EE 10-Q Quarterly Report June 30, 2016

EL PASO ELECTRIC CO /TX/

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10-Q 1 a2016june10q.htm JUNE 30, 2016 FORM 10-Q Document

Table of Contents

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



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

Commission file number 001-14206

El Paso Electric Company

(Exact name of registrant as specified in its charter)



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

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

(915) 543-5711

(Registrant’s telephone number, including area code)

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

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

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



Large accelerated filer	x	Accelerated filer	o

Non-accelerated filer	o	Smaller reporting company	o

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

As of July 31, 2016 , there were 40,520,871 shares of the Company’s no par value common stock outstanding.

Table of Contents

EL PASO ELECTRIC COMPANY

INDEX TO FORM 10-Q



		Page No.
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
Balance Sheets – June 30, 2016 and December 31, 2015		1
Statements of Operations – Three Months, Six Months, and Twelve Months Ended June 30, 2016 and 2015		3
Statements of Comprehensive Operations – Three Months, Six Months, and Twelve Months Ended June 30, 2016 and 2015		5
Statements of Cash Flows – Six Months Ended June 30, 2016 and 2015		6
Notes to Financial Statements		7
Report of Independent Registered Public Accounting Firm		29
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	46
Item 4.	Controls and Procedures	46
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	47
Item 1A.	Risk Factors	47
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 4.	Mine Safety Disclosures	47
Item 5.	Other Information	47
Item 6.	Exhibits	47



	( i )

Table of Contents

PART I. FINANCIAL INFORMATION


Item 1.	Financial Statements

EL PASO ELECTRIC COMPANY

BALANCE SHEETS



	June 30, 2016			December 31, 2015
	(Unaudited)

ASSETS (In thousands)
Utility plant:
Electric plant in service	$	3,783,907		$	3,616,301
Less accumulated depreciation and amortization	(1,369,646		)	(1,329,843		)
Net plant in service	2,414,261			2,286,458
Construction work in progress	221,607			293,796
Nuclear fuel; includes fuel in process of $54,224 and $51,854, respectively	191,925			190,282
Less accumulated amortization	(75,546		)	(75,031		)
Net nuclear fuel	116,379			115,251
Net utility plant	2,752,247			2,695,505
Current assets:
Cash and cash equivalents	9,607			8,149
Accounts receivable, principally trade, net of allowance for doubtful accounts of $1,570 and $2,046, respectively	105,443			66,326
Inventories, at cost	47,376			48,697
Under-collection of fuel revenues	30			—
Prepayments and other	15,062			9,872
Total current assets	177,518			133,044
Deferred charges and other assets:
Decommissioning trust funds	248,240			239,035
Regulatory assets	116,617			115,127
Other	17,640			17,896
Total deferred charges and other assets	382,497			372,058
Total assets	$	3,312,262		$	3,200,607

See accompanying notes to financial statements.



	1

Table of Contents

EL PASO ELECTRIC COMPANY

BALANCE SHEETS (Continued)



	June 30, 2016			December 31, 2015
	(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
Capital in excess of stated value	320,572			320,073
Retained earnings	1,059,398			1,067,396
Accumulated other comprehensive loss, net of tax	(13,300		)	(13,914		)
	1,432,498			1,439,384
Treasury stock, 25,307,484 and 25,384,834 shares, respectively, at cost	(421,558		)	(422,846		)
Common stock equity	1,010,940			1,016,538
Long-term debt, net of current portion	1,278,301			1,122,660
Total capitalization	2,289,241			2,139,198
Current liabilities:
Short-term borrowings under the revolving credit facility	101,614			141,738
Accounts payable, principally trade	44,162			59,978
Taxes accrued	25,318			30,351
Interest accrued	13,267			12,649
Over-collection of fuel revenues	2,063			4,023
Other	41,950			28,325
Total current liabilities	228,374			277,064
Deferred credits and other liabilities:
Accumulated deferred income taxes	502,677			495,237
Accrued pension liability	87,728			90,527
Accrued post-retirement benefit liability	55,677			54,553
Asset retirement obligation	85,363			81,621
Regulatory liabilities	23,930			24,303
Other	39,272			38,104
Total deferred credits and other liabilities	794,647			784,345
Commitments and contingencies
Total capitalization and liabilities	$	3,312,262		$	3,200,607

See accompanying notes to financial statements.



	2

Table of Contents

EL PASO ELECTRIC COMPANY

STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands except for share data)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Operating revenues	$	217,865		$	219,508		$	375,674		$	383,254
Energy expenses:
Fuel	43,143			49,813			77,462			87,542
Purchased and interchanged power	13,610			11,742			23,256			22,917
	56,753			61,555			100,718			110,459
Operating revenues net of energy expenses	161,112			157,953			274,956			272,795
Other operating expenses:
Other operations	56,817			57,656			115,204			113,255
Maintenance	20,426			19,857			37,941			35,417
Depreciation and amortization	23,852			23,135			47,145			44,700
Taxes other than income taxes	15,320			15,433			30,132			29,591
	116,415			116,081			230,422			222,963
Operating income	44,697			41,872			44,534			49,832
Other income (deductions):
Allowance for equity funds used during construction	2,133			2,268			4,469			6,543
Investment and interest income, net	3,591			1,398			6,520			6,652
Miscellaneous non-operating income	145			507			801			687
Miscellaneous non-operating deductions	(890		)	(1,271		)	(1,356		)	(1,762		)
	4,979			2,902			10,434			12,120
Interest charges (credits):
Interest on long-term debt and revolving credit facility	18,298			16,495			34,897			32,978
Other interest	272			354			834			517
Capitalized interest	(1,253		)	(1,261		)	(2,495		)	(2,550		)
Allowance for borrowed funds used during construction	(1,375		)	(1,391		)	(3,033		)	(4,012		)
	15,942			14,197			30,203			26,933
Income before income taxes	33,734			30,577			24,765			35,019
Income tax expense	11,450			9,505			8,289			10,489
Net income	$	22,284		$	21,072		$	16,476		$	24,530

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

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

Dividends declared per share of common stock	$	0.310		$	0.295		$	0.605		$	0.575
Weighted average number of shares outstanding	40,345,150			40,269,885			40,335,236			40,256,615
Weighted average number of shares and dilutive potential shares outstanding	40,399,491			40,302,694			40,380,640			40,284,757

See accompanying notes to financial statements.



	3

Table of Contents

EL PASO ELECTRIC COMPANY

STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands except for share data)



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

Basic earnings per share	$	1.83		$	2.01

Diluted earnings per share	$	1.83		$	2.01

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

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
	June 30,						June 30,						June 30,
	2016			2015			2016			2015			2016			2015
Net income	$	22,284		$	21,072		$	16,476		$	24,530		$	73,864		$	81,247
Other comprehensive income (loss):
Unrecognized pension and post-retirement benefit costs:
Net gain (loss) arising during period	—			—			—			—			5,429			(74,028		)
Prior service benefit	—			—			—			—			824			34,200
Reclassification adjustments included in net income for amortization of:
Prior service benefit	(1,664		)	(1,662		)	(3,330		)	(3,325		)	(6,579		)	(7,455		)
Net loss	1,222			2,250			2,445			4,500			6,567			7,730
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 losses on cash flow hedges:
Reclassification adjustment for interest expense included in net income	123			116			245			230			482			452
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):
Unrecognized pension and post-retirement benefit costs	166			(291		)	222			(622		)	(2,442		)	14,761
Net unrealized losses (gains) on marketable securities	(149		)	325			(322		)	881			1,625			979
Losses on cash flow hedges	(46		)	(43		)	(128		)	(115		)	(216		)	(197		)
Total income tax benefit (expense)	(29		)	(9		)	(228		)	144			(1,033		)	15,543
Other comprehensive income (loss), net of tax	332			(686		)	614			(2,563		)	(2,736		)	(28,294		)
Comprehensive income	$	22,616		$	20,386		$	17,090		$	21,967		$	71,128		$	52,953

See accompanying notes to financial statements.



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Table of Contents

EL PASO ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)



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

See accompanying notes to financial statements.



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Table of Contents

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 (the " 2015 Form 10-K"). Capitalized terms used in this report and not defined herein have the meaning ascribed to such terms in the 2015 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 and December 31, 2015 ; the results of its operations and comprehensive operations for the three, six and twelve months ended June 30, 2016 and 2015 ; and its cash flows for the six months ended June 30, 2016 and 2015 . The results of operations and comprehensive operations for the three and six months ended June 30, 2016 and the cash flows for the six months ended June 30, 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"), certain financial information has been condensed and certain footnote disclosures have been omitted. Such information and disclosures are normally included in financial statements prepared in accordance with generally accepted accounting principles.

Use of Estimates . The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. 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 million at June 30, 2016 and $21.7 million at December 31, 2015 . The Company presents revenues net of sales taxes in its statements of operations.



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. In April 2015, the 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. 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 financial



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Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

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

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. The Company implemented ASU 2015-07 in 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.

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. The Company has not selected a transition method and is currently assessing the future impact of this ASU.

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 beginning after December 15, 2017, including interim periods within those fiscal years. The Company is currently assessing the future impact of this ASU.



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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 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. 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 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. The Company is 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. The Company is currently assessing the future impact of this ASU.

Reclassification. Certain amounts in the financial statements for 2015 have been reclassified to conform to the 2016 presentation. The Company implemented ASU 2015-03 and 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.



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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
		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		$	(30,256	)	$	28,394		$	(11,770	)	$	(13,632	)	$	(34,628	)	$	36,782		$	(12,032	)	$	(9,878	)
	Other comprehensive income (loss) before reclassifications	—			2,224			—			2,224			—			(1,191		)	—			(1,191		)
	Amounts reclassified from accumulated other comprehensive income (loss)	(276		)	(1,693		)	77			(1,892		)	297			135			73			505
Balance at end of period		$	(30,532	)	$	28,925		$	(11,693	)	$	(13,300	)	$	(34,331	)	$	35,726		$	(11,959	)	$	(10,564	)

		Six Months Ended June 30, 2016												Six Months Ended June 30, 2015
		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		$	(29,869	)	$	27,765		$	(11,810	)	$	(13,914	)	$	(34,884	)	$	38,957		$	(12,074	)	$	(8,001	)
	Other comprehensive income (loss) before reclassifications	—			3,966			—			3,966			—			(369		)	—			(369		)
	Amounts reclassified from accumulated other comprehensive income (loss)	(663		)	(2,806		)	117			(3,352		)	553			(2,862		)	115			(2,194		)
Balance at end of period		$	(30,532	)	$	28,925		$	(11,693	)	$	(13,300	)	$	(34,331	)	$	35,726		$	(11,959	)	$	(10,564	)

		Twelve Months Ended June 30, 2016												Twelve Months Ended June 30, 2015
		Unrecognized Pension and Post-retirement Benefit Costs			Net Unrealized Gains (Losses) on Marketable Securities			Net Losses on Cash Flow Hedges			Accumulated Other Comprehensive Income (Loss)			Unrecognized Pension and Post-retirement Benefit Costs			Net Unrealized Gains (Losses) on Marketable Securities			Net Losses on Cash Flow Hedges			Accumulated Other Comprehensive Income (Loss)

Balance at beginning of period		$	(34,331	)	$	35,726		$	(11,959	)	$	(10,564	)	$	(9,539	)	$	39,483		$	(12,214	)	$	17,730
	Other comprehensive income (loss) before reclassifications	3,777			2,080			—			5,857			(24,775		)	2,681			—			(22,094		)
	Amounts reclassified from accumulated other comprehensive income (loss)	22			(8,881		)	266			(8,593		)	(17		)	(6,438		)	255			(6,200		)
Balance at end of period		$	(30,532	)	$	28,925		$	(11,693	)	$	(13,300	)	$	(34,331	)	$	35,726		$	(11,959	)	$	(10,564	)



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



Details about Accumulated Other Comprehensive Income (Loss) Components		Three Months Ended June 30,						Six Months Ended June 30,						Twelve Months Ended June 30,						Affected Line Item in the Statement of Operations
		2016			2015			2016			2015			2016			2015			Affected Line Item in the Statement of Operations

Amortization of pension and post-retirement benefit costs:
	Prior service benefit	$	1,664		$	1,662		$	3,330		$	3,325		$	6,579		$	7,455		(a)
	Net loss	(1,222		)	(2,250		)	(2,445		)	(4,500		)	(6,567		)	(7,730		)	(a)
		442			(588		)	885			(1,175		)	12			(275		)	(a)
	Income tax effect	(166		)	291			(222		)	622			(34		)	292			Income tax expense
		276			(297		)	663			(553		)	(22		)	17			(a)

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
		2,110			(182		)	3,498			3,563			11,049			7,946			Income before income taxes
	Income tax effect	(417		)	47			(692		)	(701		)	(2,168		)	(1,508		)	Income tax expense
		1,693			(135		)	2,806			2,862			8,881			6,438			Net income

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

	Total reclassifications	$	1,892		$	(505	)	$	3,352		$	2,194		$	8,593		$	6,200

(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 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 . 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 155 th 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 January 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 parties to the rate case in Docket No. 44941 (the "Unopposed Settlement"). The terms of the Unopposed Settlement include: (i) an annual non-fuel base rate increase of $37 million , lower annual depreciation expense of approximately $8.5 million , a return on equity of 9.7% for AFUDC purposes, and including 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; (iii) removing the separate treatment for residential customers with solar generation; and (iv) allowing the Company to recover most of the rate case expenses up to a date certain. The Unopposed Settlement is subject to approval by the PUCT. The settlement documents were filed with ALJs assigned to oversee the Company's Texas Rate case, who have returned the settled case to the PUCT for approval. It is anticipated that the Unopposed Settlement will be considered by the PUCT at its meeting scheduled for August 18, 2016. The costs of serving residential customers with solar generation will be addressed in a future proceeding.

Given the uncertainties regarding the ultimate resolution of this rate case, the Company did not recognize the impacts of the Unopposed Settlement in the Statements of Operations for the second quarter of 2016. The additional revenues resulting from the implementation of the 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 . At this time, the Company believes the revenue and other impacts of the Unopposed



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

Fuel Reconciliation Proceeding . Pursuant to the 2012 Texas retail rate settlement discussed above, on September 27, 2013, the Company filed an application with the PUCT, designated as PUCT Docket No. 41852, to reconcile $545.3 million of fuel and purchased power expenses incurred during the 45 -month period from July 1, 2009 through March 31, 2013. A settlement was reached and a final order was issued by the PUCT on July 11, 2014 with no significant adjustments. The PUCT's final order completes the regulatory review and reconciliation of the Company's fuel expenses for the period through March 31, 2013. The Company is required to file an application by the end of September 2016 for fuel reconciliation of the Company's fuel expenses for the period through March 31, 2016.

Montana Power Station ("MPS") Approvals . T he Company has received 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 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 .

Community Solar. On June 8, 2015, the Company filed a petition with the PUCT to initiate a community solar program to include construction and ownership of a 3 MW solar photovoltaic system located at MPS. 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 the program, and the Company expects an order from the PUCT on or about August 18, 2016 approving the settlement agreement.



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Four Corners Generating Station ("Four Corners"). On February 17, 2015 , the Company and Arizona Public Service Company ("APS") entered into an asset purchase agreement (the "Purchase and Sale Agreement") providing for the purchase by APS of the Company's interests in Four Corners. The 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 mine reclamation costs, in 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 costs in Texas under previous orders and decisions of 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.

Other Required Approvals . The Company has obtained other required approvals for tariffs and approvals as required by the Public Utility Regulatory Act (the "PURA") and the PUCT.

New Mexico Regulatory Matters

2009 New Mexico Stipulation. On December 10, 2009, the NMPRC issued a final order conditionally approving the stipulated rates in NMPRC Case No. 09-00171-UT. The stipulated rates went into effect with January 2010 bills. The stipulated rates provide for an Efficient Use of Energy Factor Rate Rider to recover energy efficiency expenditures which are updated annually for adjustment to the recovery factors.

2015 New Mexico Rate Case Filing . On May 11, 2015, the Company filed with the NMPRC 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 . On June 8, 2016, the NMPRC issued its final order approving an annual increase in non-fuel base rates of approximately $1.1 million and a decrease in the Company's allowed return on equity to 9.48% . The final order concludes that all of the Company's plant additions are in service and used and useful, and that the costs were prudently incurred, and therefore would be recoverable and included in rate base. The Company's rates were approved by the NMPRC effective July 1, 2016.

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 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 of Case No. 15-00127-UT, fuel and purchase power costs will no longer be recovered through base rates but will be completely recovered through the FPPCAC. Fuel and purchased power costs are reconciled to actual costs on a monthly basis and recovered or refunded to customers the second succeeding month. The Company recovers costs related to Palo Verde Unit 3 capacity and energy in New Mexico through the FPPCAC as purchased power using a proxy market price approved in Case No. 13-00380-UT. At June 30, 2016 , the Company had a net fuel over-recovery balance of $1.1 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 . On June 15, 2015, the Company filed a petition with the NMPRC requesting CCN authorization to construct a 5 MW solar-powered generation facility to be located at 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 a power sales agreement for the facility to replace the existing load retention agreement.

Issuance of Long-Term Debt and Guarantee of Debt. On October 7, 2015, the Company received approval in NMPRC Case No. 15-00280-UT to issue up to $310 million in new long-term debt; and to guarantee the issuance of up to $65 million 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, 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 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.



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D. Palo Verde and Four Corners

Spent Nuclear Fuel and Waste Disposal. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "NWPA"), the U.S. Department of Energy (the "DOE") is legally obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive waste generated by all domestic power reactors by 1998. The DOE's obligations are reflected in a contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (the "Standard Contract") with each nuclear power plant. The DOE failed to begin accepting spent nuclear fuel by 1998.

On December 19, 2012 , APS, acting on behalf of itself and the 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 request for reimbursement of spent nuclear fuel storage costs for the period July 1, 2011 through June 30, 2014 . The accepted claim amount was $42.0 million . On June 1, 2015 , the Company received approximately $6.6 million , representing its share of the award. The majority of the award was credited to customers through the applicable fuel adjustment clauses in March 2015. Thereafter 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 received in the first quarter of 2016 . The Company's share of this claim is approximately $1.9 million . The majority of the award was credited to customers through the applicable fuel adjustment clauses in March 2016. APS's next claim pursuant to the terms of the August 18, 2014 settlement agreement will be submitted to 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 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 value 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, the Company received approximately $4.2 million in cash, subject to post-closing adjustments. No significant gain or loss was recorded upon the closing of the sale. APS will assume responsibility for all capital expenditures made after July 6, 2016. In addition, APS will indemnify the Company against liabilities and costs related to the future operation of Four Corners. See Note C for a discussion of regulatory filings associated with Four Corners.



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E. Common Stock

Dividends. The Company paid $12.5 million and $11.9 million in quarterly cash dividends during the three months ended June 30, 2016 and 2015 , 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 , 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 .



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,
	2016			2015
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	40,345,150			40,269,885
Dilutive effect of unvested performance awards	54,341			32,809
Diluted number of common shares outstanding	40,399,491			40,302,694
Basic net income per common share:
Net income	$	22,284		$	21,072
Income allocated to participating restricted stock	(65		)	(65		)
Net income available to common shareholders	$	22,219		$	21,007
Diluted net income per common share:
Net income	$	22,284		$	21,072
Income reallocated to participating restricted stock	(65		)	(65		)
Net income available to common shareholders	$	22,219		$	21,007
Basic net income per common share:
Distributed earnings	$	0.310		$	0.295
Undistributed earnings	0.240			0.225
Basic net income per common share	$	0.550		$	0.520
Diluted net income per common share:
Distributed earnings	$	0.310		$	0.295
Undistributed earnings	0.240			0.225
Diluted net income per common share	$	0.550		$	0.520



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	Six Months Ended June 30,
	2016			2015
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	40,335,236			40,256,615
Dilutive effect of unvested performance awards	45,404			28,142
Diluted number of common shares outstanding	40,380,640			40,284,757
Basic net income per common share:
Net income	$	16,476		$	24,530
Income allocated to participating restricted stock	(66		)	(71		)
Net income available to common shareholders	$	16,410		$	24,459
Diluted net income per common share:
Net income	$	16,476		$	24,530
Income reallocated to participating restricted stock	(66		)	(71		)
Net income available to common shareholders	$	16,410		$	24,459
Basic net income per common share:
Distributed earnings	$	0.605		$	0.575
Undistributed earnings	(0.195		)	0.035
Basic net income per common share	$	0.410		$	0.610
Diluted net income per common share:
Distributed earnings	$	0.605		$	0.575
Undistributed earnings	(0.195		)	0.035
Diluted net income per common share	$	0.410		$	0.610



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	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:
	Three Months Ended		Six months ended		Twelve Months Ended
	June 30,		June 30,		June 30,
	2016	2015	2016	2015	2016	2015
Restricted stock awards	42,759	48,669	51,111	58,432	52,714	59,380
Performance shares (a)	62,995	59,898	62,995	59,898	56,089	48,136


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



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F. Income Taxes

The Company files income tax returns in the United States ("U.S.") federal jurisdiction and in the states of Texas, New Mexico and Arizona. The Company is no longer subject to tax examination by the taxing authorities in the federal and New Mexico jurisdictions for years prior to 2011 . 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.

For the three months ended June 30, 2016 and 2015 , the Company’s effective tax rate was 33.9% and 31.1% , respectively. For the six months ended June 30, 2016 and 2015 , the Company's effective tax rate was 33.5% and 30.0% , respectively. For the twelve months ended June 30, 2016 and 2015 , the Company's effective tax rate was 30.7% and 30.3% , 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"), and state taxes.

In November 2015, the FASB issued new guidance (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 implement ASU 2015-17 on a retrospective basis for financial statements issued beginning March 31, 2016. The implementation of ASU 2015-17 did not have a material impact on the Company's results of operations. The impact of ASU 2015-17 on the Company's Balance Sheet was to reclassify $21.6 million of current deferred tax assets to long-term deferred tax liabilities at December 31, 2015.

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 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 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 Form 10-K.

Environmental Matters

General. The Company is subject to extensive laws, regulations and permit requirements with respect to air and greenhouse gas emissions, water discharges, soil and water quality, waste management and disposal, natural resources and other environmental matters by federal, state, regional, tribal and local authorities. Failure to comply with such laws, regulations and requirements can result in actions by authorities or other third parties that might seek to impose on the Company administrative, civil and/or criminal penalties or other sanctions. In addition, releases of pollutants or contaminants into the environment can result in costly cleanup liabilities. These laws, regulations, and requirements are subject to change through modification or reinterpretation, or the introduction of new laws and regulations and, as a result, the Company may face additional capital and operating costs to comply. For a more detailed discussion of certain key environmental issues, laws, and regulations facing the Company, see Note K of the Notes to Financial Statements in the 2015 Form 10-K.

Clean Air Interstate Rule/Cross State Air Pollution Rule . The EPA promulgated the Cross-State Air Pollution Rule ("CSAPR") in August 2011, which rule involves requirements to limit emissions of nitrogen oxides ("NOx") and sulfur dioxide ("SO2") from certain of the Company's power plants in Texas and/or purchase allowances representing other parties' emissions reductions. CSAPR was intended to replace the EPA's 2005 Clean Air Interstate Rule ("CAIR"). While the U.S. Court of Appeals for the



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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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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.



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(Unaudited)

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

I. Employee Benefits

Retirement Plans

The net periodic benefit cost recognized for the three, six and twelve months ended June 30, 2016 and 2015 is made up of the components listed below as determined using the projected unit credit actuarial cost method (in thousands):



	Three Months Ended						Six Months Ended						Twelve Months Ended
	June 30,						June 30,						June 30,
	2016			2015			2016			2015			2016			2015
Components of net periodic benefit cost:
Service cost	$	1,905		$	2,100		$	3,810		$	4,200		$	8,402		$	8,425
Interest cost	3,265			3,625			6,530			7,250			13,775			14,632
Expected return on plan assets	(4,713		)	(4,948		)	(9,425		)	(9,895		)	(19,325		)	(19,258		)
Amortization of:
Net loss	1,887			2,750			3,775			5,500			8,922			10,065
Prior service benefit	(877		)	(887		)	(1,755		)	(1,775		)	(3,486		)	(3,528		)
Net periodic benefit cost	$	1,467		$	2,640		$	2,935		$	5,280		$	8,288		$	10,336

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



	Three Months Ended						Six Months Ended						Twelve Months Ended
	June 30,						June 30,						June 30,
	2016			2015			2016			2015			2016			2015
Components of net periodic benefit cost:
Service cost	$	715		$	875		$	1,430		$	1,750		$	3,134		$	3,173
Interest cost	872			1,025			1,745			2,050			3,730			4,281
Expected return on plan assets	(460		)	(525		)	(920		)	(1,050		)	(1,940		)	(2,108		)
Amortization of:
Prior service benefit	(787		)	(775		)	(1,575		)	(1,550		)	(3,093		)	(3,927		)
Net gain	(665		)	(500		)	(1,330		)	(1,000		)	(2,355		)	(2,335		)
Net periodic benefit cost (benefit)	$	(325	)	$	100		$	(650	)	$	200		$	(524	)	$	(916	)

During the six months ended June 30, 2016 , the Company contributed $1.1 million of its projected $1.7 million 2016 annual contribution to its other post retirement 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, accounts payable and customer deposits meet the definition of financial



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(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.

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
	Carrying Amount (1)		Estimated Fair Value		Carrying Amount (1)		Estimated Fair Value
Pollution Control Bonds	$	190,637	$	214,132	$	190,499	$	212,624
Senior Notes	992,924		1,193,209		837,475		829,864
RGRT Senior Notes (2)	94,740		101,215		94,686		100,345
RCF (2)	101,614		101,614		141,738		141,738
Total	$	1,379,915	$	1,610,170	$	1,264,398	$	1,284,571

_______________

(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 and December 31, 2015 , is funded through the $95 million RGRT Senior Notes and $34.6 million and $33.7 million , respectively under the RCF. As of June 30, 2016 , $67.0 million was outstanding under the RCF for working capital or general corporate purposes. As of December 31, 2015 , $108.0 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 c urrent market rates. Consequently, the carrying value approximates fair value.

Marketable Securities. The Company's marketable securities, included in decommissioning trus t funds in the Balance Sheets, are reported at fair value which was $248.2 million and $239.0 million at June 30, 2016 and December 31, 2015 , 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
	Less than 12 Months					12 Months or Longer					Total
	Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses
Description of Securities (1) :
Federal Agency Mortgage Backed Securities	$	497	$	(5	)	$	584	$	(6	)	$	1,081	$	(11	)
U.S. Government Bonds	6,174		(54		)	14,844		(461		)	21,018		(515		)
Municipal Obligations	2,020		(23		)	9,018		(540		)	11,038		(563		)
Corporate Obligations	1,498		(30		)	3,300		(166		)	4,798		(196		)
Total Debt Securities	10,189		(112		)	27,746		(1,173		)	37,935		(1,285		)
Common Stock	2,146		(504		)	—		—			2,146		(504		)
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	)

_________________


(1)	Includes 93 securities.



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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)



	December 31, 2015
	Less than 12 Months					12 Months or Longer					Total
	Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses
Description of Securities (2) :
Federal Agency Mortgage Backed Securities	$	9,383	$	(97	)	$	1,113	$	(47	)	$	10,496	$	(144	)
U.S. Government Bonds	24,094		(310		)	14,272		(623		)	38,366		(933		)
Municipal Obligations	8,286		(160		)	7,388		(446		)	15,674		(606		)
Corporate Obligations	6,058		(722		)	2,307		(228		)	8,365		(950		)
Total Debt Securities	47,821		(1,289		)	25,080		(1,344		)	72,901		(2,633		)
Common Stock	3,584		(344		)	—		—			3,584		(344		)
Institutional Equity Funds-International Equity	22,454		(768		)	—		—			22,454		(768		)
Total Temporarily Impaired Securities	$	73,859	$	(2,401	)	$	25,080	$	(1,344	)	$	98,939	$	(3,745	)

_________________


(2)	Includes 133 securities.

The Company monitors the length of time specific securities trade below its cost basis along with the amount and percentage of the unrealized loss in determining if a decline in fair value of marketable securities below recorded cost is considered to be other than temporary. 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 and 2015, 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	)	$	—

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
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
Description of Securities:
Federal Agency Mortgage Backed Securities	$	17,852	$	725	$	9,589	$	438
U.S. Government Bonds	37,332		1,670		12,033		136
Municipal Obligations	11,747		539		8,671		332
Corporate Obligations	17,455		1,265		10,110		368
Total Debt Securities	84,386		4,199		40,403		1,274
Common Stock	67,574		34,603		72,636		37,001
Equity Mutual Funds	29,153		863		18,853		91
Cash and Cash Equivalents	5,686		—		8,204		—
Total	$	186,799	$	39,665	$	140,096	$	38,366



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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

The Company's marketable securities include investments in municipal, corporate and federal debt obligations. Substantially all of the Company's mortgage-backed securities, based on contractual maturity, are due in ten years or more. The mortgage-backed securities have an estimated weighted average maturity which generally range from two years to six years and reflects anticipated future prepayments. The contractual year for maturity of these available-for-sale securities as of June 30, 2016 is as follows (in thousands):



	Total		2016		2017 through 2020		2021 through 2025		2026 and Beyond
Municipal Debt Obligations	$	22,785	$	711	$	8,957	$	11,727	$	1,390
Corporate Debt Obligations	22,253		—		4,799		8,920		8,534
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 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 and 2015 and the related effects on pre-tax income are as follows (in thousands):



	Three Months Ended						Six Months Ended						Twelve Months Ended
	June 30,						June 30,						June 30,
	2016			2015			2016			2015			2016			2015
Proceeds from sales or maturities of available-for-sale securities	$	16,634		$	12,516		$	40,712		$	37,158		$	106,121		$	109,095
Gross realized gains included in pre-tax income	$	2,409		$	33		$	4,241		$	3,815		$	12,805		$	8,410
Gross realized losses included in pre-tax income	(299		)	(215		)	(587		)	(252		)	(1,262		)	(464		)
Gross unrealized losses included in pre-tax income	—			—			(156		)	—			(494		)	—
Net gains (losses) included in pre-tax income	$	2,110		$	(182	)	$	3,498		$	3,563		$	11,049		$	7,946
Net unrealized holding gains (losses) included in accumulated other comprehensive income	$	2,790		$	(1,563	)	$	4,980		$	(549	)	$	2,623		$	3,210
Net (gains) losses reclassified from accumulated other comprehensive income	(2,110		)	182			(3,498		)	(3,563		)	(11,049		)	(7,946		)
Net gains (losses) in other comprehensive income	$	680		$	(1,381	)	$	1,482		$	(4,112	)	$	(8,426	)	$	(4,736	)

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.

•

Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. Financial assets utilizing Level 2 inputs include the nuclear decommissioning trust investments in fixed income securities. The fair value of these financial instruments is based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences. The 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 and December 31, 2015 , 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)
Trading Securities:
Investments in Debt Securities	$	1,543	$	—	$	—	$	1,543
Available for sale:
U.S. Government Bonds	$	50,399	$	50,399	$	—	$	—
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		—
Common Stock	76,220		76,220		—		—
Equity Mutual Funds	18,853		18,853		—		—
Institutional Funds-International Equity (1)	22,454
Cash and Cash Equivalents	8,204		8,204		—		—
Total Available for Sale	$	239,035	$	153,676	$	62,905	$	—



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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.

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 and 2015 . 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 and 2015 .



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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 , the related condensed statements of operations and comprehensive operations for the three-month, six-month, and twelve-month periods ended June 30, 2016 and 2015 , and the related condensed statements of cash flows for the six -month periods ended June 30, 2016 and 2015 . 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 , 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, 2016 , 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 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



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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 Form 10-K.

FORWARD-LOOKING STATEMENTS

Certain matters discussed in this Quarterly Report on Form 10-Q other than statements of historical information are “forward-looking statements.” within the meaning of Section 27A of the Securities Act of 1933. as amended (the "Securities Act"), and Section 21E of the Securities Act of 1934, as amended (the "Exchange Act"). Forward-looking statements often include words like we "believe", "anticipate", "target", "project", "expect", "predict", "pro-forma", "estimate", "intend", "will", "is designed to", "plan", and words of similar meaning, or by the Company's discussion of strategies or trends. Forward-looking statements describe our future plans, objectives, expectations, and 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, 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 regulators,


•	our ability to fully and timely recover our costs and earn a reasonable rate of return on our invested capital through the rates that we are 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 operating partners to maintain plant operations and manage operation and maintenance costs at the Palo Verde plant, including costs to comply with any new or expanded regulatory or environmental requirements,


•	reductions in output at generation plants operated by us,


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


•	our reliance on significant customers,


•	the credit worthiness of our 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 and other post-retirement benefit liability calculations, as well as actual and assumed investment returns on retirement and other post-retirement plan assets,


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


•	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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•	ongoing municipal, state and federal activities,


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


•	political, legislative, judicial and regulatory developments,


•	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 and capital market conditions,


•	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 against us,


•	the impact of changes in interest rates,


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


•	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,


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


•	other circumstances affecting anticipated operations, sales and costs.

These lists are not all-inclusive because it is not possible to predict all factors. A discussion of some of these factors is included in the 2015 Form 10-K under the headings “Risk Factors” and “Management's Discussion and Analysis” “-Summary of Critical Accounting Policies and Estimates” and “-Liquidity and Capital Resources.” This 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 speaks only as of the date such statement was made, as we are not obligated to update any forward-looking statements 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 Form 10-K.

Summary

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



	Three Months Ended				Six Months Ended				Twelve Months Ended
	June 30,				June 30,				June 30,
	2016		2015		2016		2015		2016		2015
Net income (in thousands)	$	22,284	$	21,072	$	16,476	$	24,530	$	73,864	$	81,247
Basic earnings per share	0.55		0.52		0.41		0.61		1.83		2.01

Regulatory Lag

Our results of operations for the three, six and twelve months ended June 30, 2016 compared to the same periods in 2015 have been negatively impacted as a result of the completion of Montana Power Station ("MPS") Units 1 & 2 (including common plant, transmission lines and substation) and the Eastside Operations Center ("EOC"), due to the regulatory lag associated with the placement in service of these assets without a corresponding increase in revenues. The placement in service of MPS Unit 3 in



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May 2016 and the anticipated completion of MPS Unit 4 in 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 of 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 the primary factors affecting the after-tax change in net income between the 2016 and 2015 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

______________

(a)

Retail non-fuel base revenues increased for the three and six months ended June 30, 2016 compared to the three and six months ended June 30, 2015, primarily due to increased revenues from our residential customers and small commercial and industrial customers primarily due to increased kWh sales that resulted from an increase 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.

Retail non-fuel base revenues increased for the twelve months ended June 30, 2016 compared to the twelve months ended June 30, 2015 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 increase in the average number of customers served and warmer weather, and from our large commercial and industrial customers due to an interruptible rate adjustment. For a complete discussion of non-fuel base revenues, see page 34.


(b)	Investment and interest income increased for the three 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 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 on long-term debt increased for the three and six months ended June 30, 2016 compared to the three and six months ended June 30, 2015, primarily due to interest on the $150 million of 5.00% senior notes issued in March 2016.



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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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Historical Results of Operations

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

Operating revenues

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

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, fuel costs will no longer be recovered through base rates. Beginning July 1, 2016, all fuel costs will be 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 base revenues” refers to our revenues from the sale of electricity excluding such fuel costs.

No retail customer accounted for more than 4% of our non-fuel base revenues. Residential and small commercial customers comprise 75% or more of our non-fuel base revenues. While this customer base is more stable, it is also more sensitive to changes in weather conditions. The current rate structures in 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, retail non-fuel base revenues were positively impacted by warmer weather when compared to the three, 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% when compared to the six months ended June 30, 2015, but were 6.9% below the 10-year average. For the 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. The table below shows heating and cooling degree days compared to a 10-year average.



	Three Months Ended			Six Months Ended			Twelve Months Ended
	June 30,			June 30,			June 30,
			10-Year			10-Year			10-Year
	2016	2015	Average	2016	2015	Average	2016	2015	Average*
Heating degree days	75	53	72	1,129	1,206	1,255	2,018	2,064	2,174
Cooling degree days	965	929	1,031	988	963	1,061	2,864	2,514	2,696

______________

* Calendar year basis.

Customer growth is a key driver of the growth of retail sales. The average number of retail customers grew 1.5% for both the three and six month periods ended June 30, 2016 when compared to the three and six months ended June 30, 2015, and 1.4% for the twelve months ended June 30, 2016 when compared to the twelve months ended June 30, 2015. See the tables presented on pages 36, 37, and 38, 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, 2016, when compared to the three months ended June 30, 2015. The increase in retail non-fuel base revenues includes a $3.3 million increase from sales to residential customers and a $0.8 million increase from sales to small commercial and industrial customers, reflecting increases of 1.5% in the average number of customers served for both categories, as well as warmer weather experienced 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 commercial and industrial customers decreased $0.6 million and $0.4 million, respectively, reflecting a 3.5% and 2.8% decrease in kWh sales.

Retail non-fuel base revenues increased $4.0 million, or 1.6%, for the six months ended June 30, 2016, when compared to the six months ended June 30, 2015. This includes a $4.0 million increase from sales 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, in the average number of customers served, as well as warmer weather in the second quarter of 2016. KWh sales to residential and small commercial and industrial customers increased by 3.8% and 1.5%, respectively. Retail non-fuel revenues from large commercial and industrial customers and sales to public authorities each decreased by $0.5 million, reflecting a 3.0% and 1.5% decrease in kWh sales, respectively.

Retail non-fuel base revenues increased $19.5 million, or 3.5%, for the twelve months ended June 30, 2016, when compared to the twelve months ended June 30, 2015. This includes a $15.0 million increase from sales to residential customers and a $3.0 million increase from sales to small commercial and industrial customers, reflecting increases of 1.4% 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 customers increased by 6.3% and 1.7%, respectively. Retail non-fuel revenues from large commercial and industrial customers increased $0.8 million, primarily due to an interruptible rate adjustment for a large customer. Retail non-fuel 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 in the third quarter of 2015 and second quarter of 2016.

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

In the three and six months ended June 30, 2016, we under-recovered our fuel costs by $6.1 million and $2.0 million, respectively. In the twelve months ended June 30, 2016, we over-recovered our fuel costs by $0.5 million. In May 2014, we implemented a 6.9% increase in our fixed fuel factor in Texas which was based upon a formula that reflects increases in prices for natural gas. On April 15, 2015, we filed a request, which was assigned PUCT Docket No. 44633, to reduce our fixed fuel factor by approximately 24% to reflect an expected reduction in fuel expense. The over-recovered balance was below the materiality threshold. The reduction in the fixed fuel factor was effective on an interim basis on May 1, 2015, and was approved by the PUCT on May 20, 2015. In September 2014, March 2015, and March 2016, $7.9 million, $5.8 million, and $1.6 million, respectively, were credited to customers through the applicable fuel adjustment clauses as the result of a reimbursement from the DOE related to spent nuclear fuel storage. At June 30, 2016, we had a net fuel over-recovery balance of $2.0 million, including an over-recovery of $1.1 million in New Mexico and $1.0 million in Texas and an under-recovery of $0.1 million for our FERC regulated customer.

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) and 50% of 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 million, or 26.6%, for the three months ended June 30, 2016, when compared to the three months ended June 30, 2015, as a result of lower average market prices for power and a 12.9% 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 million, or 30.6%, for the six months ended June 30, 2016, when compared to the six months ended June 30, 2015, as a result of lower average market prices for power and a 14.3% 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 million, or 28.7%, for the twelve months ended June 30, 2016, when compared to the twelve months ended June 30, 2015, as a result of lower average market prices for power and an 8.6% 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:	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

________________________________________


(1)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $1.9 million in 2016 and 2015.


(2)	Represents revenues with no related kWh sales.


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



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Comparisons of kWh sales and operating revenues are shown below (in thousands):
						Increase (Decrease)
Six Months Ended June 30:	2016		2015			Amount			Percent
kWh sales:
Retail:
Residential	1,248,120		1,202,593			45,527			3.8	%
Commercial and industrial, small	1,133,940		1,117,034			16,906			1.5
Commercial and industrial, large	515,834		531,942			(16,108		)	(3.0	)
Sales to public authorities	751,512		762,975			(11,463		)	(1.5	)
Total retail sales	3,649,406		3,614,544			34,862			1.0
Wholesale:
Sales for resale	32,509		32,449			60			0.2
Off-system sales	1,029,474		1,201,281			(171,807		)	(14.3	)
Total wholesale sales	1,061,983		1,233,730			(171,747		)	(13.9	)
Total kWh sales	4,711,389		4,848,274			(136,885		)	(2.8	)
Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	110,422	$	106,362		$	4,060		3.8	%
Commercial and industrial, small	86,847		85,834			1,013			1.2
Commercial and industrial, large	17,582		18,128			(546		)	(3.0	)
Sales to public authorities	42,072		42,575			(503		)	(1.2	)
Total retail non-fuel base revenues	256,923		252,899			4,024			1.6
Wholesale:
Sales for resale	1,195		1,129			66			5.8
Total non-fuel base revenues	258,118		254,028			4,090			1.6
Fuel revenues:
Recovered from customers during the period	48,753		63,371			(14,618		)	(23.1	)
Under (over) collection of fuel (1)	1,993		(10,832		)	12,825			—
New Mexico fuel in base rates	32,828		32,550			278			0.9
Total fuel revenues (2)	83,574		85,089			(1,515		)	(1.8	)
Off-system sales:
Fuel cost	16,890		23,284			(6,394		)	(27.5	)
Shared margins	3,407		6,252			(2,845		)	(45.5	)
Retained margins	573		520			53			10.2
Total off-system sales	20,870		30,056			(9,186		)	(30.6	)
Other (3)	13,112		14,081			(969		)	(6.9	)
Total operating revenues	$	375,674	$	383,254		$	(7,580	)	(2.0	)
Average number of retail customers (4):
Residential	360,929		355,625			5,304			1.5	%
Commercial and industrial, small	40,684		40,127			557			1.4
Commercial and industrial, large	49		50			(1		)	(2.0	)
Sales to public authorities	5,324		5,245			79			1.5
Total	406,986		401,047			5,939			1.5

________________________________________


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


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


(3)	Represents revenues with no related kWh sales.


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



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



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Energy expenses

Our sources of energy include electricity generated from our nuclear, natural gas and coal generating plants and purchased power. After adding the new natural gas generating units (MPS Units 1 & 2) in March 2015 and (MPS Unit 3) in May 2016 into the Company's system generation resources, Palo Verde represents approximately 30% of our net dependable generating capacity and approximately 51%, 58%, and 54% of our Company-generated energy for the three, six, and twelve months ended June 30, 2016, 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 million or 7.8% for the three months ended June 30, 2016, when compared to the three months ended June 30, 2015, primarily due to (i) decreased natural gas costs of $6.0 million due to a 17.4% decrease in the average price of natural gas, 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 million due to a 30.3% increase in the MWhs purchased.



	Three Months Ended June 30,
	2016					2015
Fuel Type	Cost		MWh	Cost per MWh		Cost		MWh	Cost per MWh
	(in thousands)					(in thousands)
Natural gas	$	29,387	1,032,439	$	28.46	$	35,349	1,025,980	$	34.45
Coal	2,893		82,143	35.22		3,600		173,427	20.76
Nuclear	10,863		1,165,459	9.32		10,864		1,203,902	9.02
Company-generated	43,143		2,280,041	18.92		49,813		2,403,309	20.73
Purchased power:
Photovoltaic	7,187		88,765	80.97		7,126		87,655	81.30
Other	6,423		239,329	26.84		4,616		164,194	28.11
Total purchased power	13,610		328,094	41.48		11,742		251,849	46.62
Total energy	$	56,753	2,608,135	21.76		$	61,555	2,655,158	23.18

Energy expenses decreased $9.7 million, or 8.8% for the six months ended June 30, 2016, when compared to the six months ended June 30, 2015, primarily due to (i) decreased natural gas costs of $13.6 million due to a 20.0% decrease in the average price of natural gas, and (ii) decreased coal costs of $1.2 million due to decreased generation. These decreases in energy expenses were partially offset by an increase in nuclear fuel expenses related to a $4.6 million reduction in the DOE refund in 2016 compared to the same period in 2015.



	Six Months Ended June 30,
	2016						2015
Fuel Type	Cost			MWh	Cost per MWh		Cost			MWh	Cost per MWh
	(in thousands)						(in thousands)
Natural gas	$	50,523		1,669,869	$	30.26	$	64,097		1,694,555	$	37.83
Coal	5,528			163,149	33.88		6,716			310,645	21.62
Nuclear	21,411		(a)	2,545,956	9.11		16,729		(a)	2,566,096	9.01
Company-generated	77,462			4,378,974	18.10		87,542			4,571,296	20.55
Purchased power:
Photovoltaic	12,695			156,529	81.10		11,929			146,714	81.31
Other	10,561			444,486	23.76		10,988			405,907	27.07
Total purchased power	23,256			601,015	38.69		22,917			552,621	41.47
Total energy	$	100,718		4,979,989	20.58		$	110,459		5,123,917	22.81

_______________

(a) Costs includes a DOE refund related to spent fuel storage of $1.8 million and $6.4 million recorded in March 2016 and 2015, respectively. Cost per MWh excludes these refunds.



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Energy expenses decreased $36.8 million, or 13.7% for the twelve months ended June 30, 2016, when compared to the twelve months ended June 30, 2015, primarily due to decreased natural gas costs of $50.0 million due to a 27.3% decrease in the average price of natural gas. The decrease in energy expenses was partially offset by (i) a $13.1 million reduction in DOE refund and (ii) increased purchased photovoltaic power costs of $1.4 million due to a 7.7% increase in MWhs purchased for the twelve months ended June 30, 2016 compared to the twelve months ended June 30, 2015.



	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

_____________

(a) Costs includes a DOE refund related to spent fuel storage of $1.8 million recorded 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 and in the third quarter of 2014, respectively. Cost per MWh excludes these refunds.

Other operations expense

Other operations expense decreased $0.8 million, or 1.5% for the three months ended June 30, 2016, 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 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 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 decrease 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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Depreciation and amortization expense

Depreciation and amortization expense increased $0.7 million or 3.1% 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 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, 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 decreased AEFUDC resulting from lower averages balances of CWIP and a reduction in the AEFUDC accrual rate, partially offset by (i) increased investment and interest income due to higher realized gains in our decommissioning trust funds in 2016 and (ii) decreased miscellaneous deductions due to reduced donations.

Interest charges (credits)

Interest charges (credits) increased by $1.7 million, or 12.3% for the three months ended June 30, 2016, compared to the three months ended June 30, 2015, primarily due to increased interest expense on the $150 million of 5.00% Senior Notes due 2044 issued in March 2016.

Interest charges (credits) increased by $3.3 million, or 12.1% for the six months ended June 30, 2016, compared to the six months ended June 30, 2015, 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.

Income tax expense

Income tax expense increased $1.9 million, or 20.5% for the three months ended June 30, 2016, compared to the three months ended June 30, 2015, primarily due to an increase in pre-tax income 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, primarily due to a decrease in pre-tax income.



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New Accounting Standards

In April 2015, the 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 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. 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.

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 common stock equity in our capital structure which supports our bond ratings, allowing us to obtain financing from the capital markets at a reasonable cost. At June 30, 2016, our capital structure, including common stock, long-term debt, current maturities of long-term debt, and short-term borrowings under the RCF, consisted of 42.3% common stock equity and 57.7% debt. At June 30, 2016, we had a balance of $9.6 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.

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.

Capital Requirements . During the six months ended June 30, 2016, our capital requirements primarily consisted of expenditures for the construction and purchase of electric utility plant, cash dividend payments, and purchases of nuclear fuel. Projected utility construction expenditures are to 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 approximat ely $81.3 millio n. 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 expenditures for new electric plant were $102.8 million in the six months ended June 30, 2016 compared to $147.0 million in the six months ended June 30, 2015. Capital requirements for purchases of nuclear fuel were $20.5 million for the six months ended June 30, 2016 compared to $22.4 million for the six months ended June 30, 2015.

On June 30, 2016, we paid a quarterly cash dividend of $0.31 per share, or $12.5 million, to shareholders of record as of the close of business on June 15, 2016. We paid a total of $24.5 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. At the current payout rate, we would expect to pay total cash dividends of approximately $49.6 million during 2016. In addition, while we do not currently anticipate repurchasing shares of our common stock in 2016, 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. As of June 30, 2016, a total of 393,816 shares remain eligible for repurchase under the program.

We will 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 due to accelerated tax deductions, including bonus depreciation, available in 2016.

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, we contributed $2.8 million and $1.1 million to our retirement plans and other post-retirement benefits plan, respectively, and $2.2 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 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



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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, we had an under-recovery 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. At June 30, 2016, we had a net fuel over-recovery balance of $2.0 million, including an over-recovery of $1.1 million in New Mexico and an over-recovery of $1.0 million in Texas and an under-recovery of $0.1 million in the FERC jurisdiction.

We maintain a 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, we amended and extended our $300 million RCF, which includes an option to expand the size to $400 million, upon the satisfaction of certain conditions including obtaining commitments from lenders or third party financial institutions. The amended facility extends the maturity from September 2016 to January 2019. In addition, we may extend the January 2019 maturity, subject to lenders' approval, by two additional one year periods. The total amount borrowed for nuclear fuel by RGRT, excluding debt issuance costs, was $129.6 million at June 30, 2016, of which $34.6 million had been borrowed under the RCF, and $95.0 million was borrowed through senior notes. As 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 outstanding balances for working capital and general corporate purposes, which may include funding capital expenditures, were $67.0 million and $110.0 million at June 30, 2016 and 2015, respectively.

We received approval from the NMPRC on October 7, 2015 and from the FERC on October 19, 2015, to issue up to $310 million in new long-term debt and to guarantee the issuance of up to $65 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 issued $150 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 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.

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 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 , 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 Form 10-K Annual Report.


Item 4.	Controls and Procedures

Evaluation of disclosure controls and procedures . Under the supervision and with the participation of our management, including our chief executive officer and our chief financial officer, we conducted an evaluation pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934 of our disclosure controls and procedures as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934. Based on that evaluation, our chief executive officer and our chief financial officer concluded that, as of June 30, 2016 , 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 , 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 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


Item 4.	Mine Safety Disclosures

Not Applicable.


Item 5.	Other Information

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


Item 6.	Exhibits

See Index to Exhibits incorporated herein by reference.



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SIGNATURES

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




	EL PASO ELECTRIC COMPANY

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

Dated: August 5, 2016



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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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Part I. Financial Information Item 1. Financial Statements Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II. Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 4. Mine Safety Disclosures Item 5. Other Information Item 6. Exhibits

EE 10-Q Quarter ended June 30, 2016