Four Corners.~~Palo Verde as follows (in thousands):



	2017		2016
Three months ended June 30,	$	25,931	$	24,048
Six months ended June 30,	47,539		46,391
Twelve months ended June 30,	98,062		98,343



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E. Common Stock

Dividends. The Company paid $~~12.5~~13.6 million and $~~11.9~~12.5 million in quarterly cash dividends during the three months ended June 30, 2017 and 2016, respectively. The Company paid a total of $26.2 million and ~~2015,~~$51.3 million in quarterly cash dividends during the six and twelve months ended June 30, 2017, respectively. The Company paid a total of $24.5 million and $48.4 million in quarterly cash dividends during the six and twelve months ended June 30, 2016, 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.~~ On July ~~21, 2016,~~27, 2017, the Board of

Directors declared a quarterly cash dividend of ~~$0.31~~$0.335 per share payable on September ~~30, 2016~~29, 2017 to shareholders of record as of the close of business on September ~~14, 2016.~~15, 2017.


Basic and Diluted Earnings Per Share. The basic and diluted earnings per share are presented below (in thousands except for share data):	Basic and Diluted Earnings Per Share. The basic and diluted earnings per share are presented below (in thousands except for share data):						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,						Three Months Ended June 30,
	2016			2015			2017			2016
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	40,345,150			40,269,885			40,409,030			40,345,150
Dilutive effect of unvested performance awards	54,341			32,809			116,555			54,341
Diluted number of common shares outstanding	40,399,491			40,302,694			40,525,585			40,399,491
Basic net income per common share:
Net income	$	22,284		$	21,072		$	36,066		$	22,284
Income allocated to participating restricted stock	(65		)	(65		)	(142		)	(65		)
Net income available to common shareholders	$	22,219		$	21,007		$	35,924		$	22,219
Diluted net income per common share:
Net income	$	22,284		$	21,072		$	36,066		$	22,284
Income reallocated to participating restricted stock	(65		)	(65		)	(142		)	(65		)
Net income available to common shareholders	$	22,219		$	21,007		$	35,924		$	22,219
Basic net income per common share:
Distributed earnings	$	0.310		$	0.295		$	0.335		$	0.31
Undistributed earnings	0.240			0.225			0.555			0.24
Basic net income per common share	$	0.550		$	0.520		$	0.890		$	0.55
Diluted net income per common share:
Distributed earnings	$	0.310		$	0.295		$	0.335		$	0.31
Undistributed earnings	0.240			0.225			0.555			0.24
Diluted net income per common share	$	0.550		$	0.520		$	0.890		$	0.55



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(Unaudited)



	Six Months Ended June 30,
	2017			2016
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	40,398,192			40,335,236
Dilutive effect of unvested performance awards	101,152			45,404
Diluted number of common shares outstanding	40,499,344			40,380,640
Basic net income per common share:
Net income	$	32,077		$	16,476
Income allocated to participating restricted stock	(119		)	(66		)
Net income available to common shareholders	$	31,958		$	16,410
Diluted net income per common share:
Net income	$	32,077		$	16,476
Income reallocated to participating restricted stock	(119		)	(66		)
Net income available to common shareholders	$	31,958		$	16,410
Basic net income per common share:
Distributed earnings	$	0.645		$	0.605
Undistributed earnings	0.145			(0.195		)
Basic net income per common share	$	0.790		$	0.410
Diluted net income per common share:
Distributed earnings	$	0.645		$	0.605
Undistributed earnings	0.145			(0.195		)
Diluted net income per common share	$	0.790		$	0.410



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(Unaudited)


	Six Months Ended June 30,						Twelve Months Ended June 30,
	2016			2015			2017			2016
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	40,335,236			40,256,615			40,381,776			40,314,032
Dilutive effect of unvested performance awards	45,404			28,142			85,219			42,207
Diluted number of common shares outstanding	40,380,640			40,284,757			40,466,995			40,356,239
Basic net income per common share:
Net income	$	16,476		$	24,530		$	112,369		$	73,864
Income allocated to participating restricted stock	(66		)	(71		)	(423		)	(210		)
Net income available to common shareholders	$	16,410		$	24,459		$	111,946		$	73,654
Diluted net income per common share:
Net income	$	16,476		$	24,530		$	112,369		$	73,864
Income reallocated to participating restricted stock	(66		)	(71		)	(423		)	(210		)
Net income available to common shareholders	$	16,410		$	24,459		$	111,946		$	73,654
Basic net income per common share:
Distributed earnings	$	0.605		$	0.575		$	1.265		$	1.195
Undistributed earnings	(0.195		)	0.035			1.505			0.635
Basic net income per common share	$	0.410		$	0.610		$	2.770		$	1.830
Diluted net income per common share:
Distributed earnings	$	0.605		$	0.575		$	1.265		$	1.195
Undistributed earnings	(0.195		)	0.035			1.505			0.635
Diluted net income per common share	$	0.410		$	0.610		$	2.770		$	1.830



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~~(Unaudited)~~

Twelve Months Ended June 30,
2016 2015
Weighted average number of common shares outstanding:
Basic number of common shares outstanding 40,314,032
40,236,466
Dilutive effect of unvested performance awards 42,207
26,838
Diluted number of common shares outstanding 40,356,239
40,263,304
Basic net income per common share:
Net income $ 73,864
$ 81,247
Income allocated to participating restricted stock (210 ) (253 )
Net income available to common shareholders $ 73,654
$ 80,994
Diluted net income per common share:
Net income $ 73,864
$ 81,247
Income reallocated to participating restricted stock (210 ) (253 )
Net income available to common shareholders $ 73,654
$ 80,994
Basic net income per common share:
Distributed earnings $ 1.195
$ 1.135
Undistributed earnings 0.635
0.875
Basic net income per common share $ 1.830
$ 2.010
Diluted net income per common share:
Distributed earnings $ 1.195
$ 1.135
Undistributed earnings 0.635
0.875
Diluted net income per common share $ 1.830
$ 2.010


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:
The number 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:							The number 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		Three Months Ended		Six months ended		Twelve Months Ended
	June 30,		June 30,		June 30,		June 30,		June 30,		June 30,
	2016	2015	2016	2015	2016	2015	2017	2016	2017	2016	2017	2016
Restricted stock awards	42,759	48,669	51,111	58,432	52,714	59,380	58,792	42,759	68,409	51,111	62,352	52,714
Performance shares (a)	62,995	59,898	62,995	59,898	56,089	48,136	—	62,995	—	62,995	6,906	56,089


(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, Arizona and New Mexico jurisdictions for years prior to ~~2011.~~2012. The Company is currently under audit in Texas for tax years 2007 through 2011. In June 2016, the Arizona Department of Revenue discontinued their audits for tax years 2009 through 2012. The discontinuance of the audits did not have a material impact on the Company's results of operations or financial position.2010.

For the three months ended June 30, ~~2016~~2017 and ~~2015,~~2016, the Company’s effective tax rate was ~~33.9%~~35.4% and ~~31.1%~~33.9%, respectively. For the six months ended June 30, ~~2016~~2017 and ~~2015,~~2016, the Company's effective tax rate was ~~33.5%~~35.3% and ~~30.0%~~33.5%, respectively. For the twelve months ended June 30, ~~2016~~2017 and ~~2015,~~2016, the Company's effective tax rate was ~~30.7%~~36.0% and ~~30.3%~~30.7%, respectively. The Company's effective tax rate for all periods differs from the federal statutory tax rate of 35.0% primarily due to capital gains in the decommissioning trusts which are taxed at the federal rate of 20.0%, the allowance for equity funds used during construction ("AEFUDC"), state taxes and ~~state taxes.~~the issue discussed in the following paragraph.

In ~~November 2015,~~ the ~~FASB issued new guidance (ASU 2015-17, Balance Sheet Classification~~third quarter of ~~Deferred Taxes)~~2016, the Company changed its accounting for state income taxes from the flow-through method to ~~simplify~~ the ~~presentation of~~normalization method in accordance with the PUCT's and NMPRC's most recent final orders. Under the flow-through method, the Company previously recorded deferred state income ~~taxes. ASU 2015-17 requires that deferred tax~~taxes and regulatory liabilities and assets offsetting such deferred state income taxes at the expected cash flow to be ~~classified as noncurrent~~reflected in a classified statement of financial position. ASU 2015-17 can be applied prospectively or retrospectively and is effective for financial statements issued for annual periods beginning after December 15, 2016 and interim periods within those annual periods and early adoption is permitted. The Company elected to implement ASU 2015-17 on a retrospective basis for financial statements issued beginning March 31, 2016. Thefuture rates. Upon implementation of ~~ASU 2015-17 did not have~~normalization, the Company began amortizing the net regulatory asset for deferred state income taxes to deferred income tax expense over a ~~material impact on~~15 year period as allowed by the ~~Company's results~~regulators. In the third quarter of ~~operations.~~2016, the Company began recording deferred state income tax expense as required by normalization, retroactive to January 2016 as provided in the final orders. The impact of ~~ASU 2015-17 on~~ the ~~Company's Balance Sheet~~change was ~~to reclassify $21.6~~additional deferred income tax expense of $1.1 million, ~~of current deferred tax assets to long-term deferred tax liabilities at December 31, 2015.~~$1.7 million and $4.9 million for the three, six and twelve months ended June 30, 2017, respectively.

G. Commitments, Contingencies and Uncertainties

For a full discussion of commitments and contingencies, see Note K of the Notes to Financial Statements in the ~~2015~~2016 Form 10-K. In addition, see Notes C and D above and Notes C and E of the Notes to Financial Statements in the ~~2015~~2016 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 reserve requirements, and to meet required renewable portfolio standards, the Company engages in power purchase arrangements which may vary in duration and amount based on an 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 the Notes to Financial Statements in the ~~2015~~2016 Form 10-K. The Company is exploring the possibility of a purchase of Renewable Energy Certificates to comply with New Mexico Renewable Portfolio Standard(s) requirements and the NMPRC's approval to complete such a purchase is pending.

Environmental Matters

General. The Company is subject to extensive laws, regulations and permit requirements with respect to air and greenhouse gas ("GHG") 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~~

On March 28, 2017 the Company ~~see Note K~~entered into a Compliance Agreement (“Compliance Agreement”) with the Texas Commission on Environmental Quality under the Texas Environmental, Health and Safety Audit Privilege Act to address certain water and waste compliance issues associated with the integrity of the ~~Notes to Financial Statements~~synthetic liner of the evaporation pond at the Company’s Newman Generating Station. The Company's action plan was initiated in the ~~2015~~ ~~Form 10-K.~~

~~Clean Air Interstate Rule/Cross State Air Pollution Rule. The EPA promulgated~~second quarter of 2017 and will continue to be implemented over 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~~three year period of the ~~Company's power plants in Texas and/or purchase allowances representing other parties' emissions reductions. CSAPR was intended to replace~~Compliance Agreement. The Company is currently evaluating the ~~EPA's 2005 Clean Air Interstate Rule ("CAIR"). While~~cost of performing its obligations under the ~~U.S. Court of Appeals for the~~Compliance Agreement.



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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 EPA's emissions budgets for 13 states including Texas are invalid, but left the rule in place on remand. On December 3, 2015, EPA published the proposed CSAPR Update Rule. 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 ("NAAQS").~~ Under the Clean Air Act ("CAA"), the EPA sets 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 nitrogen dioxide ("NO2") and SO2. The EPA is considering a 1-hour secondary NAAQS for NO2 and SO2. In January 2013, the EPA tightened the NAAQS for fine PM. On October 1, 2015, following on its November 2014 proposal, EPA released a final rule tightening the primary and secondary NAAQS for ground-level ozone from its 2008 standard levels of 75 parts per billion ("ppb") to 70 ppb. 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. The EPA is expected to make attainment/nonattainment designations for the revised ozone standards by October 1, 2017. While it is currently unknown how the areas in which we operate will ultimately be designated, for nonattainment areas classified as "Moderate" and above, states, and any tribes that choose to do so, are expected to be required to complete development of implementation plans in the 2020-2021 timeframe. Most nonattainment areas are expected to have until 2020 or 2023 to meet the primary (health) standard, with the exact attainment date varying based on the ozone level in the area. 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 NAAQS, individually or in the aggregate, could have a material impact on its operations and financial results.

~~Mercury and Air Toxics Standards.~~ The operation of coal-fired power plants, such as Four Corners, results in emissions of mercury and other air toxics. In December 2011, the EPA finalized Mercury and Air Toxics Standards (known as the "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 have been made to this rule, and on June 29, 2015, the U.S. Supreme Court remanded the rule to the D.C. Circuit Court. On December 15, 2015, the D.C. Circuit Court issued an order remanding the rule to EPA but did not vacate the rule during remand. On April 15, 2016, the EPA completed a cost-benefit analysis of the MATS rule and reaffirmed its finding that the rule is "appropriate and necessary," which will be reviewed by the D.C. Circuit Court. 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 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 expects to 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. On June 15, 2016, the Company received a final order containing the required regulatory approval from the NMPRC. On July 6, 2016, the closing of the transaction occurred, after which the Company no longer owns any coal-fired generation.

~~Coal Combustion Waste.~~ On October 19, 2015, the EPA's final rule regulating the disposal of coal combustion residuals (the “CCR Rule”) from electric utilities as solid waste took effect. The Company had a 7% ownership interest in Units 4 and 5 of Four Corners, the only coal-fired generating facility for which the Company had 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 and closing of the sale occurred on July 6, 2016. The CCR Rule requires plant owners to treat coal combustion residuals as Subtitle D (as opposed to a more costly Subtitle C) waste. In general, the Company is 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 Purchase Agreement and after the sale, as a former owner, that the Company is not responsible for a significant portion of the costs under the CCR Rule, such as ongoing operational costs after July 2016. Accordingly, the Company does not expect the CCR Rule to have a significant impact on our financial condition or results of operations.

On November 3, 2015, the EPA published a final rule revising wastewater effluent limitation guidelines for steam electric power generators (the "Revised ELG Rule"). The Revised ELG Rule establishes requirements for wastewater streams from certain



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~~(Unaudited)~~

processes at affected facilities, including limits on toxic metals in wastewater discharges. Facilities must comply with the Revised ELG Rule between 2018 and 2023. The EPA anticipates that the new requirements in the Revised ELG Rule will only affect certain coal-fired steam electric power plants. Because the Company does not have an interest in Four Corners after the closing of the sale in July 2016, the Company does not expect the Revised ELG Rule will 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. On December 29, 2015, OSM took action to cure the defect in its permitting process by issuing a revised environmental assessment and finding of no new significant impact, and reissued the permit. This action is subject to possible judicial review. On March 30, 2016, the U.S. Court of Appeals vacated and dismissed the federal court decision that halted operations in Area IV North at the Navajo Mine.

On April 20, 2016, the same environmental groups filed a new complaint in Arizona's federal district court, challenging multiple permits and approvals issued to both the Navajo Mine and Four Corners authorizing operations from July 2016 onwards. The complaint seeks to enjoin federal agencies, including the OSM and Bureau of Indian Affairs, from authorizing any element of the power plant or mine without further environmental impact analysis.

~~Climate Change.~~ In recent years, there has been increasing public debate regarding the potential impact of global climate change. There has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of GHG and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Most recently, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to creation of the Paris Agreement. On April 22, 2016, 175 countries, including the United States, signed the Paris Agreement, signaling their intent to join. Those countries that subsequently ratify the agreement will be required to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals, every five years, beginning in 2020.

The U.S. federal government has either considered, proposed, and/or finalized legislation or regulations limiting GHG emissions, including carbon dioxide. 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 carbon dioxide 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 October 2015, the EPA published a final rule establishing new source performance standards ("NSPS") limiting CO2 emissions from new, modified, and reconstructed electric generating units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate CO2 emissions from existing power plants, as well as a proposed "federal plan" to address CO2 emissions from affected units in those states that do not submit an approvable compliance plan. 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 were filed by groups of states and industry members. On February 9, 2016, the U.S. Supreme Court issued a decision to stay the rule until legal issues are resolved. We cannot at this time determine the impact the CPP and related rules and legal challenges may have on our financial position, results of operations, or cash flows.

H. Litigation

The Company is involved in various legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. The Company regularly analyzes current information and, as necessary, makes provisions in its financial statements for probable liabilities for the eventual disposition of these matters. While the outcome of these matters cannot be predicted with certainty, based upon a review of the matters and applicable insurance coverage, the Company believes that none of these matters 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.



	22

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~~EL PASO ELECTRIC COMPANY~~

~~NOTES TO FINANCIAL STATEMENTS~~

~~(Unaudited)~~

See Notes C and G above and Notes C and K of the Notes to Financial Statements in the ~~2015~~2016 Form 10-K for discussion of the effects of government legislation and regulation on the Company.



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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, ~~2016~~2017 and ~~2015~~2016 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						Three Months Ended						Six Months Ended						Twelve Months Ended
	June 30,						June 30,						June 30,						June 30,						June 30,						June 30,
	2016			2015			2016			2015			2016			2015			2017			2016			2017			2016			2017			2016
Components of net periodic benefit cost:
Service cost	$	1,905		$	2,100		$	3,810		$	4,200		$	8,402		$	8,425		$	1,989		$	1,905		$	4,259		$	3,810		$	8,450		$	8,402
Interest cost	3,265			3,625			6,530			7,250			13,775			14,632			3,282			3,265			6,530			6,530			13,039			13,775
Expected return on plan assets	(4,713		)	(4,948		)	(9,425		)	(9,895		)	(19,325		)	(19,258		)	(4,787		)	(4,713		)	(9,595		)	(9,425		)	(19,049		)	(19,325		)
Amortization of:
Net loss	1,887			2,750			3,775			5,500			8,922			10,065			2,138			1,887			4,227			3,775			7,791			8,922
Prior service benefit	(877		)	(887		)	(1,755		)	(1,775		)	(3,486		)	(3,528		)	(875		)	(877		)	(1,753		)	(1,755		)	(3,504		)	(3,486		)
Net periodic benefit cost	$	1,467		$	2,640		$	2,935		$	5,280		$	8,288		$	10,336		$	1,747		$	1,467		$	3,668		$	2,935		$	6,727		$	8,288

During the six months ended June 30, ~~2016~~2017, the Company contributed $~~2.8~~6.5 million of its projected $~~6.2~~10.0 million ~~2016~~2017 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, ~~2016~~2017 and ~~2015~~2016 is made up of the components listed below (in thousands):


	Three Months Ended						Six Months Ended						Twelve Months Ended						Three Months Ended						Six Months Ended						Twelve Months Ended
	June 30,						June 30,						June 30,						June 30,						June 30,						June 30,
	2016			2015			2016			2015			2016			2015			2017			2016			2017			2016			2017			2016
Components of net periodic benefit cost:
Components of net periodic benefit:
Service cost	$	715		$	875		$	1,430		$	1,750		$	3,134		$	3,173		$	530		$	715		$	1,118		$	1,430		$	2,457		$	3,134
Interest cost	872			1,025			1,745			2,050			3,730			4,281			684			872			1,362			1,745			2,784			3,730
Expected return on plan assets	(460		)	(525		)	(920		)	(1,050		)	(1,940		)	(2,108		)	(483		)	(460		)	(953		)	(920		)	(1,868		)	(1,940		)
Amortization of:
Prior service benefit	(787		)	(775		)	(1,575		)	(1,550		)	(3,093		)	(3,927		)	(1,538		)	(787		)	(3,076		)	(1,575		)	(5,402		)	(3,093		)
Net gain	(665		)	(500		)	(1,330		)	(1,000		)	(2,355		)	(2,335		)	(444		)	(665		)	(839		)	(1,330		)	(1,883		)	(2,355		)
Net periodic benefit cost (benefit)	$	(325	)	$	100		$	(650	)	$	200		$	(524	)	$	(916	)
Net periodic benefit																			$	(1,251	)	$	(325	)	$	(2,388	)	$	(650	)	$	(3,912	)	$	(524	)

During the six months ended June 30, ~~2016,~~2017, the Company contributed ~~$1.1~~$0.2 million of its projected ~~$1.7~~$2.4 million ~~2016~~2017 annual contribution to its other ~~post retirement~~postretirement benefits plan.

J. Financial Instruments and Investments

The FASB guidance requires the Company to disclose estimated fair values for its financial instruments. The Company has determined that cash and temporary investments, investment in debt securities, accounts receivable, decommissioning trust funds, long-term debt, short-term borrowings under the ~~RCF,~~Revolving Credit Facility ("RCF"), accounts payable and customer deposits meet the definition of financial



	23

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~~EL PASO ELECTRIC COMPANY~~

~~NOTES TO FINANCIAL STATEMENTS~~

~~(Unaudited)~~

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 estimated fair value.



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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, 2016				December 31, 2015				June 30, 2017				December 31, 2016
	Carrying Amount (1)		Estimated Fair Value		Carrying Amount (1)		Estimated Fair Value		Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Pollution Control Bonds	$	190,637	$	214,132	$	190,499	$	212,624	$	190,913	$	204,498	$	190,775	$	206,818
Senior Notes	992,924		1,193,209		837,475		829,864		993,254		1,173,767		993,086		1,112,285
RGRT Senior Notes ~~(2)~~(1)	94,740		101,215		94,686		100,345		94,849		98,075		94,795		98,855
RCF ~~(2)~~(1)	101,614		101,614		141,738		141,738		178,884		178,884		81,574		81,574
Total	$	1,379,915	$	1,610,170	$	1,264,398	$	1,284,571	$	1,457,900	$	1,655,224	$	1,360,230	$	1,499,532

_______________

(1)

The Company implemented ASU 2015-03, Interest - Imputation of Interest, which 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. 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 impact of ASU 2015-03 on the Company's Balance Sheet was to reclassify $11.6 million of other deferred charges to long-term debt, net of current portion at December 31, 2015.

~~(2)~~

Nuclear fuel financing, as of June 30, ~~2016~~2017 and December 31, ~~2015,~~2016, is funded through the $95 million ~~RGRT~~Rio Grande Resources Trust ("RGRT") Senior Notes and ~~$34.6~~$38.9 million and ~~$33.7~~$37.6 million, respectively under the RCF. As of June 30, ~~2016, $67.0~~2017, $140.0 million was outstanding under the RCF for working capital or general corporate purposes. As of December 31, ~~2015, $108.0~~2016, $44.0 million 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 ~~$248.2~~$271.3 million and ~~$239.0~~$255.7 million at June 30, ~~2016~~2017 and December 31, ~~2015,~~2016, respectively. These securities are classified as available for sale and recorded at their estimated fair value using the FASB guidance for certain investments in debt and equity 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, 2016															June 30, 2017
	Less than 12 Months					12 Months or Longer					Total					Less than 12 Months					12 Months or Longer					Total
	Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses
Description of Securities (1):
Federal Agency Mortgage Backed Securities	$	497	$	(5	)	$	584	$	(6	)	$	1,081	$	(11	)	$	15,446	$	(188	)	$	415	$	(19	)	$	15,861	$	(207	)
U.S. Government Bonds	6,174		(54		)	14,844		(461		)	21,018		(515		)	35,388		(598		)	9,816		(630		)	45,204		(1,228		)
Municipal Obligations	2,020		(23		)	9,018		(540		)	11,038		(563		)
Corporate Obligations	1,498		(30		)	3,300		(166		)	4,798		(196		)
Municipal Debt Obligations																6,903		(165		)	5,928		(482		)	12,831		(647		)
Corporate Debt Obligations																7,308		(79		)	2,944		(235		)	10,252		(314		)
Total Debt Securities	10,189		(112		)	27,746		(1,173		)	37,935		(1,285		)	65,045		(1,030		)	19,103		(1,366		)	84,148		(2,396		)
Common Stock	2,146		(504		)	—		—			2,146		(504		)	718		(65		)	—		—			718		(65		)
Institutional Equity Funds-International Equity	21,360		(1,774		)	—		—			21,360		(1,774		)
Total Temporarily Impaired Securities	$	33,695	$	(2,390	)	$	27,746	$	(1,173	)	$	61,441	$	(3,563	)	$	65,763	$	(1,095	)	$	19,103	$	(1,366	)	$	84,866	$	(2,461	)

_________________


(1)	Includes 93136 securities.



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NOTES TO FINANCIAL STATEMENTS

(Unaudited)


	December 31, 2015															December 31, 2016
	Less than 12 Months					12 Months or Longer					Total					Less than 12 Months					12 Months or Longer					Total
	Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses
Description of Securities (2):
Federal Agency Mortgage Backed Securities	$	9,383	$	(97	)	$	1,113	$	(47	)	$	10,496	$	(144	)	$	11,582	$	(239	)	$	436	$	(22	)	$	12,018	$	(261	)
U.S. Government Bonds	24,094		(310		)	14,272		(623		)	38,366		(933		)	31,655		(762		)	17,976		(835		)	49,631		(1,597		)
Municipal Obligations	8,286		(160		)	7,388		(446		)	15,674		(606		)
Corporate Obligations	6,058		(722		)	2,307		(228		)	8,365		(950		)
Municipal Debt Obligations																9,596		(394		)	4,067		(372		)	13,663		(766		)
Corporate Debt Obligations																7,971		(172		)	2,092		(172		)	10,063		(344		)
Total Debt Securities	47,821		(1,289		)	25,080		(1,344		)	72,901		(2,633		)	60,804		(1,567		)	24,571		(1,401		)	85,375		(2,968		)
Common Stock	3,584		(344		)	—		—			3,584		(344		)	2,760		(167		)	—		—			2,760		(167		)
Institutional Equity Funds-International Equity	22,454		(768		)	—		—			22,454		(768		)	22,945		(110		)	—		—			22,945		(110		)
Total Temporarily Impaired Securities	$	73,859	$	(2,401	)	$	25,080	$	(1,344	)	$	98,939	$	(3,745	)	$	86,509	$	(1,844	)	$	24,571	$	(1,401	)	$	111,080	$	(3,245	)

_________________


(2)	Includes ~~133~~152 securities.

The Company monitors the length of time specific securities trade below ~~its~~their 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. The Company recognizes impairment losses on certain of its securities deemed to be other than temporary. In accordance with the FASB guidance, these impairment losses are recognized in net income, and a lower cost basis is established for these securities. In addition, the Company will research the future prospects of individual securities as necessary. The Company does not anticipate expending monies held in trust before 2044 or a later period when decommissioning of Palo Verde begins.

For the three, six and twelve months ended June 30, ~~2016~~2017 and ~~2015,~~2016, the Company recognized other than temporary impairment losses on its available-for-sale securities as follow (in thousands):

Three Months Ended Six Months Ended Twelve Months Ended
June 30, June 30, June 30,
2016 2015 2016 2015 2016 2015
Unrealized holding losses included in pre-tax income $ —
$ —
$ (156 ) $ —
$ (494 ) $ —



	Three Months Ended				Six Months Ended					Twelve Months Ended
	June 30,				June 30,					June 30,
	2017		2016		2017		2016			2017			2016
Unrealized holding losses included in pre-tax income	$	—	$	—	$	—	$	(156	)	$	(196	)	$	(494	)

The reported securities 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, 2016				December 31, 2015				June 30, 2017				December 31, 2016
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains		Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
Description of Securities:
Federal Agency Mortgage Backed Securities	$	17,852	$	725	$	9,589	$	438	$	6,662	$	272	$	7,430	$	319
U.S. Government Bonds	37,332		1,670		12,033		136		13,846		311		12,237		138
Municipal Obligations	11,747		539		8,671		332
Corporate Obligations	17,455		1,265		10,110		368
Municipal Debt Obligations									5,197		161		2,481		144
Corporate Debt Obligations									20,981		995		12,350		655
Total Debt Securities	84,386		4,199		40,403		1,274		46,686		1,739		34,498		1,256
Common Stock	67,574		34,603		72,636		37,001		53,489		30,766		61,884		34,066
Equity Mutual Funds	29,153		863		18,853		91		54,236		7,028		42,244		3,345
Institutional Funds - International Equity									26,149		3,174		—		—
Cash and Cash Equivalents	5,686		—		8,204		—		5,889		—		6,002		—
Total	$	186,799	$	39,665	$	140,096	$	38,366	$	186,449	$	42,707	$	144,628	$	38,667



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NOTES TO FINANCIAL STATEMENTS

(Unaudited)

The Company's marketable securities include investments in mortgage backed securities, 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, ~~2016~~2017 is as follows (in thousands):


	Total		2016		2017 through 2020		2021 through 2025		2026 and Beyond		Total		2017		2018 through 2021		2022 through 2026		2027 and Beyond
Federal Agency Mortgage Backed Securities											$	22,523	$	—	$	5	$	338	$	22,180
U.S. Government Bonds											59,050		5,893		24,224		15,981		12,952
Municipal Debt Obligations	$	22,785	$	711	$	8,957	$	11,727	$	1,390	18,028		796		6,215		9,743		1,274
Corporate Debt Obligations	22,253		—		4,799		8,920		8,534		31,233		—		12,309		8,949		9,975
U.S. Government Bonds	58,350		3,404		27,172		14,676		13,098

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~~from accumulated other comprehensive income ~~and~~ into net income. The proceeds from the sale of these securities during the three, six and twelve months ended June 30, ~~2016~~2017 and ~~2015~~2016 and the related effects on pre-tax income are as follows (in thousands):


	Three Months Ended						Six Months Ended						Twelve Months Ended						Three Months Ended						Six Months Ended						Twelve Months Ended
	June 30,						June 30,						June 30,						June 30,						June 30,						June 30,
	2016			2015			2016			2015			2016			2015			2017			2016			2017			2016			2017			2016
Proceeds from sales or maturities of available-for-sale securities	$	16,634		$	12,516		$	40,712		$	37,158		$	106,121		$	109,095		$	36,476		$	16,634		$	62,531		$	40,712		$	113,087		$	106,121
Gross realized gains included in pre-tax income	$	2,409		$	33		$	4,241		$	3,815		$	12,805		$	8,410		$	5,322		$	2,409		$	7,909		$	4,241		$	12,880		$	12,805
Gross realized losses included in pre-tax income	(299		)	(215		)	(587		)	(252		)	(1,262		)	(464		)	(156		)	(299		)	(552		)	(587		)	(1,185		)	(1,262		)
Gross unrealized losses included in pre-tax income	—			—			(156		)	—			(494		)	—			—			—			—			(156		)	(196		)	(494		)
Net gains (losses) included in pre-tax income	$	2,110		$	(182	)	$	3,498		$	3,563		$	11,049		$	7,946
Net gains included in pre-tax income																			$	5,166		$	2,110		$	7,357		$	3,498		$	11,499		$	11,049
Net unrealized holding gains (losses) included in accumulated other comprehensive income	$	2,790		$	(1,563	)	$	4,980		$	(549	)	$	2,623		$	3,210		$	4,458		$	2,790		$	12,179		$	4,980		$	15,643		$	2,623
Net (gains) losses reclassified from accumulated other comprehensive income	(2,110		)	182			(3,498		)	(3,563		)	(11,049		)	(7,946		)
Net gains reclassified from accumulated other comprehensive income																			(5,166		)	(2,110		)	(7,357		)	(3,498		)	(11,499		)	(11,049		)
Net gains (losses) in other comprehensive income	$	680		$	(1,381	)	$	1,482		$	(4,112	)	$	(8,426	)	$	(4,736	)	$	(708	)	$	680		$	4,822		$	1,482		$	4,144		$	(8,426	)

Fair Value Measurements. The FASB guidance requires the Company to provide expanded quantitative disclosures for financial assets and liabilities recorded on the balance sheet at fair value. Financial assets carried at fair value include the Company's decommissioning trust investments and investments in debt securities which are included in deferred charges and other assets on the 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. The Institutional Funds 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. During the third quarter of 2016, the Company concluded that the NAV used for determining the fair value of the Institutional Funds-International Equity investments have readily determinable fair values. Accordingly, such fund values have been re-categorized from Level 2 to Level 1 hierarchy.

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



	24

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

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 Institutional Funds are valued using the 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.



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~~EL PASO ELECTRIC COMPANY~~

~~NOTES TO FINANCIAL STATEMENTS~~

~~(Unaudited)~~

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. The 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.

The fair value of the Company's decommissioning trust funds and investments in debt securities at June 30, ~~2016~~2017 and December 31, ~~2015~~2016, and the level within the three levels of the fair value hierarchy defined by the FASB guidance are presented in the table below (in thousands):

Description of Securities Fair Value as of June 30, 2016
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 $ 1,376
$ —
$ —
$ 1,376
Available for sale:
U.S. Government Bonds $ 58,350
$ 58,350
$ —
$ —
Federal Agency Mortgage Backed Securities 18,933
—
18,933
—
Municipal Bonds 22,785
—
22,785
—
Corporate Asset Backed Obligations 22,253
—
22,253
—
Subtotal Debt Securities 122,321
58,350
63,971
—
Common Stock 69,720
69,720
—
—
Equity Mutual Funds 29,153
29,153
—
—
Institutional Funds-International Equity (1) 21,360

Cash and Cash Equivalents 5,686
5,686
—
—
Total Available for Sale $ 248,240
$ 162,909
$ 63,971
$ —


Description of Securities	Fair Value as of December 31, 2015		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Fair Value as of June 30, 2017		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	$	1,543	$	—	$	—	$	1,543	$	1,538	$	—	$	—	$	1,538
Available for sale:
Available for Sale:
Federal Agency Mortgage Backed Securities									$	22,523	$	—	$	22,523	$	—
U.S. Government Bonds	$	50,399	$	50,399	$	—	$	—	59,050		59,050		—		—
Federal Agency Mortgage Backed Securities	20,085		—		20,085		—
Municipal Bonds	24,345		—		24,345		—
Corporate Asset Backed Obligations	18,475		—		18,475		—
Subtotal Debt Securities	113,304		50,399		62,905		—
Municipal Debt Obligations									18,028		—		18,028		—
Corporate Debt Obligations									31,233		—		31,233		—
Subtotal, Debt Securities									130,834		59,050		71,784		—
Common Stock	76,220		76,220		—		—		54,207		54,207		—		—
Equity Mutual Funds	18,853		18,853		—		—		54,236		54,236		—		—
Institutional Funds-International Equity ~~(1)~~	22,454								26,149		26,149		—		—
Cash and Cash Equivalents	8,204		8,204		—		—		5,889		5,889		—		—
Total Available for Sale	$	239,035	$	153,676	$	62,905	$	—	$	271,315	$	199,531	$	71,784	$	—



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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

(1) In accordance with ASU 2015-07 Subtopic 820-10, certain investments that are measured at fair value using the NAV per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in the table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the statement of financial position.



Description of Securities	Fair Value as of December 31, 2016		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	$	1,421	$	—	$	—	$	1,421
Available for Sale:
Federal Agency Mortgage Backed Securities	$	19,448	$	—	$	19,448	$	—
U.S. Government Bonds	61,868		61,868		—		—
Municipal Debt Obligations	16,144		—		16,144		—
Corporate Debt Obligations	22,413		—		22,413		—
Subtotal, Debt Securities	119,873		61,868		58,005		—
Common Stock	64,644		64,644		—		—
Equity Mutual Funds	42,244		42,244		—		—
Institutional Funds-International Equity	22,945		22,945		—		—
Cash and Cash Equivalents	6,002		6,002		—		—
Total Available for Sale	$	255,708	$	197,703	$	58,005	$	—

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 ended June 30, ~~2016~~2017 and ~~2015.~~2016. 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, ~~2016~~2017 and ~~2015.~~2016.



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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, ~~2016~~2017, the related ~~condensed~~ statements of operations and comprehensive operations for the three-month, six-month, and twelve-month periods ended June 30, ~~2016~~2017 and ~~2015~~2016, and the related ~~condensed~~ statements of cash flows for the six-month periods ended June 30, ~~2016~~2017 and ~~2015~~2016. These ~~condensed~~ 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 ~~the~~ standards of the Public Company Accounting Oversight Board (United States), the balance sheet of El Paso Electric Company as of December 31, ~~2015~~2016, 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 ~~29,~~24, ~~2016~~2017, 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, ~~2015~~2016, is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived.

/s/ KPMG LLP

Houston, Texas

August ~~5, 2016~~4, 2017



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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 ~~2015~~2016 Form 10-K.

FORWARD-LOOKING STATEMENTS

Certain matters discussed in this Quarterly Report on Form 10-Q, other than statements of historical ~~information~~fact, are “forward-looking statements.” within the meaning of Section 27A of the Securities Act of ~~1933.~~1933, as amended ~~(the "Securities~~("Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended ~~(the "Exchange~~("Exchange Act"). Forward-looking statements often include words like we "believe", "anticipate", "target", "project", "expect", "predict", ~~"pro-forma"~~"pro forma", "estimate", "intend", "will", "is designed to", "plan", and words of similar meaning, or are indicated by the Company's discussion of strategies or trends. Forward-looking statements describe ~~our~~the Company's future plans, objectives, expectations ~~and~~or goals. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, no assurances can be given that these expectations will prove to be correct. Such statements address future events and conditions and include, but are not limited to:

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,

operation of the Company's generating units and its transmission and distribution systems, and

the overall economy of our service area.

These forward-looking statements are based on assumptions and analyses in light of the Company's experience and perception of historical trends, current conditions, expected future developments, and other factors the Company believes were appropriate in the circumstances when the statements were made. Forward-looking statements by their nature involve substantial risks and uncertainties that could significantly impact expected results, and actual future results could differ materially from those described in such statements. While it is not possible to identify all factors, the Company continues to face many risks and uncertainties. Factors that would cause or contribute to such differences include, but are not limited to:

actions of ~~our~~the Company's regulators,

~~our~~the Company's ability to fully and timely recover ~~our~~its costs and earn a reasonable rate of return on ~~our~~its invested capital through the rates that ~~we are~~it is permitted to charge,

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

the ability of ~~our~~the Company's operating partners to maintain plant operations and manage operation and maintenance ("O&M") costs at ~~the~~ Palo Verde ~~plant,~~Nuclear Generating Station ("Palo Verde"), including costs to comply with any new or expanded regulatory or environmental requirements,

reductions in output at generation plants operated by ~~us,~~the Company,

the size of ~~our~~the Company's construction program and ~~our~~its ability to complete construction on budget and on time,

~~our~~the Company's reliance on significant customers,

the credit worthiness of ~~our~~the Company's customers,

unscheduled outages of generating units including outages at Palo Verde,

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

individual customer groups, including distributed generation customers, may not pay their full cost of service, and other customers may or may not be required to pay the difference,

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

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

~~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,~~



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disruptions in the Company's transmission system, and in particular the lines that deliver power from its remote generating facilities,

the sufficiency of the Company's insurance coverage, including availability, cost, coverage and terms,

electric utility deregulation or re-regulation,

regulated and competitive markets,

ongoing municipal, state and federal activities,

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

political, legislative, judicial and regulatory developments,

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

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,

economic, commercial bank and ~~capital~~financial market conditions,

actions by credit rating agencies,

changes in accounting requirements and other accounting matters,

changing weather trends and the impact of severe weather conditions,

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

the impact of lawsuits filed against ~~us,~~the Company,

the impact of changes in interest rates or rates of inflation,

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

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 Internal Revenue Service or state taxing authorities,

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

the effectiveness of the Company's risk management activities,

loss of key personnel, ~~our~~the Company's ability to recruit and retain qualified employees and ~~our~~the Company's 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 ~~2015~~2016 Form 10-K under the headings “Risk Factors” and “Management's Discussion and ~~Analysis” “-Summary~~Analysis Summary of Critical Accounting Policies and ~~Estimates”~~Estimates and ~~“-Liquidity~~Liquidity and Capital Resources.” This Quarterly Report on Form 10-Q should be read in its entirety. Management cautions against putting undue reliance on forward-looking statements or projecting any future results based on such statements or present or prior earnings levels. Any forward-looking ~~statements~~statement speaks only as of the date such statement was made, ~~as we are~~and the Company is not obligated to update any forward-looking ~~statements~~statement to reflect events or circumstances after the date on which such statement was made, except as required by applicable laws or regulations.

Summary of Critical Accounting Policies and Estimates

The preparation of our financial statements requires management to make estimates and assumptions that affect the amounts reported in the financial statements and related notes for the periods presented and actual results could differ in future periods from those estimates. Critical accounting policies and estimates are both important to the portrayal of our financial condition and results of operations and require complex, subjective judgments and are more fully described in the "Management's Discussion and Analysis of Financial Condition and Results of Operations" in ~~our 2015~~the Annual Report of El Paso Electric Company on Form ~~10-K.~~10-K for the fiscal year ended December 31, 2016 ("2016 Form 10-K").



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Table of Contents

Summary

The following is an overview of our results of operations for the three, six and twelve month periods ended June 30, ~~2016~~2017 and ~~2015~~2016. Net income and basic earnings per share for the three, six and twelve month periods ended June 30, ~~2016~~2017 and ~~2015~~2016 are shown below:


	Three Months Ended				Six Months Ended				Twelve Months Ended				Three Months Ended				Six Months Ended				Twelve Months Ended
	June 30,				June 30,				June 30,				June 30,				June 30,				June 30,
	2016		2015		2016		2015		2016		2015		2017		2016		2017		2016		2017		2016
Net income (in thousands)	$	22,284	$	21,072	$	16,476	$	24,530	$	73,864	$	81,247	$	36,066	$	22,284	$	32,077	$	16,476	$	112,369	$	73,864
Basic earnings per share	0.55		0.52		0.41		0.61		1.83		2.01		0.89		0.55		0.79		0.41		2.77		1.83

Financial Effect of the PUCT Final Order

~~Regulatory Lag~~

~~Our~~On August 25, 2016, the Public Utility Commission of Texas ("PUCT") issued its final order in the Company's rate case in Docket No. 44941 ("PUCT Final Order"). The PUCT Final Order had a significant effect on the Company's financial results ~~of operations~~ for the three, six, and twelve months ended June 30, 2017, the impacts of which are reflected in the table below. For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2015 Texas retail rate case until it received the PUCT Final Order in August 2016. Accordingly, it recorded in the third quarter of 2016 ~~compared~~the cumulative effect of the PUCT Final Order that related back to January 12, 2016. The impact of the PUCT Final Order recorded in August 2016 relating to the ~~same periods in 2015~~three and six months ended June 30, 2016 would have ~~been negatively impacted~~increased net income by approximately $8.0 million and $12.6 million, respectively. Likewise as ~~a result~~it relates to the PUCT Final Order, net income for the twelve months ended June 30, 2016 would have increased by approximately $12.6 million while net income for the twelve months ended June 30, 2017 would have decreased by approximately $12.6 million. Furthermore, because the Company recorded the cumulative effect of the ~~completion~~PUCT’s Final Order in August 2016, it is expected that results of ~~Montana Power Station ("MPS") Units 1 & 2 (including common plant, transmission lines and substation) and~~operations for the ~~Eastside Operations Center ("EOC"), due~~three months ended September 30, 2017 will not be comparative to the ~~regulatory lag associated with~~results of operations for the ~~placement in service ofthese assets without a corresponding increase in revenues. The placement in service of MPS Unit 3 in~~



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~~Table of Contents~~

~~May 2016 and the anticipated completion of MPS Unit 4 in~~three months ended September 2016 will continue the negative impact of regulatory lag until new and higher rates become effective. As discussed in Note C of the Notes to Financial Statements, interim rates subject to refund or surcharge were implemented on April 1, 2016 in Texas. However, due to the uncertainties surrounding the rate case, the Company did not recognize the effects of the increased interim rates in our Statements of Operations. The Company believes rates reflecting the recovery of the investment in and related costs of MPS Units 1 & 2 and the EOC in our Texas jurisdiction will be in place in the second half of30, 2016. New rates reflecting such recovery were implemented in New Mexico effective July 1, 2016. The Company anticipates filing new rate cases in Texas and New Mexico in early 2017 to reflect MPS Units 3 & 4 in rate base. The primary impact from these assets being placed in service include a reduction in amounts capitalized for allowance for funds used during construction ("AFUDC"), and increases in depreciation, operations and maintenance ("O&M") expense, property taxes and interest cost.

The following table ~~and accompanying explanations show~~shows the primary factors affecting the after-tax change in net income between the ~~2016~~2017 and ~~2015~~2016 periods presented (in thousands):

Three Months Ended Six Months Ended Twelve Months Ended
June 30, 2015 net income $ 21,072
$ 24,530
$ 81,247
Change in (net of tax):
Increased retail non-fuel base revenues (a) 1,992
2,616
12,674
Increased (decreased) investment and interest income (b) 1,769
(95 ) 2,581
(Increased) decreased operation and maintenance at fossil-fuel generating plants (c) 45
(2,016 ) 472
Increased interest on long-term debt (d) (1,171 ) (1,247 ) (3,217 )
Increased depreciation and amortization (e) (466 ) (1,590 ) (3,822 )
Decreased allowance for funds used during construction (f) (148 ) (2,712 ) (8,076 )
(Increased) decreased administrative and general expenses (g) 268
(208 ) (3,791 )
Deregulated Palo Verde Unit 3 (h) (12 ) (636 ) (2,196 )
Other (101 ) (1,295 ) (1,614 )
Changes in the effective tax rate (i) (964 ) (871 ) (394 )
June 30, 2016 net income $ 22,284
$ 16,476
$ 73,864



	Three Months Ended			Six Months Ended			Twelve Months Ended
June 30, 2016 net income	$	22,284		$	16,476		$	73,864
Change in (net of tax):
Increased retail non-fuel base revenues (a)	12,062			15,421			41,607
Palo Verde performance rewards, net (b)	3,253			3,253			3,253
Increased investment and interest income (c)	2,477			3,289			744
Decreased depreciation and amortization (d)	882			1,765			6,935
Decreased allowance for funds used during construction (e)	(1,838		)	(3,923		)	(6,098		)
Increased administrative and general expenses (f)	(1,438		)	(1,019		)	(672		)
Increased taxes other than income taxes (g)	(1,264		)	(1,860		)	(2,676		)
Increased interest on long-term debt (h)	(71		)	(1,220		)	(3,673		)
Other (i)	(281		)	(105		)	(915		)
June 30, 2017 net income	$	36,066		$	32,077		$	112,369

______________

All information presented below is expressed in pre-tax amounts except when stated otherwise.

(a)

Retail non-fuel base revenues increased for the three ~~and six~~months ended June 30, 2017 compared to the three months ended June 30, 2016 ~~compared~~primarily due to the non-fuel base rate increase approved in the PUCT Final Order. The three ~~and six~~ months ended June 30, ~~2015, primarily due to increased~~2016 did not include approximately $11.3 million of retail non-fuel base revenues for the period from ~~our residential customers and small commercial and industrial customers primarily due to increased kWh sales that resulted from an increase~~April 1, 2016 through June 30, 2016, which revenues were not recognized until the PUCT Final Order was approved in ~~average number of customers served and warmer weather. These increases were partially offset by the decreased revenues from sales to public authorities and large commercial and industrial customers.~~August 2016.



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Table of Contents

Warmer weather and the 1.8% growth in the average number of retail customers served also contributed to the increase in retail non-fuel base revenues.

Retail non-fuel base revenues increased for the six months ended June 30, 2017 compared to the six months ended June 30, 2016 primarily due to the non-fuel base rate increase approved in the PUCT Final Order. The six months ended June 30, 2016 did not include approximately $17.2 million of retail non-fuel base revenues for the period from January 12, 2016 through June 30, 2016, which revenues were not recognized until the PUCT Final Order was approved in August 2016. The 1.7% growth in the average number of retail customers served also contributed to the increase in retail non-fuel base revenues.

Retail non-fuel base revenues increased for the twelve months ended June 30, ~~2016~~2017 compared to the twelve months ended June 30, ~~2015~~2016 primarily due to ~~increased revenues from our residential customers, small commercial and industrial customers and sales to public authorities primarily due to increased kWh sales that resulted from an~~the non-fuel base rate increase approved in the PUCT Final Order. The 1.6% growth in the average number of retail customers served ~~and warmer weather, and from our large commercial and industrial customers due~~also contributed to ~~an interruptible rate adjustment. For a complete discussion of~~the remaining increase in retail non-fuel base revenues, see page ~~34.~~32 for a complete discussion.


(b)	Palo Verde performance rewards, associated with the 2013 to 2015 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. 46308 for the period from April 2013 through March 2016, were recorded in June 2017 with no comparable amount in 2016.


(c)	Investment and interest income increased for the three, six and twelve months ended June 30, 2017 compared to the three, six and twelve months ended June 30, 2016 ~~compared to the three and twelve months ended June 30, 2015~~ primarily due to higher realized gains on securities sold from our Palo Verde decommissioning trust in ~~2016~~2017 compared to ~~2015.~~

~~(c)~~

O&M expenses at our fossil fuel generating plants increased for the six months ended June 30, 2016 compared to the six months ended June 30, 2015, primarily due to maintenance outages on Four Corners Units 4 & 5 and Rio Grande Unit 7 compared to the six months ended June 30, 2015. These increases were partially offset by a maintenance outage at Newman Unit 5 in 2015, with no comparable expense in the six months ended June 30, 2016.

(d)

~~Interest~~Depreciation and amortization decreased for the three, six, and twelve months ended June 30, 2017 compared to the three, six, and twelve months ended June 30, 2016 primarily due to reductions in depreciation rates as approved in the PUCT Final Order and in the final order in the NMPRC final order in Case No. 15-00127-UT issued on ~~long-term debt~~June 8, 2016 ("NMPRC Final Order"), and the sale of the Company's interest in Units 4 and 5 of Four Corners Generating Station ("Four Corners"). These decreases were partially offset by increases in plant, including Montana Power Station ("MPS") Units 3 and 4, which were placed in service in May and September 2016, respectively.


(e)	Allowance for funds used during construction ("AFUDC") decreased for the three, six and twelve months ended June 30, 2017 compared to the three, six and twelve months ended June 30, 2016 due to (i) lower balances of construction work in progress ("CWIP"), primarily due to MPS Units 3 and 4 being placed in service in 2016, and (ii) reductions in the AFUDC rate.

(f)

Administrative and general ("A&G") expense increased for the three and six months ended June 30, ~~2016~~2017 compared to the three and six months ended June 30, ~~2015,~~2016 primarily due to timing of the accrual of employee incentive compensation and an annual merit increase. A&G expense increased for the twelve months ended June 30, 2017 compared to the twelve months ended June 30, 2016 primarily due to (i) timing of the accrual of employee incentive compensation and an annual merit increase, and (ii) increased regulatory expenses due to our recent Texas and New Mexico rate cases. These increases were partially offset by decreased pension and benefit costs due primarily to (i) changes in actuarial assumptions used to calculate the pension and post-retirement employee benefit plans, and (ii) the sale of the Company's interest in Units 4 and 5 of Four Corners.


(g)	Taxes other than income taxes increased for the three months ended June 30, 2017 compared to the three months ended June 30, 2016 primarily due to increased revenue related taxes and increased property valuations in Texas as a result of MPS Units 3 and 4 being placed in service in 2016.

Taxes other than income taxes increased for the six and twelve months ended June 30, 2017 compared to the six and twelve months ended June 30, 2016 primarily due to increased revenue related taxes and increased property valuations in Texas as a result of MPS Units 3 and 4 being placed in service in 2016. These increases were partially offset by decreased property taxes in New Mexico due to decreased property valuations.


(h)	Interest on long-term debt increased for the ~~$150~~six and twelve months ended June 30, 2017 compared to the six and twelve months ended June 30, 2016 primarily due to the $150.0 million principal amount of ~~5.00%~~ senior notes issued in March 2016.


(i)	Other for the twelve months ended June 30, 2017 includes an increase in the effective tax rate due to the change to normalize state income taxes partially offset by an increase in other revenues due to additional miscellaneous service revenues approved in the PUCT Final Order and in the NMPRC Final Order.



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~~Table of Contents~~

Interest on long-term debt increased for the twelve months ended June 30, 2016 compared to the twelve months ended June 30, 2015, primarily due to interest on the $150 million of 5.00% senior notes each of which were issued in December 2014 and March 2016.


~~(e)~~	Depreciation and amortization increased for the three months ended June 30, 2016, compared to the three months ended June 30, 2015 due to an increase in depreciable plant, primarily due to MPS Unit 3, which was placed in service in May 2016, partially offset by a change in the estimated useful life of certain intangible software assets.

Depreciation and amortization increased for the six and twelve months ended June 30, 2016, compared to the six and twelve months ended June 30, 2015 due to an increase in depreciable plant, primarily due to MPS Units 1 & 2, and the EOC being placed in service in March 2015 and MPS Unit 3 being placed in service in May 2016, partially offset by a change in the estimated useful life of certain intangible software assets.


~~(f)~~	AFUDC decreased for the three months ended June 30, 2016 compared to the three months ended June 30, 2015, primarily due to a reduction in the AFUDC rate effective January 2016, partially offset by the AFUDC earned on construction costs related to MPS Units 3 & 4 in 2016.

AFUDC decreased for the six months ended June 30, 2016 compared to the six months ended June 30, 2015, primarily due to a reduction in the AFUDC rate effective January 2016 and lower balances of construction work in progress ("CWIP"), primarily due to MPS Units 1 & 2 and the EOC being placed in service in March 2015, partially offset by AFUDC earned on construction costs related to MPS Units 3 & 4 in 2016.

AFUDC decreased for the twelve months ended June 30, 2016 compared to the twelve months ended June 30, 2015 due to lower balances of CWIP, primarily due to MPS Units 1 & 2 and the EOC being placed in service in March 2015 and a reduction in the AFUDC rate. These decreases were partially offset by the AFUDC earned on construction costs related to MPS Units 3 & 4 in 2016.

~~(g)~~

Administrative and general expense increased for the twelve months ended June 30, 2016, compared to the twelve months ended June 30, 2015, primarily due to increased (i) employee payroll and incentive compensation and (ii) benefit costs primarily due to medical claims paid partially offset by decreased benefit costs due to a change in actuarial assumptions used to calculate our employee pension plan and (iii) regulatory expense due to the 2015 New Mexico rate case costs being expensed on a current basis.

~~(h)~~

Deregulated Palo Verde Unit 3 revenues for the six and twelve months ended June 30, 2016, decreased primarily due to 21.8% and 23.0%, respectively, decreases in proxy market prices as compared to the six and twelve months ended June 30, 2015, reflecting a decline in the price of natural gas. These decreases were partially offset by an increase in generation for the six and twelve months ended June 30, 2016 due in part to a Unit 3 planned 2015 spring refueling outage that was completed in May 2015 with no comparable outage in 2016.


~~(i)~~	The effective tax rate changed for the three, six and twelve months ended June 30, 2016, compared to the three, six and twelve months ended June 30, 2015, primarily due to the reduction of the domestic production manufacturing deduction and changes in state taxes.



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Table of Contents

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~~Federal Energy Regulatory Commission ("FERC") regulated cost-based wholesale sales within our service territory) accounted for less than 1% of revenues.

As discussed in Regulatory Lag above, we implemented interim rates in our Texas Jurisdiction on April 1, 2016. Given the uncertainties regarding the ultimate resolution of our Texas rate case, additional revenues resulting from the implementation of interim rates in the amount of $10.8 million were deferred and included in other current liabilities on the Company's Balance Sheet at June 30, 2016.

Revenues from the sale of electricity include fuel costs that are recovered from our customers through fuel adjustment mechanisms. Historically, a significant portion of fuel costs have been recovered through base rates in New Mexico. Effective July 1, 2016, with the implementation of the ~~final order of our New Mexico rate case,~~NMPRC Final Order, fuel costs ~~will~~are no longer be recovered through base rates. Beginning July 1, 2016, all fuel costs ~~will be~~are recovered through a fuel adjustment mechanism. 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~~"Non-fuel base ~~revenues”~~revenues" refers to our revenues from the sale of electricity excluding such fuel costs.

No retail customer accounted for more than 4%3% of our non-fuel base revenues. Residential and small commercial customers ~~comprise 75% or more~~approximates 77% 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 Texas and New Mexico 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, ~~2016,~~2017, retail non-fuel base revenues were positively impacted by warmer weather when compared to the three months ended June 30, 2016. Cooling degree days for the three months ended June 30, 2017 increased 14.8% when compared to the three months ended June 30, 2016, and were 4.5% above the 10-year average. Weather had minimal impact in the six and twelve months ended June 30, 2015. Cooling degree days in the second quarter of 2016 increased 3.9% when compared to the second quarter of 2015, but were 6.4% below the 10-year average. Cooling degree days for the six months ended June 30, 2016 increased 2.6%2017, when compared to the six ~~months ended June 30, 2015, but were 6.9% below the 10-year average. For the~~and twelve months ended June 30, 2016, cooling degree days increased 13.9% when compared to the twelve months ended June 30, 2015, and were 6.2% above the 10-year average. For the six months ended June 30, 2016, heating degree days decreased 6.4% when compared to the six months ended June 30, 2015, and were 10.0% below the 10-year average. For the twelve months ended June 30, 2016, heating degree days decreased 2.2% when compared to the twelve months ended June 30, 2015, and were 7.2% below the 10-year average.2016. The table below shows heating and cooling degree days compared to a 10-year average.


	Three Months Ended			Six Months Ended			Twelve Months Ended			Three Months Ended			Six Months Ended			Twelve Months Ended
	June 30,			June 30,			June 30,			June 30,			June 30,			June 30,
			10-Year			10-Year			10-Year			10-Year			10-Year			10-Year
	2016	2015	Average	2016	2015	Average	2016	2015	Average*	2017	2016	Average	2017	2016	Average	2017	2016	Average*
Heating degree days	75	53	72	1,129	1,206	1,255	2,018	2,064	2,174	45	75	68	855	1,129	1,203	1,577	2,018	2,157
Cooling degree days	965	929	1,031	988	963	1,061	2,864	2,514	2,696	1,108	965	1,060	1,180	988	1,093	3,003	2,864	2,732

______________

* Calendar year basis.

Customer growth is a key driver of the growth of retail sales. The average number of retail customers grew ~~1.5%~~1.8% and 1.7% for ~~both~~ the three and six ~~month periods~~months ended June 30, ~~2016~~2017, respectively, when compared to the three and six months ended June 30, ~~2015,~~2016, and ~~1.4%~~1.6% for the twelve months ended June 30, ~~2016~~2017 when compared to the twelve months ended June 30, ~~2015.~~2016. See the tables presented on pages 35, 36, ~~37,~~ and ~~38,~~37, 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 increased ~~$3.1 million, or 2.1%,~~ for the three months ended June 30, 2017 primarily due to the non-fuel base rate increase approved in the PUCT Final Order. The three months ended June 30, 2016 ~~when~~did not include approximately $11.3 million of retail non-fuel base revenues for the period from April 1, 2016 through June 30, 2016, which revenues were not recognized until the PUCT Final Order was approved in August 2016. Warmer weather and the 1.8% growth in the average number of retail customers served also contributed to the increase in retail non-fuel base revenues.

Excluding the $11.3 million PUCT Final Order impact, for the three months ended June 30, 2017, retail non-fuel base revenues increased $7.3 million pre-tax, or 4.5%, compared to the three months ended June 30, ~~2015. The~~2016. This increase primarily includes (i) a $4.3 million increase in ~~retail non-fuel base~~ revenues ~~includes a $3.3 million increase~~ from ~~sales to~~ residential customers due to a 6.7% increase in kWh sales which were driven by warmer weather and a ~~$0.8 million~~1.6% increase ~~from sales to small commercial and industrial customers, reflecting increases of 1.5%~~ in the average number of residential customers, ~~served for both categories, as well as~~(ii) a $1.2 million increase in revenues from sales to public authorities due to a 4.5% increase in kWh sales which were driven by warmer weather, ~~experienced~~and (iii) a $1.1 million increase in ~~the second quarter of 2016. KWh sales to residential customers and small commercial and industrial customers~~



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~~increased by 5.9% and 1.1%, respectively. Retail non-fuel base~~ revenues from ~~sales to public authorities and large~~small commercial and industrial customers ~~decreased $0.6 million and $0.4 million, respectively, reflecting~~due to a ~~3.5% and 2.8% decrease~~2.2% increase in kWh ~~sales.~~sales which were driven by a 2.5% increase in the average number of small commercial and industrial customers.

Retail non-fuel ~~base~~ revenues increased ~~$4.0 million, or 1.6%,~~ for the six months ended June 30, 2017 primarily due to the non-fuel base rate increase approved in the PUCT Final Order. The six months ended June 30, 2016 did not include approximately $17.2 million of retail non-fuel base revenues for the period from January 12, 2016 through June 30, 2016, which revenues were not recognized until the PUCT Final Order was approved in August 2016. The 1.7% growth in the average number of retail customers served also contributed to the increase in retail non-fuel base revenues. Weather had minimal impact in the six months ended June 30, 2017, when compared to the six months ended June 30, ~~2015. This includes a $4.0 million increase from sales~~2016 due to ~~residential customers and a $1.0 million increase from sales to small commercial and industrial customers, reflecting increases of 1.5% and 1.4%, respectively,~~milder weather in the ~~average number~~first quarter of ~~customers served, as well as~~2017 offsetting warmer weather in the second quarter of 2017.

Excluding the $17.2 million PUCT Final Order impact, for the six months ended June 30, 2017, retail non-fuel base revenues increased $6.5 million pre-tax, or 2.4%, compared to the six months ended June 30, 2016. ~~KWh~~This increase primarily includes (i) a $3.5 million increase in revenues from residential customers due to a 1.7% increase in kWh sales towhich were driven by a 1.5% increase in the average number of residential customers served, and (ii) a $2.1 million increase in revenues from small commercial and industrial customers ~~increased~~due to a 1.2% increase in kWh sales which were driven by ~~3.8% and 1.5%, respectively. Retail non-fuel revenues from large~~a 3.2% increase in the average number of small commercial and industrial customers ~~and sales to public authorities each decreased by $0.5 million, reflecting a 3.0% and 1.5% decrease~~served.

The increase in ~~kWh sales, respectively.~~

~~Retail~~reported retail non-fuel base revenues ~~increased $19.5 million, or 3.5%,~~ for the twelve months ended June 30, ~~2016, when~~2017 compared to the twelve months ended June 30, ~~2015.~~2016 was $64.0 million. Included in this increase is $58.1 million related to the effects of the PUCT Final Order received in August 2016. The annual impact of the PUCT Final Order was $40.9 million all of which was recorded in the twelve months ended June 30, 2017. Included in the PUCT Final Order annual impact was $17.2 million related to the period from January 12, 2016 through June 30, 2016 which was recognized in August 2016.

Excluding the PUCT Final Order impact, for the twelve months ended June 30, 2017, retail non-fuel base revenues increased by $5.9 million or 1.0% compared to the twelve months ended June 30, 2016. This ~~includes~~increase primarily included a ~~$15.0~~$3.7 million increase ~~from sales to residential customers and a $3.0 million increase from~~in sales to small commercial and industrial customers ~~reflecting increases~~and a $3.0 million increase in sales to residential customers due to an increase in kWh sales of ~~1.4%~~0.7% and 0.4%, respectively, which were driven by an increase in the average number of ~~customers served for both categories, as well as warmer weather experienced in the third quarter of 2015 and second quarter of 2016. KWh sales to residential customers and~~ small commercial and industrial and residential customers ~~increased by 6.3%~~served of 2.8% and ~~1.7%~~1.5%, respectively. ~~Retail non-fuel revenues~~Revenues from large commercial and industrial customers ~~increased $0.8~~decreased by $1.3 million, primarily due to ~~an interruptible rate adjustment for~~reduced demand by the steel manufacturing industry and a decrease in surcharges billed to a large customer. ~~Retail non-fuel~~

The three and six months ended June 30, 2017 included approximately $0.9 million and $1.7 million, respectively, of base revenues ~~from sales to public authorities increased $0.7 million, reflecting a 1.7% increase in kWh sales, due primarily to a 2.2% increase in average number of customers served and warmer weather experienced~~associated with the Four Corners surcharge which was established in the ~~third quarter~~PUCT Final Order. This surcharge represents $3.7 million of ~~2015~~annualized base revenue and ~~second quarter of 2016.~~in accordance with the PUCT Final Order, was discontinued in July 2017.

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) prior to July 1, 2016, fuel costs recovered in base rates in New Mexico. In New Mexico, effective July 1, 2016, with the implementation of the NMPRC Final Order, fuel and ~~with our sales for resale customer, the fuel adjustment clause allows us to recover under-recoveries or refund over-recoveries of current fuel~~purchased power costs ~~above the amount~~will no longer be recovered inthrough base rates, ~~with~~as it was historically, but will be completely recovered through the Fuel and Purchased Power Cost Adjustment Clause ("FPPCAC"). Fuel and purchased power costs are reconciled to actual costs on a ~~two-month lag.~~monthly basis and recovered or refunded to customers the second succeeding month. 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 and six months ended June 30, ~~2016,~~2017, we under-recovered our fuel costs by ~~$6.1~~$5.8 million and ~~$2.0~~over-recovered our fuel costs by $2.7 million, respectively. In the twelve months ended June 30, ~~2016,~~2017, we ~~over-recovered~~under-recovered our fuel costs by ~~$0.5~~$10.2 million. ~~In May 2014, we implemented a 6.9% increase in our fixed fuel factor~~Contributing to the under-recovery balance in Texas ~~which was based upon a formula that reflects increases in prices for natural gas. On April 15, 2015, we filed a request, which was assigned PUCT Docket No. 44633, to reduce our fixed~~is the recognition of $5.0 million resulting from the settlement of the Texas fuel ~~factor by approximately 24% to reflect an expected reduction in fuel expense. The over-recovered balance was below the materiality threshold. The reduction~~reconciliation in the ~~fixed fuel factor was effective on an interim basis on May 1, 2015, and was approved by the PUCT on May 20, 2015.~~second quarter of 2017. In ~~September 2014,~~ March ~~2015,~~2016 and March ~~2016, $7.9 million, $5.8~~2017, $1.6 million and ~~$1.6~~$1.4 million, respectively, were credited to customers through the applicable fuel adjustment clauses as the result of a reimbursement from the ~~DOE~~U.S. Department of Energy ("DOE") related to spent nuclear fuel storage. At June 30, ~~2016,~~2017, we had a net fuel ~~over-recovery~~under-recovery balance of ~~$2.0~~$8.2 million, including an under-recovery of $8.5 million in Texas, offset by an over-recovery of ~~$1.1~~$0.3 million in New ~~Mexico~~Mexico. On November 30, 2016, we filed a request to increase our Texas fixed fuel factor by approximately 28.8% to reflect increased fuel expenses primarily related to an increase in the price of natural gas used to generate power. The increase in our Texas fixed fuel factor was effective on an interim basis on January 1, 2017 and ~~$1.0 million in Texas and an under-recovery of $0.1 million for our FERC regulated customer.~~was approved by the PUCT on January 10, 2017.

Off-system sales. Off-system sales are wholesale sales into markets outside our service territory. Off-system sales are primarily made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations. We have shared 100% of margins on non-arbitrage sales (as defined by the ~~settlement)~~settlement in PUCT Docket No. 41852) and 50% of



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margins on arbitrage sales with our Texas customers since April 1, 2014. 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 $3.4~~increased $0.9 million, or ~~26.6%~~9.1%, for the three months ended June 30, ~~2016,~~2017, when compared to the three months ended June 30, ~~2015,~~2016, as a result of ~~lower~~higher average market prices for power, ~~and~~partially offset by a ~~12.9%~~16.8% decrease in kWh sales. ~~Retained margins from off-system sales for the three months ended June 30, 2016 were relatively unchanged when compared to the three months ended June 30, 2015.~~ Off-system sales revenues ~~decreased $9.2~~increased $3.7 million, or ~~30.6%~~17.5%, for the six months ended June 30, ~~2016,~~2017, when compared to the six months ended June 30, ~~2015,~~2016, as a result of ~~lower~~higher average market prices for power, ~~and~~partially offset by a ~~14.3%~~5.6% decrease in kWh sales. ~~Retained margins from off-system sales were relatively unchanged for the six months ended June 30, 2016, when compared to the six months ended June 30, 2015.~~ Off-system sales revenues decreased ~~$22.4~~$6.3 million, or ~~28.7%~~11.3%, for the twelve months ended June 30, ~~2016,~~2017, when compared to the twelve months ended June 30, ~~2015,~~2016, as a result of ~~lower average market prices for power and an 8.6%~~a 19.7% decrease in kWh sales. ~~Retained margins from off-system sales decreased $0.1 million, or 8.3%, for the twelve months ended June 30, 2016, compared to the twelve months ended June 30, 2015.~~



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Comparisons of kWh sales and operating revenues are shown below (in thousands):
					Increase (Decrease)
Quarter Ended June 30:	2017		2016		Amount			Percent
kWh sales:
Retail:
Residential	724,656		679,035		45,621			6.7	%
Commercial and industrial, small	647,377		633,714		13,663			2.2
Commercial and industrial, large	276,391		270,908		5,483			2.0
Sales to public authorities	423,374		405,277		18,097			4.5
Total retail sales	2,071,798		1,988,934		82,864			4.2
Wholesale:
Sales for resale	21,718		20,668		1,050			5.1
Off-system sales	374,861		450,801		(75,940		)	(16.8	)
Total wholesale sales	396,579		471,469		(74,890		)	(15.9	)
Total kWh sales	2,468,377		2,460,403		7,974			0.3
Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	75,027	$	62,679	$	12,348		19.7	%
Commercial and industrial, small	57,090		54,707		2,383			4.4
Commercial and industrial, large	10,443		9,489		954			10.1
Sales to public authorities	27,544		24,672		2,872			11.6
Total retail non-fuel base revenues (1)	170,104		151,547		18,557			12.2
Wholesale:
Sales for resale	859		826		33			4.0
Total non-fuel base revenues	170,963		152,373		18,590			12.2
Fuel revenues:
Recovered from customers during the period	57,148		26,219		30,929			—
Under collection of fuel (2)	5,822		6,096		(274		)	(4.5	)
New Mexico fuel in base rates (3)	—		16,602		(16,602		)	—
Total fuel revenues (4)	62,970		48,917		14,053			28.7
Off-system sales:
Fuel cost	8,833		8,398		435			5.2
Shared margins	1,089		852		237			27.8
Retained margins	403		213		190			89.2
Total off-system sales	10,325		9,463		862			9.1
Other (5)	7,585		7,112		473			6.7
Total operating revenues	$	251,843	$	217,865	$	33,978		15.6
Average number of retail customers (6):
Residential	367,686		361,812		5,874			1.6	%
Commercial and industrial, small	41,860		40,832		1,028			2.5
Commercial and industrial, large	48		49		(1		)	(2.0	)
Sales to public authorities	5,622		5,274		348			6.6
Total	415,216		407,967		7,249			1.8


(1)	2016 excludes $11.3 million of relate back revenues in Texas from April 2016 through June 2016 which were recorded in August 2016.


(2)	2017 includes $5.0 million related to the Palo Verde performance rewards, net.


(3)	Historically, fuel and purchased power costs in the New Mexico jurisdiction were recorded through base rates and a FPPCAC that accounts for the changes in the costs of fuel relative to the amount included in base rates. Effective July 1, 2016, with the implementation of the NMPRC Final Order, these costs are no longer recovered through base rates but are recovered through the FPPCAC.


(4)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $2.2 million and $1.9 million in 2017 and 2016, respectively.


(5)	Represents revenues with no related kWh sales.


(6)	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)
Quarter Ended June 30: 2016 2015 Amount Percent
kWh sales:
Retail:
Residential 679,035
640,940
38,095
5.9 %
Commercial and industrial, small 633,714
626,968
6,746
1.1
Commercial and industrial, large 270,908
278,822
(7,914 ) (2.8 )
Sales to public authorities 405,277
419,882
(14,605 ) (3.5 )
Total retail sales 1,988,934
1,966,612
22,322
1.1
Wholesale:
Sales for resale 20,668
20,504
164
0.8
Off-system sales 450,801
517,752
(66,951 ) (12.9 )
Total wholesale sales 471,469
538,256
(66,787 ) (12.4 )
Total kWh sales 2,460,403
2,504,868
(44,465 ) (1.8 )
Operating revenues:
Non-fuel base revenues:
Retail:
Residential $ 62,679
$ 59,422
$ 3,257
5.5 %
Commercial and industrial, small 54,707
53,864
843
1.6
Commercial and industrial, large 9,489
9,879
(390 ) (3.9 )
Sales to public authorities 24,672
25,317
(645 ) (2.5 )
Total retail non-fuel base revenues 151,547
148,482
3,065
2.1
Wholesale:
Sales for resale 826
689
137
19.9
Total non-fuel base revenues 152,373
149,171
3,202
2.1
Fuel revenues:
Recovered from customers during the period 26,219
28,949
(2,730 ) (9.4 )
Under collection of fuel 6,096
4,855
1,241
25.6
New Mexico fuel in base rates 16,602
16,437
165
1.0
Total fuel revenues (1) 48,917
50,241
(1,324 ) (2.6 )
Off-system sales:
Fuel cost 8,398
10,419
(2,021 ) (19.4 )
Shared margins 852
2,316
(1,464 ) (63.2 )
Retained margins 213
164
49
29.9
Total off-system sales 9,463
12,899
(3,436 ) (26.6 )
Other (2) 7,112
7,197
(85 ) (1.2 )
Total operating revenues $ 217,865
$ 219,508
$ (1,643 ) (0.7 )
Average number of retail customers (3):
Residential 361,812
356,495
5,317
1.5 %
Commercial and industrial, small 40,832
40,213
619
1.5
Commercial and industrial, large 49
50
(1 ) (2.0 )
Sales to public authorities 5,274
5,273
1
—
Total 407,967
402,031
5,936
1.5



Comparisons of kWh sales and operating revenues are shown below (in thousands):
						Increase (Decrease)
Six Months Ended June 30:	2017			2016		Amount			Percent
kWh sales:
Retail:
Residential	1,269,784			1,248,120		21,664			1.7	%
Commercial and industrial, small	1,147,967			1,133,940		14,027			1.2
Commercial and industrial, large	529,389			515,834		13,555			2.6
Sales to public authorities	758,937			751,512		7,425			1.0
Total retail sales	3,706,077			3,649,406		56,671			1.6
Wholesale:
Sales for resale	32,639			32,509		130			0.4
Off-system sales	971,623			1,029,474		(57,851		)	(5.6	)
Total wholesale sales	1,004,262			1,061,983		(57,721		)	(5.4	)
Total kWh sales	4,710,339			4,711,389		(1,050		)	—
Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	126,337		$	110,422	$	15,915		14.4	%
Commercial and industrial, small	90,875			86,847		4,028			4.6
Commercial and industrial, large	18,343			17,582		761			4.3
Sales to public authorities	45,094			42,072		3,022			7.2
Total retail non-fuel base revenues (1)	280,649			256,923		23,726			9.2
Wholesale:
Sales for resale	1,322			1,195		127			10.6
Total non-fuel base revenues	281,971			258,118		23,853			9.2
Fuel revenues:
Recovered from customers during the period	104,768			48,753		56,015			—
Under (over) collection of fuel (2) (3)	(2,708		)	1,993		(4,701		)	—
New Mexico fuel in base rates (4)	—			32,828		(32,828		)	—
Total fuel revenues (5)	102,060			83,574		18,486			22.1
Off-system sales:
Fuel cost	20,361			16,890		3,471			20.6
Shared margins	3,302			3,407		(105		)	(3.1	)
Retained margins	862			573		289			50.4
Total off-system sales	24,525			20,870		3,655			17.5
Other (6)	14,622			13,112		1,510			11.5
Total operating revenues	$	423,178		$	375,674	$	47,504		12.6
Average number of retail customers (7):
Residential	366,497			360,929		5,568			1.5	%
Commercial and industrial, small	41,968			40,684		1,284			3.2
Commercial and industrial, large	49			49		—			—
Sales to public authorities	5,528			5,324		204			3.8
Total	414,042			406,986		7,056			1.7


(1)	2016 excludes $17.2 million of relate back revenues in Texas from January 12, 2016 through June 30, 2016 which were recorded in August 2016.


(2)	Includes the portion of DOE refunds related to spent fuel storage of $1.4 million and $1.6 million in 2017 and 2016, respectively, that were credited to customers through the applicable fuel adjustment clauses.


(3)	2017 includes $5.0 million related to the Palo Verde performance rewards, net.


(4)	Historically, fuel and purchased power costs in the New Mexico jurisdiction were recorded through base rates and a FPPCAC that accounts for the changes in the costs of fuel relative to the amount included in base rates. Effective July 1, 2016, with the implementation of the NMPRC Final Order, these costs are no longer recovered through base rates but are recovered through the FPPCAC.


(5)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of ~~$1.9~~$5.0 million and $4.0 million in 2017 and 2016, ~~and 2015.~~respectively.


~~(2)~~(6)	Represents revenues with no related kWh sales.


~~(3)~~(7)	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):	Comparisons of kWh sales and operating revenues are shown below (in thousands):										Comparisons of kWh sales and operating revenues are shown below (in thousands):
						Increase (Decrease)										Increase (Decrease)
Six Months Ended June 30:	2016		2015			Amount			Percent
Twelve Months Ended June 30:											2017		2016			Amount			Percent
kWh sales:
Retail:
Residential	1,248,120		1,202,593			45,527			3.8	%	2,827,453		2,816,665			10,788			0.4	%
Commercial and industrial, small	1,133,940		1,117,034			16,906			1.5		2,417,474		2,401,420			16,054			0.7
Commercial and industrial, large	515,834		531,942			(16,108		)	(3.0	)	1,044,300		1,046,554			(2,254		)	(0.2	)
Sales to public authorities	751,512		762,975			(11,463		)	(1.5	)	1,579,935		1,574,105			5,830			0.4
Total retail sales	3,649,406		3,614,544			34,862			1.0		7,869,162		7,838,744			30,418			0.4
Wholesale:
Sales for resale	32,509		32,449			60			0.2		62,216		63,407			(1,191		)	(1.9	)
Off-system sales	1,029,474		1,201,281			(171,807		)	(14.3	)	1,869,657		2,329,140			(459,483		)	(19.7	)
Total wholesale sales	1,061,983		1,233,730			(171,747		)	(13.9	)	1,931,873		2,392,547			(460,674		)	(19.3	)
Total kWh sales	4,711,389		4,848,274			(136,885		)	(2.8	)	9,801,035		10,231,291			(430,256		)	(4.2	)
Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	110,422	$	106,362		$	4,060		3.8	%	$	294,689	$	250,325		$	44,364		17.7	%
Commercial and industrial, small	86,847		85,834			1,013			1.2		198,970		188,449			10,521			5.6
Commercial and industrial, large	17,582		18,128			(546		)	(3.0	)	39,831		39,865			(34		)	(0.1	)
Sales to public authorities	42,072		42,575			(503		)	(1.2	)	99,903		90,741			9,162			10.1
Total retail non-fuel base revenues(1)	256,923		252,899			4,024			1.6		633,393		569,380			64,013			11.2
Wholesale:
Sales for resale	1,195		1,129			66			5.8		2,534		2,521			13			0.5
Total non-fuel base revenues	258,118		254,028			4,090			1.6		635,927		571,901			64,026			11.2
Fuel revenues:
Recovered from customers during the period	48,753		63,371			(14,618		)	(23.1	)	204,412		113,147			91,265			80.7
Under (over) collection of fuel (1)	1,993		(10,832		)	12,825			—
Under (over) collection of fuel (2) (3)											10,192		(517		)	10,709			—
New Mexico fuel in base rates(4)	32,828		32,550			278			0.9		451		72,407			(71,956		)	(99.4	)
Total fuel revenues ~~(2)~~(5)	83,574		85,089			(1,515		)	(1.8	)	215,055		185,037			30,018			16.2
Off-system sales:
Fuel cost	16,890		23,284			(6,394		)	(27.5	)	42,404		46,012			(3,608		)	(7.8	)
Shared margins	3,407		6,252			(2,845		)	(45.5	)	5,527		8,203			(2,676		)	(32.6	)
Retained margins	573		520			53			10.2		1,426		1,415			11			0.8
Total off-system sales	20,870		30,056			(9,186		)	(30.6	)	49,357		55,630			(6,273		)	(11.3	)
Other (3)	13,112		14,081			(969		)	(6.9	)
Other (6) (7)											34,101		29,721			4,380			14.7
Total operating revenues	$	375,674	$	383,254		$	(7,580	)	(2.0	)	$	934,440	$	842,289		$	92,151		10.9
Average number of retail customers (4):
Average number of retail customers (8):
Residential	360,929		355,625			5,304			1.5	%	364,922		359,621			5,301			1.5	%
Commercial and industrial, small	40,684		40,127			557			1.4		41,656		40,529			1,127			2.8
Commercial and industrial, large	49		50			(1		)	(2.0	)	49		49			—			—
Sales to public authorities	5,324		5,245			79			1.5		5,405		5,289			116			2.2
Total	406,986		401,047			5,939			1.5		412,032		405,488			6,544			1.6


(1)	Included in the increase from 2016 to 2017 is $58.1 million related to the effects of the PUCT Final Order received in August 2016. See page 33 for a complete discussion.


(2)	Includes the portion of DOE refunds related to spent fuel storage of $1.4 million and $1.6 million in 2017 and ~~$5.8 million in~~ 2016, ~~and 2015,~~ respectively, that were credited to customers through the applicable fuel adjustment clauses.


~~(2)~~(3)	2017 includes $5.0 million related to the Palo Verde performance rewards, net.


(4)	Historically, fuel and purchased power costs in the New Mexico jurisdiction were recorded through base rates and a FPPCAC that accounts for the changes in the costs of fuel relative to the amount included in base rates. Effective July 1, 2016, with the implementation of the NMPRC Final Order, these costs are no longer recovered through base rates but are recovered through the FPPCAC.


(5)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of ~~$4.0~~$9.7 million and ~~$5.0~~$8.7 million in ~~2016~~2017 and ~~2015,~~2016, respectively.


~~(3)~~(6)	Represents revenues with no related kWh sales.


~~(4)~~(7)	Includes an Energy Efficiency Bonus of $0.8 million and $1.3 million in 2017 and 2016, respectively.


(8)	The number of retail customers presented is based on the number of service locations.



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Table of Contents

Comparisons of kWh sales and operating revenues are shown below (in thousands):
Increase (Decrease)
Twelve Months Ended June 30: 2016 2015 Amount Percent
kWh sales:
Retail:
Residential 2,816,665
2,650,095
166,570
6.3 %
Commercial and industrial, small 2,401,420
2,360,331
41,089
1.7
Commercial and industrial, large 1,046,554
1,077,752
(31,198 ) (2.9 )
Sales to public authorities 1,574,105
1,547,801
26,304
1.7
Total retail sales 7,838,744
7,635,979
202,765
2.7
Wholesale:
Sales for resale 63,407
61,458
1,949
3.2
Off-system sales 2,329,140
2,548,183
(219,043 ) (8.6 )
Total wholesale sales 2,392,547
2,609,641
(217,094 ) (8.3 )
Total kWh sales 10,231,291
10,245,620
(14,329 ) (0.1 )
Operating revenues:
Non-fuel base revenues:
Retail:
Residential $ 250,325
$ 235,311
$ 15,014
6.4 %
Commercial and industrial, small 188,449
185,426
3,023
1.6
Commercial and industrial, large 39,865
39,076
789
2.0
Sales to public authorities 90,741
90,070
671
0.7
Total retail non-fuel base revenues 569,380
549,883
19,497
3.5
Wholesale:
Sales for resale 2,521
2,278
243
10.7
Total non-fuel base revenues 571,901
552,161
19,740
3.6
Fuel revenues:
Recovered from customers during the period 113,147
152,721
(39,574 ) (25.9 )
Over collection of fuel (1) (517 ) (21,081 ) 20,564
97.5
New Mexico fuel in base rates 72,407
70,937
1,470
2.1
Total fuel revenues (2) 185,037
202,577
(17,540 ) (8.7 )
Off-system sales:
Fuel cost 46,012
58,537
(12,525 ) (21.4 )
Shared margins 8,203
17,980
(9,777 ) (54.4 )
Retained margins 1,415
1,543
(128 ) (8.3 )
Total off-system sales 55,630
78,060
(22,430 ) (28.7 )
Other (3) (4) 29,721
30,664
(943 ) (3.1 )
Total operating revenues $ 842,289
$ 863,462
$ (21,173 ) (2.5 )
Average number of retail customers (5):
Residential 359,621
354,497
5,124
1.4 %
Commercial and industrial, small 40,529
39,988
541
1.4
Commercial and industrial, large 49
49
—
—
Sales to public authorities 5,289
5,173
116
2.2
Total 405,488
399,707
5,781
1.4


~~(1)~~	2016 includes the portion of a DOE refund related to spent fuel storage of $1.6 million that was credited to customers through the applicable fuel adjustment clause. 2015 includes the portion of two DOE refunds related to spent fuel which totaled $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 $8.7 million and $12.0 million in 2016 and 2015, respectively.~~


~~(3)~~	~~Includes an Energy Efficiency Bonus of $1.3 million and $2.0 million in 2016 and 2015, respectively.~~


~~(4)~~	~~Represents revenues with no related kWh sales.~~


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



	38

~~Table of Contents~~

Energy expenses

Our sources of energy include electricity generated from our nuclear and natural gas ~~and coal~~ generating plants and purchased power. After adding the new natural gas generating units ~~(MPS~~MPS Units 1 ~~& 2)~~and 2 in March 2015 and ~~(MPS Unit 3)~~MPS Units 3 and 4 in May 2016 and September 2016, respectively, into the Company's system generation resources, Palo Verde represents approximately 30% of our net dependable generating capacity and approximately ~~51%~~52%, ~~58%,~~61% and ~~54%~~59% of our Company-generated energy for the three, six and twelve months ended June 30, ~~2016,~~2017, 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 $4.8~~increased $9.1 million, or ~~7.8%~~16.1%, for the three months ended June 30, ~~2016,~~2017, when compared to the three months ended June 30, ~~2015,~~2016, primarily due to (i) ~~decreased~~increased natural gas costs of ~~$6.0~~$9.2 million due to a ~~17.4% decrease~~28.5% increase in the average ~~price~~cost of ~~natural gas,~~MWhs generated and (ii) ~~decreased coal costs of $0.7 million due to decreased generation. The decrease in energy expenses was partially offset by~~ increased total purchased power costs of ~~$1.9~~$3.1 million due to a ~~30.3%~~21.9% increase in the MWhs purchased. These increases in energy expenses were partially offset by decreased coal costs of $2.9 million as a result of the sale of our interest in Four Corners, a coal-fired generation station, on July 6, 2016.


	Three Months Ended June 30,										Three Months Ended June 30,
	2016					2015					2017						2016
Fuel Type	Cost		MWh	Cost per MWh		Cost		MWh	Cost per MWh		Cost			MWh	Cost per MWh		Cost		MWh	Cost per MWh
	(in thousands)					(in thousands)					(in thousands)						(in thousands)
Natural gas	$	29,387	1,032,439	$	28.46	$	35,349	1,025,980	$	34.45	$	38,602		1,055,911	$	36.56	$	29,387	1,032,439	$	28.46
Coal	2,893		82,143	35.22		3,600		173,427	20.76		37		(a)	—	—		2,893		82,143	35.22
Nuclear	10,863		1,165,459	9.32		10,864		1,203,902	9.02		10,534			1,151,530	9.15		10,863		1,165,459	9.32
Company-generated	43,143		2,280,041	18.92		49,813		2,403,309	20.73
Total											49,173			2,207,441	22.28		43,143		2,280,041	18.92
Purchased power:
Photovoltaic	7,187		88,765	80.97		7,126		87,655	81.30		7,479			91,921	81.36		7,187		88,765	80.97
Other	6,423		239,329	26.84		4,616		164,194	28.11		9,242			307,904	30.02		6,423		239,329	26.84
Total purchased power	13,610		328,094	41.48		11,742		251,849	46.62		16,721			399,825	41.82		13,610		328,094	41.48
Total energy	$	56,753	2,608,135	21.76		$	61,555	2,655,158	23.18		$	65,894		2,607,266	25.27		$	56,753	2,608,135	21.76

_______________

(a) The sale of our interest in Four Corners, a coal-fired generation station, closed on July 6, 2016. The cost reported in 2017 represents the

amortization of deferred coal mine reclamation obligations.

Energy expenses ~~decreased $9.7~~increased $15.5 million, or ~~8.8%~~15.3%, for the six months ended June 30, ~~2016,~~2017, when compared to the six months ended June 30, ~~2015,~~2016, primarily due to (i) ~~decreased~~increased natural gas costs of ~~$13.6~~$14.2 million due to a ~~20.0% decrease~~31.5% increase in the average ~~price~~cost of ~~natural gas,~~MWhs generated and (ii) ~~decreased coal~~increased total purchased power costs of ~~$1.2~~$7.1 million due to ~~decreased generation.~~a 37.8% increase in MWhs purchased. These ~~decreases~~increases in energy expenses were partially offset by ~~an increase~~decreased coal costs of $5.3 million as a result of the sale of our interest in ~~nuclear fuel expenses related to~~Four Corners, a ~~$4.6 million reduction in the DOE refund in 2016 compared to the same period in 2015.~~coal-fired generation station, on July 6, 2016.



	38

Table of Contents


	Six Months Ended June 30,												Six Months Ended June 30,
	2016						2015						2017						2016
Fuel Type	Cost			MWh	Cost per MWh		Cost			MWh	Cost per MWh		Cost			MWh	Cost per MWh		Cost			MWh	Cost per MWh
	(in thousands)						(in thousands)						(in thousands)						(in thousands)
Natural gas	$	50,523		1,669,869	$	30.26	$	64,097		1,694,555	$	37.83	$	64,708		1,626,736	$	39.78	$	50,523		1,669,869	$	30.26
Coal	5,528			163,149	33.88		6,716			310,645	21.62		245		(a)	—	—		5,528			163,149	33.88
Nuclear	21,411		(a)	2,545,956	9.11		16,729		(a)	2,566,096	9.01		20,826		(b)	2,515,057	8.90		21,411		(b)	2,545,956	9.11
Company-generated	77,462			4,378,974	18.10		87,542			4,571,296	20.55
Total													85,779			4,141,793	21.09		77,462			4,378,974	18.10
Purchased power:
Photovoltaic	12,695			156,529	81.10		11,929			146,714	81.31		12,778			156,656	81.57		12,695			156,529	81.10
Other	10,561			444,486	23.76		10,988			405,907	27.07		17,616			671,279	26.24		10,561			444,486	23.76
Total purchased power	23,256			601,015	38.69		22,917			552,621	41.47		30,394			827,935	36.71		23,256			601,015	38.69
Total energy	$	100,718		4,979,989	20.58		$	110,459		5,123,917	22.81		$	116,173		4,969,728	23.69		$	100,718		4,979,989	20.58

_______________

(a) ~~Costs~~The sale of our interest in Four Corners, coal-fired generation station, closed on July 6, 2016. The cost reported in 2017 represents the

amortization of deferred coal mine reclamation obligations.

(b) Cost includes a DOE refund related to spent fuel storage of ~~$1.8~~$1.6 million and ~~$6.4~~$1.8 million recorded in March 2017 and 2016, respectively.

Cost per MWh excludes these refunds.

Energy expenses increased $16.7 million, or 7.2%, for the twelve months ended June 30, 2017, when compared to the twelve months ended June 30, 2016, primarily due to (i) increased natural gas costs of $17.2 million due to a 22.7% increase in the average cost of MWhs generated and (ii) increased total purchased power costs of $13.0 million due to a 23.6% increase in MWhs purchased. These increases in energy expenses were partially offset by (i) decreased coal costs of $11.9 million as a result of the sale of our interest in Four Corners, a coal-fired generation station, on July 6, 2016 and ~~2015,~~(ii) decreased nuclear costs of $1.6 million due to a 3.0% decrease in the average cost of MWhs generated and a 1.0% decrease in the MWhs generated with nuclear fuel.



	Twelve Months Ended June 30,
	2017						2016
Fuel Type	Cost			MWh	Cost per MWh		Cost			MWh	Cost per MWh
	(in thousands)						(in thousands)
Natural gas	$	137,991		3,507,771	$	39.34	$	120,787		3,765,973	$	32.07
Coal	871		(a)	12,109	71.93		12,725			510,248	24.94
Nuclear	43,193		(b)	5,062,945	8.84		44,808		(b)	5,116,546	9.11
Total	182,055			8,582,825	21.39		178,320			9,392,767	19.17
Purchased power:
Photovoltaic	23,496			289,927	81.04		23,261			287,056	81.03
Other	43,369			1,489,244	29.12		30,623			1,152,284	26.58
Total purchased power	66,865			1,779,171	37.58		53,884			1,439,340	37.44
Total energy	$	248,920		10,361,996	24.17		$	232,204		10,832,107	21.61

_____________

(a) The sale of our interest in Four Corners, coal-fired generation station, closed on July 6, 2016. The cost reported in 2017 represents the

amortization of deferred coal mine reclamation obligations.

(b) Cost includes a DOE refund related to spent fuel storage of $1.6 million and $1.8 million recorded in March 2017 and 2016, respectively. Cost per MWh excludes these refunds.

Other operations expense

Other operations expense increased $3.0 million, or 5.3%, for the three months ended June 30, 2017, compared to the three months ended June 30, 2016 primarily due to a (i) $3.0 million increase in A&G operating expenses primarily due to timing of the accrual of employee incentive compensation, an annual merit increase and increased regulatory expenses, and (ii) a $2.4 million increase in operating expenses at Palo Verde primarily due to a $1.6 million increase in the A&G load true up in 2017 compared



	39

Table of Contents

~~Energy expenses decreased $36.8~~to 2016. These increases were partially offset by a $2.8 million decrease due to the sale of the Company's interest in Units 4 and 5 of Four Corners in July 2016.

Other operations expense increased $0.8 million, or ~~13.7%~~0.7%, for the six months ended June 30, 2017, compared to the six months ended June 30, 2016 primarily due to a (i) $3.7 million increase in A&G operating expenses primarily due to timing of the accrual of employee incentive compensation, an annual merit increase and an increase in pension and benefit costs due to an increase in medical claims paid and other employee benefit costs, and (ii) a $2.2 million increase in operating expenses at Palo Verde primarily due to a $1.6 million increase in the A&G load true up in 2017 compared to 2016. These increases were partially offset by a $5.5 million decrease due to the sale of the Company's interest in Units 4 and 5 of Four Corners in July 2016.

Other operations expense decreased $2.1 million, or 0.9%, for the twelve months ended June 30, ~~2016, when~~2017, compared to the twelve months ended June 30, ~~2015,~~2016 primarily due to ~~decreased natural gas costs of $50.0~~(i) a $7.8 million decrease due to ~~a 27.3%~~the sale of the Company's interest in Units 4 and 5 of Four Corners in July 2016. This decrease ~~in the average price of natural gas. The decrease in energy expenses~~ was partially offset by (i) a ~~$13.1~~$3.2 million ~~reduction~~increase in ~~DOE refund~~A&G operating expenses primarily due to timing of the accrual of employee incentive compensation, an annual merit increase and increased regulatory expenses, (ii) a $1.0 million increase in operating expenses at Palo Verde primarily due to a $1.6 million increase in the A&G load true up in 2017 compared to 2016, and (iii) a $0.8 million increase in routine operating expenses at MPS.

Maintenance expense

Maintenance expense remained relatively unchanged for the three months ended June 30, 2017, compared to the three months ended June 30, 2016.

Maintenance expense increased $3.5 million, or 9.1%, for the six months ended June 30, 2017, compared to the six months ended June 30, 2016 primarily due to (i) increased maintenance expense of $8.7 million for outages at Newman Units 1, 3, 4 & 5, and (ii) increased ~~purchased photovoltaic power costs~~routine maintenance of ~~$1.4~~$2.4 million at MPS, Rio Grande and Newman. These increases were partially offset by (i) $5.5 million due to the sale of the Company's interest in Units 4 and 5 of Four Corners in July 2016, (ii) $1.3 million decrease in maintenance expense for an outage at Rio Grande Unit 7 in 2016 with no comparable activity in 2017, and (iii) a ~~7.7% increase~~$1.0 million decrease in ~~MWhs purchased~~maintenance expenses at Palo Verde.

Maintenance expense increased $2.5 million, or 3.6%, for the twelve months ended June 30, ~~2016~~2017 compared to the twelve months ended June 30, ~~2015.~~2017 primarily due to (i) increased maintenance expense of $8.9 million for outages at Newman Units 1, 3, 4 & 5, and (ii) increased routine maintenance of $2.3 million at MPS and Rio Grande. These increases were partially offset by (i) $7.4 million due to the sale of the Company's interest in Units 4 and 5 of Four Corners in July 2016, (ii) a $1.3 million decrease in maintenance expenses at Palo Verde, and (iii) a $1.1 million decrease in maintenance expense for an outage at Rio Grande Unit 7 in 2016 with no comparable activity in 2017.

Twelve Months Ended June 30,
2016 2015
Fuel Type Cost MWh
Cost per
MWh
Cost MWh
Cost per
MWh
(in thousands) (in thousands)
Natural gas $ 120,787
3,765,973
$ 32.07
$ 170,807
3,873,476
$ 44.10
Coal 12,725
510,248
24.94
13,706
634,673
21.60
Nuclear 44,808
(a) 5,116,546
9.11
32,776
(b) 5,116,789
9.33
Total 178,320
9,392,767
19.17
217,289
9,624,938
24.13
Purchased power:
Photovoltaic 23,261
287,056
81.03
21,880
266,509
82.10
Other 30,623
1,152,284
26.58
29,798
914,970
32.57
Total purchased power 53,884
1,439,340
37.44
51,678
1,181,479
43.74
Total energy $ 232,204
10,832,107
21.61
$ 268,967
10,806,417
26.27

~~_____________~~Depreciation and amortization expense

~~(a) Costs includes a DOE refund related~~Depreciation and amortization expense decreased $1.4 million, or 5.7%, $2.7 million, or 5.8%, and $10.7 million, or 11.6%, for the three, six, and twelve months ended June 30, 2017, respectively, compared to ~~spent fuel storage~~the three, six, and twelve months ended June 30, 2016, primarily due to (i) reductions of ~~$1.8~~approximately $2.9 million, ~~recorded~~$5.8 million, and $16.6 million, respectively, resulting from changes in depreciation rates as approved in the ~~first quarter of 2016. Cost per MWh excludes this refund.~~

~~(b) Costs includes DOE refunds related to spent fuel storage of $6.4 million and $8.5 million recorded in the first quarter of 2015~~PUCT Final Order and in the ~~third quarter~~NMPRC Final Order, and (ii) the sale of ~~2014,~~the Company's interest in Units 4 and 5 of the Four Corners Power Plant. These decreases were partially offset by increases in plant, including MPS Units 3 and 4, which were placed in service in May and September 2016, respectively. ~~Cost per MWh excludes these refunds.~~

~~Other operations expense~~Taxes other than income taxes

~~Other operations expense decreased $0.8~~Taxes other than income taxes increased $1.9 million, or ~~1.5%~~12.7%, for the three months ended June 30, 2017 compared to the three months ended 2016, primarily due to increased revenue related taxes and increased property valuations in Texas as a result of MPS Units 3 and 4 being placed in service in 2016.

Taxes other than income taxes increased $2.9 million, or 9.5%, and $4.1 million, or 6.4%, for the six and twelve months ended June 30, 2017, respectively, compared to the six and twelve months ended June 30, 2016, primarily due to increased revenue related taxes and increased property valuations in Texas as a result of MPS Units 3 and 4 being placed in service in 2016. These increases were partially offset by decreased property taxes in New Mexico due to decreased property valuations.

Other income (deductions)

Other income (deductions) increased $2.0 million, or 41.0%, for the three months ended June 30, 2017 compared to the three months ended June 30, ~~2015, primarily due to decreased administrative and general payroll costs and employee incentive compensation.~~

~~Other operations expense increased $1.9 million, or 1.7% for the six months ended June 30,~~ 2016, ~~compared to the six months ended June 30, 2015,~~ primarily due to increased ~~regulatory expense of $0.9 million related to the 2015 New Mexico rate case costs being expensed on a current basis~~investment and ~~operation expenses at Palo Verde generating plant of $0.8 million.~~

~~Other operations expense increased $9.2 million, or 3.9% for the twelve months ended June 30, 2016, compared to the twelve months ended June 30, 2015, primarily~~interest income due to (i) increased administrative and general payroll costs and employee incentive compensation of $3.5 million, (ii) increased medical claims paid of $3.1 million, (iii) increased operation expenses at Palo Verde generation plant of $1.7 million, and (iv) increased regulatory expenses of $1.6 million related to the 2015 New Mexico rate case costs being expensed on a current basis. These increases were partially offset by a $2.2 million decreasehigher realized gains in ~~benefit costs due to a change in actuarial assumptions used to calculate~~ our ~~employee pension plan.~~

~~Maintenance expense~~

Maintenance expense increased $0.6 million, or 2.9% for the three months ended June 30, 2016, compared to the three months ended June 30, 2015, primarily due to an increase in the level of maintenance at Rio Grande, Four Corners and Palo Verde generating plants partially offset by a decrease in maintenance at Newman generating plant.

Maintenance expense increased $2.5 million, or 7.1% for the six months ended June 30, 2016, compared to the six months ended June 30, 2015, primarily due to an increase in the level of maintenance at Four Corners and Rio Grande generating plants partially offset by a decrease in maintenance at Newman generating plant.

Maintenance expense decreased $3.1 million, or 4.3% for the twelve months ended June 30, 2016, compared to the twelve months ended June 30, 2015, primarily due to (i) a decrease in the level of maintenance at Newman and Palo Verde generating plants; and (ii) a decrease in transmission and distribution maintenance expenses. These decreases were partially offset by an increase in maintenance at Four Corners generating plant.



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decommissioning trust funds in 2017. This increase was partially offset by decreased allowance for equity funds used during construction ("AEFUDC") resulting from lower average balances of CWIP and a reduction in the AEFUDC rate.

~~Depreciation and amortization expense~~

~~Depreciation and amortization expense~~Other income (deductions) increased $0.7 million, or ~~3.1%~~7.0%, for the three months ended June 30, 2016, compared to the three months ended June 30, 2015, primarily due to an increase in depreciable plant balances, including MPS Unit 3, which was placed in service in May 2016, partially offset by an increase in the estimated useful lives of certain intangible software assets effective July 2015.

Depreciation and amortization expense increased $2.4 million or 5.5% and $5.9 million or 6.8% for the six and twelve months ended June 30, 2016, respectively, compared to the six and twelve months ended June 30, 2015 due to an increase in depreciable plant balances, primarily due to MPS Units 1 & 2 and the EOC, which were placed in service in March 2015, partially offset by an increase in the estimated useful lives of certain intangible software assets effective July 2015.

~~Taxes other than income taxes~~

~~Taxes other than income taxes for the three and~~ six months ended June 30, ~~2016 were comparable~~2017 compared to the ~~three and~~ six months ended June 30, ~~2015. Taxes other than income taxes increased $2.9 million, or 4.6% for the twelve months ended June 30,~~ 2016, ~~compared to the twelve months ended June 30, 2015, primarily due to an increase in plant balances.~~

~~Other income (deductions)~~

~~Other income (deductions) increased $2.1 million, or 71.6% for the three months ended June 30, 2016, compared to the three months ended June 30, 2015,~~ primarily due to increased investment and interest income due to higher realized gains in our decommissioning trust funds in ~~2016 and decreased miscellaneous deductions due to reduced donations,~~2017. This increase was partially offset by ~~decreased allowance for equity funds used during construction ("AEFUDC") resulting from a reduction in the AEFUDC accrual rate net of AEFUDC earned from higher average balances of CWIP.~~

Other income (deductions) decreased $1.7 million, or 13.9% for the six months ended June 30,2016, compared to the six months ended June 30, 2015, primarily due to decreased AEFUDC resulting from a reduction in the AEFUDC accrual rate and lower average balances of CWIP, partially offset by decreased miscellaneous deductions due to reduced donations.

~~Other income (deductions) decreased $2.5 million, or 9.3% for the twelve months ended June 30, 2016, compared to the twelve months ended June 30, 2015, primarily due to~~(i) decreased AEFUDC resulting from lower ~~averages~~average balances of CWIP and a reduction in the AEFUDC ~~accrual~~ rate and (ii) gain on sale of land in 2016 with no comparable activity in 2017.

Other income (deductions) decreased $4.8 million, or 19.7%, for the twelve months ended June 30, 2017 compared to the twelve months ended June 30, 2016, primarily due to (i) decreased AEFUDC resulting from lower average balances of CWIP and a reduction in the AEFUDC rate and (ii) decreased miscellaneous other income due to net gains recognized on sale of assets in 2016 with no comparable activity in 2017. These decreases were partially offset by ~~(i)~~ increased investment and interest income due to ~~higher~~lower realized ~~gains~~losses in our decommissioning trust ~~funds in 2016 and (ii) decreased miscellaneous deductions due to reduced donations.~~funds.

Interest charges (credits)

Interest charges (credits) increased by ~~$1.7~~$1.2 million, or ~~12.3%~~7.4%, for the three months ended June 30, ~~2016,~~2017, compared to the three months ended June 30, ~~2015,~~2016, primarily due to ~~increased~~(i) decreased allowance for borrowed funds used during construction ("ABFUDC") as a result of lower average balances of CWIP and a reduction in the ABFUDC accrual rate and (ii) an increase in interest ~~expense~~ on ~~the $150 million of 5.00% Senior Notes due 2044 issued in March 2016.~~short-term borrowing for working capital purposes.

Interest charges (credits) increased by ~~$3.3~~$3.6 million and $8.0 million, or ~~12.1%~~12.0% and 13.6%, for the six and twelve months ended June 30, ~~2016,~~2017, respectively, compared to the six and twelve months ended June 30, ~~2015,~~2016, primarily due to (i) increased interest expense on the $150 million of 5.00% Senior Notes due 2044 issued in March 2016, ~~and (ii) decreased allowance for ABFUDC as a result of a reduction in ABFUDC accrual rate and lower average balances of CWIP.~~

Interest charges (credits) increased by $8.2 million, or 16.4%, for the twelve months ended June 30, 2016, compared to the twelve months ended June 30, 2015, primarily due to (i) interest expense on the $150 million of 5.00% Senior Notes due 2044 issued in December 2014 and March 2016 and (ii) decreased allowance for ABFUDC as a result of lower average balances of CWIP and a reduction in the ABFUDC accrual ~~rate.~~rate and (iii) an increase in interest on short-term borrowing for working capital purposes.

Income tax expense (benefit)

Income tax expense increased ~~$1.9~~$8.3 million, or ~~20.5%~~72.8%, $9.2 million, or 111.0%, and $30.4 million, or 93.1%, for the three, six and twelve months ended June 30, ~~2016,~~2017, respectively. The increases compared to the three, ~~months ended June 30, 2015, primarily due to an increase in pre-tax income~~six and a decrease in AEFUDC. Income tax expense decreased $2.2 million, or 21.0% for the six months ended June 30, 2016, compared to the six months ended June 30, 2015, primarily due to a decrease in pre-tax income, offset by a decrease in AEFUDC. Income tax expense decreased $2.6 million, or 7.5% for the twelve months ended June 30, 2016, ~~compared to the twelve months ended June 30, 2015,~~are primarily due to ~~a decrease~~increases in pre-tax ~~income.~~



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~~Table~~income and increases in state income taxes due to normalization as discussed in Note F of ~~Contents~~

the Notes to Financial Statements.

New Accounting Standards

~~In April 2015, the~~See Notes to Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("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. In August 2015, the FASB issued ASU 2015-15, Interest - Imputation of Interest (Subtopic 835-30), to provide further clarification to ASU 2015-03 as it relates to the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements. We implemented ASU 2015-03 and ASU 2015-15 in the first quarter of 2016, retrospectively to all prior periods presented in our financial statements. The implementation of ASU 2015-03 did not have a material impact on our results of operations.

In May 2015, the FASB issued ASU 2015-07, Fair Value Measurement (Topic 820) to eliminate the requirement to categorize investments in the fair value hierarchy if the fair value is measured at net asset value ("NAV") per share (or its equivalent) using the practical expedient in the FASB’s fair value measurement gui~~dance~~. Reporting entities must still provide sufficient information to enable users to reconcile total investments in the fair value hierarchy and total investments measured at fair value in the financial statements. Additionally, the scope of current disclosure requirements for investments eligible to be measured at NAV will be limited to investments to which the practical expedient is applied. This ASU is effective in fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The ASU requires retrospective application. We implemented ASU 2015-07 in the first quarter of 2016, retrospectively to all prior periods presented in our fair value disclosures. This guidance required a revision of the fair value disclosures but did not impact our financial statements. The implementation of ASU 2015-07 did not have a material impact on our results of operations.

In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes to simplify the presentation of deferred income taxes. ASU 2015-17 requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. ASU 2015-17 can be applied prospectively or retrospectively and is effective for financial statements issued for annual periods beginning after December 15, 2016 and interim periods within those annual periods and early adoption is permitted. We elected to early adopt ASU 2015-17 retrospectively in the first quarter of 2016. The implementation of ASU 2015-17 did not have a material impact on our results of operations.

In May 2014, the FASB issued 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. In August 2015, FASB issued ASU 2015-14 to defer the effective date of ASU 2014-09 for all entities by one year. Public business entities will apply the guidance in ASU 2014-09 to annual reporting periods beginning after December 15, 2017 and interim periods within that reporting period. In March 2016, the FASB issued ASU 2016-08 to clarify the implementation guidance on principal versus agent consideration. In April 2016, the FASB issued ASU 2016-10 to clarify the implementation guidance on identifying performance obligations and licensing. In May 2016, the FASB issued ASU 2016-11, which rescinds certain SEC Staff Observer comments that are codified in FASB ASC Topic 605 (Revenue Recognition), effective upon adoption of Topic 606. In May 2016, the FASB issued ASU 2016-12, which makes narrow-scope amendments to ASU 2014-09, and provides practical expedients to simplify the transition to the new standard and to clarify certain aspects of the standard. Early adoption of ASU 2014-09 is permitted after December 15, 2016. We have not selected a transition method and we are currently assessing the future impact of this ASU.



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the FASB is permitting early adoption. The remaining provisions of this ASU become effective for public companies for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. We are currently assessing the future impact of this ASU.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and requiring qualitative and quantitative disclosures on leasing agreements. ASU 2016-02 maintains a distinction between finance leases and operating leases similar to the distinction under previous leases guidance for capital leases and operating leases. The impact of leases reported in the Company's operating results and statement of cash flows are expected to be similar to previous GAAP. ASU 2016-02 requires the recognition in the statement of financial position, by the lessee, of a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. How leases are recorded in regard to financial position represents a significant change from previous GAAP. The lessee is permitted to make annew accounting policy election to not recognize lease assets and lease liabilities for short-term leases. Implementation of the standard for public companies will be required for annual reporting periods beginning after December 15, 2018 and interim periods within that reporting period. Early adoption of ASU 2016-02 is permitted for all entities. Adoption of the new lease accounting standard will require us to apply the new standard to the earliest period using a modified retrospective approach. We are currently assessing the future impact of this ASU.

In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation (Topic 718) Improvements to Employee Share-Based Payment Accounting to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards either as equity or liabilities, and classification on the statements of cash flows. This ASU is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted. We are currently assessing the future impact of this ASU.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326). ASU 2016-13 significantly changes how companies measure and recognize credit impairment for many financial assets. The new current expected credit loss model will require companies to immediately recognize an estimate of credit losses expected to occur over the remaining life of the financial assets that are in the scope of the standard. The ASU also makes targeted amendments to the current impairment model for available-for-sale debt securities. For public business entities, the provisions of ASU 2016-13 are effective for fiscal years and interim periods within that reporting period beginning after December 15, 2019. Early implementation is permitted as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. ASU 2016-13 will be applied in a modified-retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is implemented. We are currently assessing the future impact of this ASU.standards.

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

In March 2016, we issued $150 million in aggregate principal amount of 5.00% Senior Notes due December 1, 2044 to repay outstanding short-term borrowings on our Revolving Credit Facility ("RCF") used for working capital and general corporate purposes, which may include funding capital expenditures. We continue to maintain a strong ~~balance of~~capital structure in which common stock equity inrepresented 42.7% of our ~~capital structure which supports our bond ratings, allowing us to obtain financing from the capital markets at a reasonable cost. At June 30, 2016, our capital structure, including common~~capitalization (common stock equity, long-term debt, current maturities of long-term debt and short-term borrowings under the ~~RCF, consisted~~RCF) as of ~~42.3% common stock equity and 57.7% debt.~~June 30, 2017. At June 30, ~~2016,~~2017, we had a balance of ~~$9.6~~$11.3 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 our RCF to meet all of our anticipated cash requirements for the next twelve ~~months.~~months including the upcoming maturities of long term debt.

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, ~~and~~ operating expenses including fuel costs, maintenance costs and ~~taxes.~~taxes, payment of our $50.0 million Series B 4.47% Senior Notes which mature on August 15, 2017 and payment or remarketing of $33.3 million 2012 Series A 1.875% Pollution Control Bonds which are subject to mandatory tender for purchase on September 1, 2017.

Capital Requirements. During the six months ended June 30, ~~2016,~~2017, our primary capital requirements ~~primarily consisted of expenditures~~were for the construction and purchase of our electric utility plant, ~~cash dividend~~ payments of common stock dividends and purchases of nuclear fuel. Projected utility construction expenditures are to add new generation, expand and update our transmission and distribution systems, and make capital improvements and replacements at Palo Verde and other generating facilities. 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 $226 million. On May 3, 2016, ~~we placed into commercial operation the third generating unit at the MPS and the related common facilities and transmission systems at a cost of approximately $81.3 million. MPS Uni~~t 4 is projected to be completed in September 2016. In 2016 we have incurred approximately $24.4 million of the estimated $41.5 million in cost for the MPS, including AFUDC. Estimated cash construction expenditures in 2016 for all capital projects are approximately $234 million. See Part I, Item 1, “Business - Construction Program” in our 2015 Form 10-K. Cash capital expendituresCapital requirements for new electric utility plant were ~~$102.8~~$108.1 million infor the six months ended June 30, ~~2016 compared to $147.0~~2017 and $102.8 million infor the six months ended June 30, ~~2015.~~2016. Capital expenditures for 2017 are expected to be approximately $215.0 million. Capital requirements for purchases of nuclear fuel were $20.6 million for the six months ended June 30, 2017, and $20.5 million for the six months ended June 30, ~~2016 compared to $22.4 million for the six months ended June 30, 2015.~~2016.

On June 30, ~~2016,~~2017, we paid a quarterly cash dividend of ~~$0.31~~$0.335 per share, or ~~$12.5~~$13.6 million, to shareholders of record as of the close of business on June ~~15, 2016.~~16, 2017. We paid a total of ~~$24.5~~$26.2 million in cash dividends during the six months ended June 30, 2016. On July 21, 2016 the Board of Directors declared a quarterly cash dividend of $0.31 per share payable on September 30, 2016 to shareholders of record as of the close of business on September 14, 2016.2017. At the current ~~payout~~dividend rate, we ~~would~~ expect to pay ~~total~~ cash dividends of approximately ~~$49.6~~$53.4 million during ~~2016.~~2017. In addition, while we do not currently anticipate repurchasing shares of our common stock in ~~2016,~~2017, we may repurchase shares of our common stock in the future. Under our repurchase program, purchases can be made at open market prices or in private transactions, and repurchased shares are available for issuance under employee benefit and stock incentive plans, or may be retired. No shares of common stock were repurchased during the six months ended June 30, ~~2016.~~2017. As of June 30, ~~2016,~~2017, a total of 393,816 shares remain ~~eligible~~available for repurchase under ~~the~~our currently authorized stock repurchase program.

We ~~will~~expect to continue to maintain a prudent level of liquidity and monitor market conditions for debt and equity securities. 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. ~~In light of these factors, we expect it will be a number of years before we achieve a dividend payout equivalent to industry average.~~

Our cash requirements for federal and state income taxes vary from year to year based on taxable income, which is influenced by the timing of revenues and expenses recognized for income tax purposes. Income tax payments are expected to be minimal in ~~2016~~2017 due to accelerated tax deductions, including bonus depreciation, available in ~~2016.~~2017.

We continually evaluate our funding requirements related to our retirement plans, other post-retirement benefit plans, and decommissioning trust funds. During the six months ended June 30, ~~2016,~~2017, we contributed ~~$2.8~~$6.5 million and ~~$1.1~~$0.2 million to our retirement plans and other post-retirement benefits plan, respectively, and ~~$2.2~~$2.3 million to our decommissioning trust funds. We are in compliance with the funding requirements of the federal government for our benefit plans. In addition, with respect to our nuclear plant decommissioning trust, we are in compliance with the funding requirements of the federal law and the ANPP Participation Agreement. We will continue to review our funding for these plans in order to meet our future obligations.

In 2010, ~~the Company~~we 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 matured and were paid with borrowings under the RCF. In August 2016, $50.0 million of these senior notes were reclassified to current maturities of long-term debt on our Balance Sheet, as they will mature in August 2017.

Capital Resources. Cash provided by operations, $68.0 million for the six months ended June 30, 2017 and $40.7 million for the six months ended June 30, 2016, is a significant source for funding capital requirements. The primary factors contributing to the increase in cash flows from operations were (i) the increase in net income and deferred income taxes, and (ii) changes in accounts payable and accounts receivable. A component of cash flows from operations is the change in net over-collection and under-collection of fuel revenues. The difference between fuel revenues collected and fuel expense incurred is deferred to be either refunded (over-recoveries) or surcharged (under-recoveries) to customers in the future. During the six months ended June 30,



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~~million of these senior notes matured and were paid with borrowings from the RCF.~~

~~Capital Resources~~. Cash provided by operations, $40.7 million for the six months ended June 30, 2016 and $60.4 million for the six months ended June 30, 2015, is a significant source for funding capital requirements. The primary factors affecting the decrease in cash flows from operations were a reduction in earnings arising from regulatory lag and decreases in the net over-collection of fuel revenues. The growth in accounts receivable, primarily reflecting the implementation of interim rates in Texas, is offset by the deferral of the related revenues. 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 our last revision except in the month of December based upon our approved formula which allows us to adjust fuel rates to reflect changes in costs of natural gas. 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, 2016,2017, we had ~~an under-recovery~~fuel over-recoveries of $2.7 million compared to under-recoveries of fuel costs of $2.0 ~~million compared to an over-recovery of fuel costs of $10.8~~ million during the six months ended June 30, ~~2015.~~2016. At June 30, ~~2016,~~2017, we had a net fuel ~~over-recovery~~under-recovery balance of ~~$2.0~~$8.2 million, including an under-recovery of $8.5 million in Texas offset by an over-recovery of ~~$1.1~~$0.3 million in New ~~Mexico and an over-recovery of $1.0 million~~Mexico. Contributing to the under-recovery balance in Texas ~~and an under-recovery~~is the recognition of ~~$0.1~~$5.0 million resulting from the settlement of the Texas fuel reconciliation in the ~~FERC jurisdiction.~~second quarter of 2017. On November 30, 2016, we filed a request to increase our Texas fixed fuel factor by approximately 28.8% to reflect increased fuel expenses primarily related to an increase in the price of natural gas used to generate power. The increase in our Texas fixed fuel factor was effective on an interim basis on January 1, 2017 and was approved by the PUCT on January 10, 2017.

We maintain athe RCF for working capital and general corporate purposes and ~~the~~ financing of nuclear fuel through ~~the~~ RGRT. ~~The~~ 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,~~9, 2017, we ~~amended and extended our $300 million RCF, which includes an~~exercised the option to ~~expand~~extend the maturity of the RCF by one year to January 14, 2020 and to increase the size of the facility by $50 million to $350 million. We still have the option to extend the facility by one additional year to January 2021 and to increase the RCF by up to $50 million (up to a total of $400 ~~million,~~million) upon the satisfaction of certain conditions, more fully set forth in the agreement, including obtaining commitments from lenders or third party financial institutions. ~~The 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, excluding debt issuance costs, was $133.9 million at June 30, 2017, of which $38.9 million had been borrowed under the RCF, and $95.0 million was borrowed through the issuance of senior notes. Borrowings by RGRT for nuclear fuel, excluding debt issuance costs, were $129.6 million atas of June 30, 2016, of which $34.6 million had been borrowed under the RCF and $95.0 million was borrowed through ~~senior notes. As~~the issuance of June 30, 2016, the amount available for borrowing under our $300 million RCF is $197.9 million. At June 30, 2015, the total amounts borrowed for nuclear fuel by RGRT, excluding debt issuance costs, was $128.1 million of which $18.1 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. ~~RCF~~At June 30, 2017, $140.0 million was outstanding ~~balances~~under the RCF for working capital and general corporate purposes, which may include funding capital ~~expenditures, were~~expenditures. At June 30, 2016, $67.0 million was outstanding under the RCF for working capital and ~~$110.0 million~~general corporate purposes. Total aggregate borrowings under the RCF at June 30, ~~2016 and 2015, respectively.~~2017 were $178.9 million with an additional $171.1 million available to borrow, after giving consideration to the $50 million increase on January 9, 2017.

We received approval from the NMPRC on October 7, 2015, and from the FERC on October 19, 2015, to issue up to ~~$310~~$310.0 million in ~~new~~ long-term debt and to guarantee the issuance of up to ~~$65~~$65.0 million of ~~new~~ debt by ~~the~~ RGRT to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. We also requested approval from the FERC to continue to utilize our existing RCF without change from the FERC’s previously approved authorization. The FERC authorization is effective from November 15, 2015 through November 15, 2017. The approvals granted in these cases supersede prior approvals. Under this authorization, on March 24, 2016, ~~the Company~~we issued ~~$150~~$150.0 million in aggregate principal amount of 5.00% Senior Notes due December 1, 2044. The proceeds from the issuance of these senior notes, after deducting the underwriters' commission, were $158.1 million. These proceeds include accrued interest of $2.4 million and a $7.1 million premium before expenses. The effective interest rate is approximately 4.77%. The net proceeds from the sale of these senior notes were used to repay outstanding short-term borrowings under the RCF used for working capital and general corporate purposes, which may include funding capital expenditures. These senior notes constitute an additional issuance of ~~the Company’s~~our 5.00% Senior Notes due 2044, of which ~~$150~~$150.0 million was previously issued on December 1, 2014, for a total principal amount outstanding of ~~$300~~$300.0 million.

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 ~~2015~~2016 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, ~~2016~~2017, 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 ~~2015~~2016 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.~~Act. Based on that evaluation, our chief executive officer and our chief financial officer concluded that, as of June 30, ~~2016~~2017, 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, ~~2016~~2017, 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 the Notes to Financial Statements.


Item 1A.	Risk Factors

Our ~~2015~~2016 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, 2016~~

—

~~393,816~~

~~May 1 to May 31, 2016~~

—

~~393,816~~

~~June 1 to June 30, 2016~~

—

~~393,816~~



Period	Total Number of Shares Purchased (a)	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, 2017	746	$	51.65	—	393,816
May 1 to May 31, 2017	—	—		—	393,816
June 1 to June 30, 2017	—	—		—	393,816

_____________________

(a) Represents shares of common stock delivered to us as payment of withholding taxes due upon the vesting of

restricted stock held by our employees, not considered part of the 2011 Plan.


~~Item 4.~~	~~Mine Safety Disclosures~~

~~Not Applicable.~~


Item 5.	Other Information

Investors should note that we announce material financial information in ~~SEC~~Securities and Exchange Commission ("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 ~~5, 2016~~4, 2017



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EL PASO ELECTRIC COMPANY

INDEX TO EXHIBITS




Exhibit Number			Exhibit


~~10.01~~			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).

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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Description of Securities	Fair Value as of June 30, 2016		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	$	1,376	$	—	$	—	$	1,376
Available for sale:
U.S. Government Bonds	$	58,350	$	58,350	$	—	$	—
Federal Agency Mortgage Backed Securities	18,933		—		18,933		—
Municipal Bonds	22,785		—		22,785		—
Corporate Asset Backed Obligations	22,253		—		22,253		—
Subtotal Debt Securities	122,321		58,350		63,971		—
Common Stock	69,720		69,720		—		—
Equity Mutual Funds	29,153		29,153		—		—
Institutional Funds-International Equity (1)	21,360
Cash and Cash Equivalents	5,686		5,686		—		—
Total Available for Sale	$	248,240	$	162,909	$	63,971	$	—