EE 10-K Annual Report Dec. 31, 2017

EE 10-K Fiscal year ended Dec. 31, 2017

Exhibits

Exhibits

EL PASO ELECTRIC CO /TX/

10-Ks and 10-Qs

10-Q	Quarter ended March 31, 2020
10-K	Fiscal year ended Dec. 31, 2019
10-Q	Quarter ended Sept. 30, 2019
10-Q	Quarter ended June 30, 2019
10-Q	Quarter ended March 31, 2019
10-K	Fiscal year ended Dec. 31, 2018
10-Q	Quarter ended Sept. 30, 2018
10-Q	Quarter ended June 30, 2018
10-Q	Quarter ended March 31, 2018
10-K	Fiscal year ended Dec. 31, 2017
10-Q	Quarter ended Sept. 30, 2017
10-Q	Quarter ended June 30, 2017
10-Q	Quarter ended March 31, 2017
10-K	Fiscal year ended Dec. 31, 2016
10-Q	Quarter ended Sept. 30, 2016
10-Q	Quarter ended June 30, 2016
10-Q	Quarter ended March 31, 2016
10-K	Fiscal year ended Dec. 31, 2015
10-Q	Quarter ended Sept. 30, 2015
10-Q	Quarter ended June 30, 2015
10-Q	Quarter ended March 31, 2015
10-K	Fiscal year ended Dec. 31, 2014
10-Q	Quarter ended Sept. 30, 2014
10-Q	Quarter ended June 30, 2014
10-Q	Quarter ended March 31, 2014
10-K	Fiscal year ended Dec. 31, 2013
10-Q	Quarter ended Sept. 30, 2013
10-Q	Quarter ended June 30, 2013
10-Q	Quarter ended March 31, 2013
10-K	Fiscal year ended Dec. 31, 2012
10-Q	Quarter ended Sept. 30, 2012
10-Q	Quarter ended June 30, 2012
10-Q	Quarter ended March 31, 2012
10-K	Fiscal year ended Dec. 31, 2011
10-Q	Quarter ended Sept. 30, 2011
10-Q	Quarter ended June 30, 2011
10-Q	Quarter ended March 31, 2011
10-K	Fiscal year ended Dec. 31, 2010
10-Q	Quarter ended Sept. 30, 2010
10-Q	Quarter ended June 30, 2010
10-Q	Quarter ended March 31, 2010
10-K	Fiscal year ended Dec. 31, 2009

PROXIES

DEF 14A	Filed on April 12, 2019
DEF 14A	Filed on April 13, 2018
DEF 14A	Filed on April 14, 2017
DEF 14A	Filed on April 15, 2016
DEF 14A	Filed on April 17, 2015
DEF 14A	Filed on April 18, 2014
DEF 14A	Filed on March 26, 2013
DEF 14A	Filed on April 20, 2012
DEF 14A	Filed on April 15, 2011
DEF 14A	Filed on April 16, 2010

10-K 1 a201710-k.htm FORM 10-K Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________________

Form 10-K

(Mark One)



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

For the fiscal year ended December 31, 2017



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

For the transition period from to

Commission file number 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)

Registrant’s telephone number, including area code: (915) 543-5711

Securities Registered Pursuant to Section 12(b) of the Act:



Title of each class		Name of each exchange on which registered
Common Stock, No Par Value		New York Stock Exchange

Securities Registered Pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES x NO ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES ¨ NO x

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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 ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 126-2 of the Exchange Act.



Large accelerated filer	x	Accelerated filer	o
Non-accelerated filer	o (Do not check if a smaller reporting company)	Smaller reporting company	o
		Emerging growth company	o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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

As of June 30, 2017 , the aggregate market value of the voting stock held by non-affiliates of the registrant was $2,069,728,021 (based on the closing price as quoted on the New York Stock Exchange on that date).

As of January 31, 2018 , there were 40,661,003 shares of the Company’s no par value common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive Proxy Statement for the 2018 annual meeting of its shareholders are incorporated by reference into Part III of this report.

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DEFINITIONS

The following abbreviations, acronyms or defined terms used in this report are defined below:



Abbreviations, Acronyms or Defined Terms		Terms

ANPP Participation Agreement		Arizona Nuclear Power Project Participation Agreement dated August 23, 1973, as amended
APS		Arizona Public Service Company
ASU		Accounting Standards Update
Company		El Paso Electric Company
Copper		The Company's Copper Power Station
DOE		United States Department of Energy
El Paso		City of El Paso, Texas
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
Fort Bliss		Fort Bliss, the United States Army post next to El Paso, Texas
Four Corners		Four Corners Generating Station
GHG		Greenhouse gas
HAFB		Holloman Air Force Base
IRS		Internal Revenue Service
kV		Kilovolt(s)
kW		Kilowatt(s)
kWh		Kilowatt-hour(s)
Las Cruces		City of Las Cruces, New Mexico
MPS		The Company's Montana Power Station
MW		Megawatt(s)
MWh		Megawatt-hour(s)
Net dependable generating capability		The maximum load net of plant operating requirements that a generating plant can supply under specified conditions for a given time interval, without exceeding approved limits of temperature and stress
Newman		The Company's Newman Power Station
NMPRC		New Mexico Public Regulation Commission
NRC		Nuclear Regulatory Commission
Palo Verde		Palo Verde Generating Station
Palo Verde Participants		Those utilities that share in power and energy entitlements, and bear certain allocated costs, with respect to Palo Verde pursuant to the ANPP Participation Agreement
PNM		Public Service Company of New Mexico
PUCT		Public Utility Commission of Texas
RGEC		Rio Grande Electric Cooperative
RGRT		Rio Grande Resources Trust
Rio Grande		The Company's Rio Grande Power Station
TCJA		The Federal Tax Cuts and Jobs Act of 2017
TEP		Tucson Electric Power Company
White Sands		White Sands Missile Range



	( i )

Table of Contents

TABLE OF CONTENTS




Item	Description	Page
	PART I
1	Business	1
1A	Risk Factors	17
1B	Unresolved Staff Comments	24
2	Properties	24
3	Legal Proceedings	24
4	Mine Safety Disclosures	24


	PART II
5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25
6	Selected Financial Data	27
7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
7A	Quantitative and Qualitative Disclosures About Market Risk	49
8	Financial Statements and Supplementary Data	51
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	112
9A	Controls and Procedures	112
9B	Other Information	112

	PART III
10	Directors, Executive Officers and Corporate Governance	113
11	Executive Compensation	114
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	114
13	Certain Relationships and Related Transactions, and Director Independence	114
14	Principal Accounting Fees and Services	114

	PART IV
15	Exhibits and Financial Statement Schedules	115
16	Form 10-K Summary	121



	( ii )

Table of Contents

FORWARD-LOOKING STATEMENTS

Certain matters discussed in this Annual Report on Form 10-K, other than statements of historical fact, 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 Exchange 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 are indicated by the Company's discussion of strategies or trends. Forward-looking statements describe the Company's future plans, objectives, expectations or goals. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, no assurances can be given that these expectations will prove to be correct. Such statements address future events and conditions and include, but are not limited to:


•	capital expenditures,


•	earnings,


•	liquidity and capital resources,


•	ratemaking/regulatory matters,


•	litigation,


•	accounting matters, including accounting for taxes,


•	possible corporate restructurings, acquisitions and dispositions,


•	compliance with debt and other restrictive covenants,


•	interest rates and dividends,


•	environmental matters,


•	nuclear operations,


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


•	the overall economy of our service area.

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


•	actions of the Company's regulators,


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


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


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


•	reductions in output at generation plants operated by the Company,


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


•	the Company's reliance on significant customers,


•	the credit worthiness of the Company's customers,


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


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



	( iii )

Table of Contents


•	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, pension and other post-retirement and post-employment benefit liability calculations, as well as actual and assumed investment returns on pension plan and other post-retirement plan assets,


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


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


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


•	electric utility deregulation or re-regulation,


•	regulated and competitive markets,


•	ongoing municipal, state and federal activities,


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


•	political, legislative, judicial and regulatory developments,


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


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


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


•	actions by credit rating agencies,


•	changes in accounting requirements and other accounting matters,


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


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


•	the impact of lawsuits filed against the Company,


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


•	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 ("IRS") or state taxing authorities,


•	the impact of recent changes to U.S. tax laws,


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


•	the effectiveness of the Company's risk management activities,


•	loss of key personnel, the Company's ability to recruit and retain qualified employees and the Company's ability to successfully implement succession planning, and


•	other circumstances affecting anticipated operations, sales and costs.

These lists are not all-inclusive because it is not possible to predict all factors. A discussion of some of these factors is included in this document under the headings "Risk Factors" and "Management’s Discussion and Analysis of Financial Condition and Results of Operations –Summary of Critical Accounting Policies and Estimates" and "Management’s Discussion and Analysis of Financial Condition and Results of Operations –Liquidity and Capital Resources." This Annual Report on Form 10-K 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 statement speaks only as of the date



	( iv )

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such statement was made, and the Company is not obligated to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made, except as required by applicable laws or regulations.



	( v )

Table of Contents

PART I


Item 1.	Business

General

El Paso Electric Company (the "Company") is a public utility engaged in the generation, transmission and distribution of electricity in an area of approximately 10,000 square miles in west Texas and southern New Mexico. The Company also serves a full requirements wholesale customer in Texas. The Company owns or has significant ownership interests in several electrical generating facilities providing it with a net dependable generating capacity of approximately 2,082 MW. For the year ended December 31, 2017, the Company’s energy sources consisted of approximately 49% nuclear fuel, 36% natural gas, 15% purchased power and less than 1% generated by Company-owned solar photovoltaic panels. The Company continues to expand its portfolio of renewable energy sources, particularly solar photovoltaic generation. As of December 31, 2017, the Company had power purchase agreements for 107 MW from solar photovoltaic generation facilities. (See "Energy Sources – Purchased Power").

The Company serves approximately 417,900 residential, commercial, industrial, public authority and wholesale customers. The Company distributes electricity to retail customers principally in El Paso, Texas and Las Cruces, New Mexico (representing approximately 64% and 11%, respectively, of the Company’s retail revenues for the year ended December 31, 2017). In addition, the Company’s wholesale sales include sales for resale to other electric utilities and power marketers. Principal industrial, public authority and other large retail customers of the Company include United States military installations, such as Fort Bliss in Texas and White Sands Missile Range ("White Sands") and Holloman Air Force Base ("HAFB") in New Mexico, an oil refinery, several medical centers, two large universities and a steel production facility.

The Company’s principal offices are located at the Stanton Tower, 100 North Stanton, El Paso, Texas 79901 (telephone: 915-543-5711). The Company was incorporated in Texas in 1901. As of January 31, 2018, the Company had approximately 1,100 employees, 38% of whom are covered by a collective bargaining agreement.

The Company makes available free of charge through its website, www.epelectric.com , its Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statement and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission ("SEC"). In addition, copies of this Annual Report on Form 10-K will be made available free of charge upon written request. The SEC also maintains an internet site that contains reports, proxy and information statements and other information for issuers that file electronically with the SEC. The address of that site is www.sec.gov . The information on the Company's website is not incorporated by reference into this Annual Report on Form 10-K.

Facilities

As of December 31, 2017, the Company’s net dependable generating capability of approximately 2,082 MW consists of the following:



Station	Primary Fuel Type	Company's Share of Net Dependable Generating Capability* (MW)	Company Ownership Interest		Location
Newman Power Station	Natural Gas	752	100	%	El Paso, Texas
Palo Verde	Nuclear	633	15.8	%	Wintersburg, Arizona
Rio Grande Power Station	Natural Gas	276	100	%	Sunland Park, New Mexico
Montana Power Station (Units 1, 2, 3 and 4)	Natural Gas	354	100	%	El Paso, Texas
Copper Power Station	Natural Gas	64	100	%	El Paso, Texas
Renewables	Solar	3	100	%	Culberson/El Paso Counties, Texas; Dona Ana County, New Mexico
Total		2,082

________________

* During summer peak period.

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Palo Verde

The Company owns an interest, along with six other utilities, in the three nuclear generating units and common facilities ("Common Facilities") at Palo Verde. Arizona Public Service Company ("APS") serves as operating agent for Palo Verde, and under the Arizona Nuclear Power Project Participation Agreement ("ANPP Participation Agreement"), the Company has limited ability to influence operations and costs at Palo Verde.

•

Palo Verde Operating Licenses. Operation of each of the three Palo Verde Units requires an operating license from the Nuclear Regulatory Commission ("NRC"). The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987 and issued renewed operating licenses for each of the three units in April 2011, which extended the licenses for Units 1, 2 and 3 to June 2045, April 2046 and November 2047, respectively.

•

Decommissioning . Pursuant to the ANPP Participation Agreement and federal law, the Company must fund its share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities, through the term of their respective operating licenses. In 2017, the Palo Verde Participants approved the 2016 Palo Verde decommissioning study (the "2016 Study"), which estimated that the Company must fund approximately $432.8 million (stated in 2016 dollars) to cover its share of decommissioning costs. At December 31, 2017 , the Company's decommissioning trust fund had a balance of $286.9 million . Although the 2016 Study was based on the latest available information, there can be no assurance that decommissioning cost estimates will not increase in the future or that regulatory requirements will not change.

• Spent Fuel and Waste Disposal . Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "NWPA"), the United States Department of Energy ("DOE") is legally obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive waste generated by all domestic power reactors by 1998. The DOE's obligations are reflected in a contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (the "Standard Contract") with each nuclear power plant. The DOE failed to begin accepting spent nuclear fuel by 1998. On December 19, 2012, 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. Pursuant to the terms of the August 18, 2014 settlement agreement, APS files annual claims for the period July 1 of the then-previous year to June 30 of the then-current year. The settlement agreement, as amended, provides APS with a method for submitting claims and receiving recovery for costs incurred through December 31, 2016, which has been extended to December 31, 2019. The Company's share of costs recovered are presented below (in thousands):



			Amount Credited
			to Customers
			through Fuel		Period Credited
Costs Recovery Period	Amount Refunded		Adjustment Clauses		to Customers

January 2007 - June 2011	$	9,076	$	7,944	September 2014
July 2011 - June 2014	6,643		5,759		March 2015
July 2014 - June 2015	1,884		1,581		March 2016
July 2015 - June 2016	1,779		1,432		March 2017

On October 31, 2017, APS filed an $8.9 million claim for the period July 1, 2016 through June 30, 2017 . The Company's share of this claim is approximately $1.4 million . In February 2018, the DOE approved this claim. Any reimbursement is anticipated to be received in the first half of 2018, and the majority of the reimbursement received by the Company is expected to be credited to customers through the applicable fuel adjustment clauses.

•

DOE’s Construction Authorization Application for Yucca Mountain. The DOE had planned to meet its disposal obligations by designing, licensing, constructing and operating a permanent geologic repository in Yucca Mountain, Nevada. In March 2010, the DOE filed a motion to dismiss with prejudice its Yucca Mountain construction authorization application that was pending before the NRC. Several interested parties have intervened in the NRC proceeding. Additionally, a number of interested parties have filed a variety of lawsuits in different jurisdictions around the country challenging the DOE's authority to withdraw the Yucca Mountain

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construction authorization application and NRC’s cessation of its review of the Yucca Mountain construction authorization application. The cases have been consolidated into one matter at the U.S. Court of Appeals for the District of Columbia Circuit (the "D.C. Circuit"). In August 2013, the D.C. Circuit ordered the NRC to resume its review of the application with available appropriated funds.

On October 16, 2014, the NRC issued Volume 3 of the safety evaluation report developed as part of the Yucca Mountain construction authorization application. This volume addresses repository safety after permanent closure, and the issuance of Volume 3 is a key milestone in the Yucca Mountain licensing process. Volume 3 contains the NRC staff’s finding that the DOE’s repository design meets the requirements that apply after the repository is permanently closed, including but not limited to the post-closure performance objectives in the NRC’s regulations.

On December 18, 2014, the NRC issued Volume 4 of the safety evaluation report developed as part of the Yucca Mountain construction authorization application. This volume covers administrative and programmatic requirements for the repository. It documents the NRC staff’s evaluation of whether the DOE’s research and development and performance confirmation programs, as well as other administrative controls and systems, meet applicable NRC requirements. Volume 4 contains the NRC staff’s finding that most administrative and programmatic requirements in NRC regulations are met, except for certain requirements relating to ownership of land and water rights.

Publication of Volumes 3 and 4 does not signal whether or when the NRC might authorize construction of the repository. The Company cannot predict when spent fuel shipments to the DOE will commence.

•

Waste Confidence and Continued Storage. On June 8, 2012, the D.C. Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high level nuclear waste and spent nuclear fuel. The petitioners challenged the NRC’s 2010 update to the agency’s Waste Confidence Decision and temporary storage rule ("Waste Confidence Decision").

The D.C. Circuit found that the agency’s 2010 Waste Confidence Decision update constituted a major federal action, which, consistent with the National Environmental Policy Act ("NEPA"), requires either an environmental impact statement or a finding of no significant impact from the agency’s actions. The D.C. Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded the 2010 Waste Confidence Decision update for further action consistent with NEPA.

On September 6, 2012, the NRC Commissioners issued a directive to the NRC staff to proceed directly with development of a generic environmental impact statement to support an updated Waste Confidence Decision. The NRC Commissioners also directed the NRC staff to establish a schedule to publish a final rule and environmental impact study within 24 months of September 6, 2012.

In September 2013, the NRC issued its draft Generic Environmental Impact Statement ("GEIS") to support an updated Waste Confidence Decision. On August 26, 2014, the NRC approved a final rule on the environmental effects of continued storage of spent nuclear fuel. Renamed the Continued Storage Rule, the NRC's decision adopted the findings of the GEIS regarding the environmental impacts of storing spent fuel at any reactor site after the reactor’s licensed period of operations. As a result, those generic impacts do not need to be re-analyzed in the environmental reviews for individual licenses. Although Palo Verde has not been involved in any licensing actions affected by the D.C. Circuit’s June 8, 2012 decision, the NRC lifted its suspension on final licensing actions on all nuclear power plant licenses and renewals that went into effect when the D.C. Circuit issued its June 2012 decision. The final Continued Storage Rule was subject to continuing legal challenges before the NRC and the Court of Appeals. In June 2016, the D.C. Circuit issued its final decision, rejecting all remaining legal challenges to the Continue Storage Rule. On August 8, 2016, the D.C. Circuit denied a petition for rehearing.

Palo Verde has sufficient capacity at its on-site independent spent fuel storage installation ("ISFSI") to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027. Additionally, Palo Verde has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047. If uncertainties regarding the United States government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation.

The One-Mill Fee. In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged the DOE’s 2010 determination of the adequacy of the one tenth of a cent per kWh

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fee (the "one-mill fee") paid by the nation’s commercial nuclear power plant owners pursuant to their individual obligations under the Standard Contract. This fee was recovered by the Company through applicable fuel adjustment clauses. In June 2012, the D.C. Circuit held that the DOE failed to conduct a sufficient fee analysis in making the 2010 determination. The D.C. Circuit remanded the 2010 determination to the Secretary of the DOE (the "Secretary") with instructions to conduct a new fee adequacy determination within six months. In February 2013, upon completion of the DOE’s revised one-mill fee adequacy determination, the court reopened the proceedings. On November 19, 2013, the D.C. Circuit ordered the Secretary to notify Congress of his intent to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators, as he is required to do pursuant to the NWPA and the court’s order. On January 3, 2014, the Secretary notified Congress of his intention to suspend collection of the one-mill fee, subject to Congress’ disapproval and on May 16, 2014, the DOE notified all commercial nuclear power plant operators, effective May 16, 2014, the one-mill fee was suspended. Electricity generated at Palo Verde and sold on or after May 16, 2014 is no longer subjected to the one-mill fee.

•

NRC Oversight of the Nuclear Energy Industry in the Wake of the Earthquake and Tsunami in Japan . The NRC regulates the operation of all commercial nuclear power reactors in the United States, including Palo Verde. The NRC periodically conducts inspections of nuclear facilities and monitors performance indicators to enable the agency to arrive at objective conclusions about a licensee's safety performance. Following the March 11, 2011 earthquake and tsunami in Japan, the NRC established a task force to conduct a systematic and methodical review of NRC processes and regulations to determine whether the agency should make additional improvements to its regulatory system. On March 12, 2012, the NRC issued the first regulatory requirements based on the recommendations of the NRC's Near Term Task Force. With respect to Palo Verde, the NRC issued two orders requiring safety enhancements regarding: (1) mitigation strategies to respond to extreme natural events resulting in the loss of power at plants and (2) enhancement of spent fuel pool instrumentation.

The NRC has issued a series of interim staff guidance documents regarding implementation of these requirements. Palo Verde has met the NRC's imposed deadlines for the installation of equipment to address these requirements. Palo Verde has spent approximately $125.4 million (the Company's share is $19.8 million ) on capital enhancements related to these requirements as of December 31, 2017.

•

Liability and Insurance Matters . The Palo Verde Participants have insurance for public liability resulting from nuclear energy hazards, covered by primary liability insurance provided by commercial insurance carriers and an industry-wide retrospective assessment program. If a loss at a nuclear power plant covered by the programs exceeds the accumulated funds in the primary level of protection, the Company could be assessed retrospective premium adjustments on a per incident basis up to $60.4 million , with an annual payment limitation of approximately $9.0 million . The Palo Verde Participants also maintain $2.75 billion of "all risk" nuclear property insurance. The insurance provides coverage for property damage and decontamination at Palo Verde. For covered incidents involving property damage not accompanied by a release of radioactive material, the policy's coverage limit is $2.25 billion . In addition, the Company has secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage at Palo Verde.

Fossil-Fueled Plants

The Newman Power Station ("Newman") consists of three conventional steam-electric generating units and two combined cycle generating units. The station operates primarily on natural gas but the conventional steam-electric generating units can also operate on fuel oil.

The Company's Rio Grande Power Station ("Rio Grande") consists of three conventional steam-electric generating units and one aeroderivative unit that operate on natural gas.

The Company's Montana Power Station ("MPS") consists of four aeroderivative generating units which operate on natural gas. The units can also operate on fuel oil.

The Company's Copper Power Station ("Copper") consists of a natural gas combustion turbine used primarily to meet peak demand.

The Company owned a 7% interest in Units 4 and 5 at Four Corners Generating Station ("Four Corners"). The Company shared power entitlements and certain allocated costs of the two units with APS (the Four Corners operating agent) and the other Four Corners participants. On July 6, 2016, the Company sold its interests in Four Corners for $32.0 million to 4C Acquisition, LLC, an affiliate of APS ("APS's affiliate"), and Pinnacle West Capital Corporation ("Pinnacle West"), the parent company of APS

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and APS's affiliate. No significant gain or loss was recorded for this sale. APS's affiliate assumed responsibility for all Four Corners capital expenditures made after July 6, 2016, which assumption is guaranteed by Pinnacle West. In addition, APS's affiliate will indemnify the Company against certain liabilities and costs related to the future operation of Four Corners, which indemnification is guaranteed by Pinnacle West. See Part II, Item 8, Financial Statements and Supplementary Data, Note C and Note E of Notes to Financial Statements for further discussions.

Solar Photovoltaic Facilities

The Company’s Texas Community solar facility, a 3 MW utility-scale solar plant located at MPS, began commercial operations on May 31, 2017. The Company also owns six other solar photovoltaic facilities with a total capacity of 0.2 MW.

Transmission and Distribution Lines and Agreements

The Company owns, or has significant ownership interests in, four 345 kV transmission lines in New Mexico and Arizona and three 500 kV lines in Arizona. These lines enable the Company to deliver its energy entitlements from its remote generation at Palo Verde to its service area (pursuant to various transmission and power exchange agreements to which the Company is a party). The Company also owns the transmission and distribution network within its New Mexico and Texas retail service area and operates these facilities under franchise agreements with various municipalities. Pursuant to standards established by the North American Electric Reliability Corporation and the Western Electricity Coordinating Council, the Company operates its transmission system in a way that allows it to maintain system integrity in the event that any one of these transmission lines is out of service.

In addition to the transmission and distribution lines within our service territory, the Company's transmission network and associated substations include the following:



Line	Length (miles)	Voltage (kV)	Company Ownership Interest
Springerville-Macho Springs-Luna-Diablo Line (1)	310	345	100.0	%
West Mesa-Arroyo Line (2)	202	345	100.0	%
Greenlee-Hidalgo-Luna-Newman Line (3)
Greenlee-Hidalgo	60	345	40.0	%
Hidalgo-Luna	50	345	57.2	%
Luna-Newman	86	345	100.0	%
Eddy County-AMRAD Line (4)	125	345	66.7	%
Palo Verde Transmission
Palo Verde-Westwing (5)	45	500	18.7	%
Palo Verde-Jojoba-Kyrene (6)	75	500	18.7	%

____________________


(1)	Runs from Tucson Electric Power Company's ("TEP") Springerville Generating Plant near Springerville, Arizona, to the Company's Diablo Substation near Sunland Park, New Mexico.


(2)	Runs from Public Service Company of New Mexico ("PNM") West Mesa Substation located near Albuquerque, New Mexico, to the Company's Arroyo Substation located near Las Cruces, New Mexico.


(3)	Runs from TEP's Greenlee Substation located near Duncan, Arizona to Newman.

(4) Runs from the Company's and PNM's high voltage direct current terminal at the Eddy County Substation near Artesia, New Mexico to the AMRAD Substation near Oro Grande, New Mexico.


(5)	Represents two 45-mile, 500 kV lines running from Palo Verde to the Westwing Substation located northwest of Phoenix near Peoria, Arizona.

(6) Runs from Palo Verde to the Jojoba Substation located near Gila Bend, Arizona, then to the Kyrene Substation located near Tempe, Arizona.

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Environmental Matters

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

In March 2017, the Company entered into a Compliance Agreement ("Compliance Agreement") with the Texas Commission on Environmental Quality under the Texas Environmental, Health and Safety Audit Privilege Act to address certain water and waste compliance issues associated with the integrity of the synthetic liner of the evaporation pond at the Company’s Newman Generating Station. The Company has initiated a capital project to extend the life of evaporation pond and in doing so will complete its obligation of the Compliance Agreement.

Air Emissions. The U.S. Clean Air Act ("CAA"), associated regulations and comparable state and local laws and regulations relating to air emissions impose, among other obligations, limitations on pollutants generated during the operations of the Company's facilities and assets, including sulfur dioxide ("SO2"), particulate matter ("PM"), nitrogen oxides ("NOx") and mercury.

National Ambient Air Quality Standards ( " NAAQS ") . Under the CAA, the EPA sets NAAQS for six criteria pollutants considered harmful to public health and the environment, including 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 primary annual NAAQS for fine PM. On October 1, 2015, the 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.The EPA may designate the areas in which we operate as nonattainment. For example, in December 2017, EPA proposed to designate southern Dona Ana County, New Mexico, as a nonattainment area. States that contain any areas designated as nonattainment, and any tribes that choose to do so, will 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.

Other Laws and Regulations and Risks . The Company sold its interest in Four Corners to APS's affiliate on July 6, 2016 at the expiration of the 50-year participation agreement. As of the closing date of the sale, the Company’s environmental liabilities associated with Four Corners were limited to conditions that existed at the time of the sale and further limited to the portion thereof for which the Company would have been financially responsible if Four Corners had fully ceased operation on July 6, 2016. Pursuant to the terms of the Purchase and Sale Agreement, neither APS's affiliate nor APS assumed the Company's pre-closing obligations under environmental laws with respect to its interest in Four Corners. The Company may be subject to certain future claims under environmental laws and regulations as a former owner of Four Corners. The extent of such claims, if any, cannot be predicted with certainty.

Climate Change. There has been a wide-ranging policy debate, at the local, state, national, and international levels, regarding the impact of GHG and possible means for their regulation. Efforts continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. In April 2016, the United States signed the Paris Agreement, which requires countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. In August 2017, the United States formally documented to the United Nations its intent to withdraw from the Paris Agreement. The earliest possible effective withdrawal date from the Paris Agreement is November 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 October 2015, the EPA published a rule establishing guidelines for states to regulate CO2 emissions from existing power plants, known as the Clean Power Plan ("CPP"). Legal challenges to the CPP are ongoing. The Company cannot at this time determine the impact of the CPP, related proposals and legal challenges may have on our financial position, results of operations or cash flows.

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While a significant portion of the Company's generation assets are nuclear or gas-fired, and as a result, the Company believes that its GHG emissions are low relative to electric power companies who rely more on coal-fired generation, current and future legislation and regulation of GHG or any future related litigation could impose significant costs and/or operating restrictions on the Company, reduce demand for the power the Company generates, and/or require the Company to purchase rights to emit GHG, any of which could be material to the Company's business, reputation, financial condition or results of operations.

Climate change also has potential physical effects that could be relevant to the Company's business. In particular, climate change could affect the Company's service area by causing higher temperatures, less winter precipitation and less spring runoff, as well as by causing more extreme weather events. Such developments could change the demand for power in the region and could also impact the price or ready availability of water supplies or affect maintenance needs and the reliability of Company equipment. The Company believes that material effects on the Company's business or results of operations may result from the physical consequences of climate change, the regulatory approach to climate change ultimately selected and implemented by governmental authorities, or both. Given the very significant remaining uncertainties regarding whether and how these issues will be regulated, as well as the timing and severity of any physical effects of climate change, the Company believes it is impossible to meaningfully quantify the costs of these potential impacts at present.

Environmental Litigation and Investigations . Since July 2011, the U.S. Department of Justice (the "DOJ"), on behalf of the EPA, and APS have been engaged in substantive settlement negotiations in an effort to resolve certain of the pending matters. The allegations being addressed through settlement negotiations are that APS failed to obtain the necessary permits and install the controls necessary under the CAA to reduce SO2, NOx, and PM , and that defendants failed to obtain an operating permit under Title V of the CAA that reflects applicable requirements imposed by law. On June 24, 2015, the parties filed with the U.S. District Court for New Mexico a settlement agreement ("CAA Settlement Agreement") resolving this matter. On August 17, 2015, the U.S. District Court for New Mexico entered the CAA Settlement Agreement. The agreement imposes a total civil penalty payable by the co-owners of Four Corners collectively in the amount of $1.5 million , and it requires the co-owners to pay $6.7 million for environmental mitigation projects. At December 31, 2017, the Company has accrued its remaining unpaid share of approximately $0.2 million related to this matter.

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Construction Program

Utility construction expenditures reflected in the following table consist primarily of local generation, expanding and updating the transmission and distribution systems, the cost of capital improvements and replacements at Palo Verde and other generating facilities, and other property and equipment. Studies indicate that the Company will need additional power generation resources to meet increasing load requirements on its system and to replace retiring plants and terminated purchased power agreements, the costs of which are included in the table below.

The Company’s estimated cash construction costs for 2018 through 2022 are approximately $1.3 billion. Actual costs may vary from the construction program estimates shown. Such estimates are under continuous review and subject to ongoing adjustment and are updated periodically to reflect changed conditions.



By Year (1)(2) (estimates in millions)			By Function (estimates in millions)
2018	$	236	Production (1)(2)	$	551
2019	238		Transmission	183
2020	278		Distribution	430
2021	298		General	139
2022	253
Total	$	1,303	Total	$	1,303

__________________________


(1)	Does not include acquisition costs for nuclear fuel. See "Energy Sources – Nuclear Fuel."


(2)	Estimated production costs consist of:


a.	$320 million for new generating capacity, primarily including:


i.	$305 million of construction costs from 2018 through 2022 for a 320 MW combined cycle generating plant scheduled to be completed in 2023.


ii.	$13 million for two utility-scale solar energy generating facilities which would have a combined maximum capacity of up to 7 MW.


b.	$231 million of other generation costs, including $184 million for Palo Verde.

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Energy Sources

General

The following table summarizes the percentage contribution of nuclear fuel, natural gas, coal and purchased power to the total kWh energy mix of the Company. Energy generated by Company-owned solar photovoltaic panels and wind turbines accounted for less than 1% of the total kWh energy mix of the Company.



	Years Ended December 31,
	2017		2016		2015
Power Source	(percentage of total kWh energy mix)
Nuclear	49	%	49	%	47	%
Natural gas	36	%	34	%	34	%
Coal	—	%	2	%	6	%
Purchased power	15	%	15	%	13	%
Total	100	%	100	%	100	%

Allocated fuel and purchased power costs are generally recoverable from customers in Texas and New Mexico pursuant to applicable regulations. Historical fuel costs and revenues are reconciled periodically in proceedings before the Public Utility Commission of Texas ("PUCT") and the New Mexico Public Regulation Commission ("NMPRC"). See "Regulation – Texas Regulatory Matters" and "Regulation – New Mexico Regulatory Matters."

Nuclear Fuel

The nuclear fuel cycle for Palo Verde consists of the following stages: the mining and milling of uranium ore to produce uranium concentrates, the conversion of the uranium concentrates to uranium hexafluoride ("conversion services"), the enrichment of uranium hexafluoride ("enrichment services"), the fabrication of fuel assemblies ("fabrication services"), the utilization of the fuel assemblies in the reactors, and the storage and disposal of the spent fuel.

Pursuant to the ANPP Participation Agreement, the Company owns an undivided interest in nuclear fuel purchased in connection with Palo Verde. The Palo Verde Participants are continually identifying their future nuclear fuel resource needs and negotiating arrangements to fill those needs. The Palo Verde Participants have contracted for 100% of Palo Verde's requirements for uranium concentrates through 2023 and 50% of its requirements for 2024 through 2025. The participants have contracted for 100% of Palo Verde's requirement for conversion services through 2021 and 46% of its requirements for 2022 through 2025. The participants have also contracted for 100% of Palo Verde's requirement for enrichment services through 2020 and 20% of its requirement for 2021 through 2026 and all of Palo Verde's requirement for fuel assembly fabrication services through 2024.

Nuclear Fuel Financing . The Company’s financing of nuclear fuel is accomplished through Rio Grande Resources Trust ("RGRT"), a Texas grantor trust, which is consolidated in the Company’s financial statements. As of December 31, 2017, RGRT has $45 million aggregate principal amount borrowed in the form of senior notes. In August 2017, RGRT's $50 million Series B 4.47% Senior Notes matured and were paid utilizing funds borrowed under the revolving credit facility (the "RCF"). T he Company guarantees the payment of principal and interest on the senior notes. The nuclear fuel financing requirements of RGRT are met with a combination of the senior notes and short-term borrowings under the RCF.

Natural Gas

The Company manages its natural gas requirements through a combination of a long-term (greater than a year) supply contract, several medium-term (greater than a month but less than one year) supply contracts and spot or short-term (daily to a month) market purchases. The long-term supply contract provides for firm deliveries of gas at market-based index prices. Medium-term and spot agreements are either fixed priced and/or index priced depending on the market. In 2017, the Company’s natural gas requirements at Newman, Rio Grande and MPS were met with short-term, medium-term and long-term natural gas purchases from various suppliers, and this practice is expected to continue in 2018. Interstate gas is delivered under a base firm transportation contract. The Company has expanded its firm interstate transportation contract to include MPS. The Company anticipates it will continue to purchase natural gas at spot market prices on a monthly basis for a portion of the fuel needs for Newman, Rio Grande and MPS. The Company will continue to evaluate the availability of short-term natural gas supplies versus medium and long-term supplies to maintain a reliable and economical supply for its local generating stations.

Natural gas for Newman and Copper is also supplied pursuant to a long-term intrastate natural gas contract that became effective October 1, 2009 and continues through March 31, 2018. Beginning April 1, 2018, intrastate natural gas reservation and storage for Newman, Copper and MPS will be provided through a new contract that will continue through March 31, 2028. Under

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this new contract, intrastate gas supply will be sourced in the same manner as interstate gas, through a variety of long, medium and short-term supply contracts.

Purchased Power

To supplement its own generation and operating reserve requirements, and to meet required renewable portfolio standards, the Company engages in power purchase arrangements that 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.

The Company has a firm 100 MW Power Purchase and Sale Agreement (the "Power Purchase and Sale Agreement") with Freeport-McMoran Copper and Gold Energy Services LLC ("Freeport"), pursuant to which Freeport will deliver energy to the Company from the Luna Energy Facility (a natural gas-fired combined cycle generation facility located in Luna County, New Mexico) and the Company will deliver a like amount of energy at Greenlee, Arizona. The Company may purchase up to the contracted MW amount at a specified price at times when energy is not exchanged under the Power Purchase and Sale Agreement. The Power Purchase and Sale Agreement was approved by the Federal Energy Regulatory Commission ("FERC") and will continue through an initial term ending December 31, 2021 , with subsequent rollovers until terminated. Upon mutual agreement, the Power Purchase and Sale Agreement allows the parties to increase the amount of energy that is purchased and sold thereunder. The parties have agreed to increase the amount up to 125 MW through December 2018.

The Company has entered into several power purchase agreements to help meet its renewable portfolio requirements. Specifically, the Company has a 25 -year purchase power agreement with Hatch Solar Energy Center I, LLC for a 5 MW solar photovoltaic project located in southern New Mexico, which began commercial operation in July 2011 . In June 2015, the Company entered into a consent agreement with Hatch Solar Energy Center 1, LLC to provide for additional or replacement photovoltaic modules. The Company also entered into a 20 -year contract with NRG Solar Roadrunner, LLC ("NRG") for the purchase of all of the output of a 20 MW solar photovoltaic plant built in southern New Mexico, which began commercial operation in August 2011 . In addition, the Company has 25 -year purchase power agreements to purchase all of the output of two additional solar photovoltaic projects located in southern New Mexico, SunE EPE1, LLC (10 MW) and SunE EPE2, LLC (12 MW), which began commercial operation in June 2012 and May 2012 , respectively. In September 2017, Longroad Solar Portfolio Holdings, LLC purchased SunE EPE1, LLC and in October 2017, Silicon Ranch Corporation purchased SunE EPE2, LLC with the Company's consent per the terms of both purchase power agreements.

Furthermore, the Company has a 20 -year purchase power agreement with Macho Springs Solar, LLC to purchase the entire generation output delivered from the 50 MW Macho Springs solar photovoltaic project located in Luna County, New Mexico which began commercial operation in May 2014 . Finally, the Company has a 30 -year purchase power agreement with Newman Solar LLC to purchase the total output, which is approximately 10 MW, from a solar photovoltaic generation plant on land subleased from the Company in proximity to Newman. This solar project began commercial operation in December 2014 .

Other purchases of shorter duration were made during 2017 to supplement the Company's generation resources during planned and unplanned outages, for economic reasons and to supply off-system sales.

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Operating Statistics



	Years Ended December 31,
	2017			2016		2015
Operating revenues (in thousands):
Non-fuel base revenues:
Retail:
Residential	$	287,884		$	278,774	$	246,265
Commercial and industrial, small	198,799			194,942		187,436
Commercial and industrial, large	38,403			39,070		40,411
Sales to public authorities	97,890			96,881		91,244
Total retail base revenues	622,976			609,667		565,356
Wholesale:
Sales for resale	2,730			2,407		2,455
Total non-fuel base revenues	625,706			612,074		567,811
Fuel revenues:
Recovered from customers during the period	218,380			148,397		127,765
Under (over) collection of fuel	(17,133		)	14,893		(13,342		)
New Mexico fuel in base rates	—			33,279		72,129
Total fuel revenues	201,247			196,569		186,552
Off-system sales:
Fuel cost	46,258			38,933		52,406
Shared margins	11,055			5,632		11,048
Retained margins	1,673			1,137		1,362
Total off-system sales	58,986			45,702		64,816
Other	30,858			32,591		30,690
Total operating revenues	$	916,797		$	886,936	$	849,869
Number of customers (end of year) (1):
Residential	370,054			363,987		358,819
Commercial and industrial, small	42,291			41,741		40,367
Commercial and industrial, large	48			49		49
Other	5,500			5,285		5,261
Total	417,893			411,062		404,496
Average annual kWh use per residential customer	7,671			7,748		7,763
Energy supplied, net, kWh (in thousands):
Generated	8,950,875			8,820,006		9,585,089
Purchased and interchanged	1,540,841			1,552,251		1,390,946
Total	10,491,716			10,372,257		10,976,035
Energy sales, kWh (in thousands):
Retail:
Residential	2,823,260			2,805,789		2,771,138
Commercial and industrial, small	2,410,710			2,403,447		2,384,514
Commercial and industrial, large	1,045,319			1,030,745		1,062,662
Sales to public authorities	1,564,670			1,572,510		1,585,568
Total retail	7,843,959			7,812,491		7,803,882
Wholesale:
Sales for resale	62,887			62,086		63,347
Off-system sales	2,042,884			1,927,508		2,500,947
Total wholesale	2,105,771			1,989,594		2,564,294
Total energy sales	9,949,730			9,802,085		10,368,176
Losses and Company use	541,986			570,172		607,859
Total	10,491,716			10,372,257		10,976,035
Native system:
Peak load, kW	1,935,000			1,892,000		1,794,000
Net dependable generating capability for peak, kW	2,082,000			2,080,000		2,055,000
Total system:
Peak load, kW (2)	1,982,000			2,027,000		1,992,000
Net dependable generating capability for peak, kW	2,082,000			2,080,000		2,055,000

___________________________


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


(2)	Includes spot sales and net losses of 47,000 kW, 135,000 kW and 198,000 kW for 2017, 2016 and 2015, respectively.

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Regulation

General

The rates and services of the Company are regulated by incorporated municipalities in Texas, the PUCT, the NMPRC and the 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

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 ("2015 Texas Retail Rate Case").

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

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

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

2017 Texas Retail Rate Case Filing. On February 13, 2017, the Company filed with the City of El Paso, other municipalities incorporated in the Company's Texas service territory and the PUCT in Docket No. 46831, a request for an increase in non-fuel base revenues ("2017 Texas Retail Rate Case"). On November 2, 2017, the Company filed the Joint Motion to Implement Uncontested Stipulation and Agreement with the Administrative Law Judges for the 2017 Texas Retail Rate Case.

On December 18, 2017, the PUCT issued its final order in the Company's rate case pending in Docket No. 46831 ("2017 PUCT Final Order"), which provides, among other things, for the following: (i) an annual non-fuel base rate increase of $14.5 million ; (ii) a return on equity of 9.65% ; (iii) all new plant in service as filed in the Company's rate filing package was prudent and used and useful and therefore is included in rate base; (iv) recovery of the costs of decommissioning Four Corners in the amount of $5.5 million over a seven year period beginning August 1, 2017; (v) the Company to recover reasonable rate case expenses of approximately $3.4 million through a separate surcharge over a three year period; and (vi) a requirement that the Company file a refund tariff if the federal statutory income tax rate, as it relates to the Company, is decreased before the Company files its next rate case. The 2017 PUCT Final Order also establishes baseline revenue requirements for recovery of future transmission and distribution investment costs, and includes a minimum monthly bill of $30.00 for new residential customers with distributed generation, such as private rooftop solar. Additionally, the 2017 PUCT Final Order allows for the annual recovery of $2.1 million of nuclear decommissioning funding and establishes annual depreciation expense that is approximately $1.9 million lower than the annual amount requested by the Company in its initial filing. Finally, the 2017 PUCT Final Order allows for the Company to recover revenues associated with the relate back of rates to consumption on and after July 18, 2017 through a separate surcharge.

New base rates, including additional surcharges associated with rate case expenses and the relate back of rates to consumption on and after July 18, 2017 through December 31, 2017 were implemented in January 2018.

For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2017 Texas Retail Rate Case until it received the 2017 PUCT Final Order on December 18, 2017. Accordingly, it reported in the fourth quarter of 2017 the cumulative effect of the 2017 PUCT Final Order, which related back to July 18, 2017.

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The 2017 PUCT Final Order requires the Company to file a refund tariff if the federal statutory income tax rate, as it relates to the Company, is decreased before the Company files its next rate case. Following the enactment of the Tax Cuts and Jobs Act of 2017 (" TCJA ") on December 22, 2017, and in compliance with the 2017 PUCT Final Order, the Company will reduce the recognition of Texas jurisdictional revenues beginning January 1, 2018, to approximate the tax savings resulting from the TCJA and will file a refund tariff which the Company will ask to be implemented in the first half of 2018. The refund tariff is expected to be reflected in rates over a period of a year and will be updated annually until new base rates are implemented pursuant to the Company's next rate case filing. See Part II, Item 8, Financial Statements and Supplementary Data, Note J for further details.

Energy Efficiency Cost Recovery Factor. On May 1, 2017, the Company filed its annual application, which was assigned PUCT Docket No. 47125, to establish its energy efficiency cost recovery factor ("EECRF") for 2018. In addition to projected energy efficiency costs for 2018 and a true-up to prior year actual costs, the Company requested approval of an incentive bonus for the 2016 energy efficiency program results in accordance with PUCT rules. Interim rates were approved effective January 1, 2018. The Company, the staff of the PUCT, and the City of El Paso reached an agreement that includes an incentive bonus of $0.8 million . The agreement was filed on January 25, 2018, and was approved by the PUCT on February 15, 2018.

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 November 30, 2016, the Company filed a request, which was assigned PUCT Docket No. 46610, to increase its fixed fuel factor by approximately 28.8% to reflect increased fuel expenses primarily related to an increase in the price of natural gas used to generate power. The increase in the fixed fuel factor was effective on an interim basis January 1, 2017 and approved by the PUCT on January 10, 2017. As of September 30, 2017, the Company had over-recovered fuel costs in the amount of $1.1 million for the Texas jurisdiction. On October 13, 2017, the Company filed a request, which was assigned PUCT Docket No. 47692, to decrease the Texas fixed fuel factor by approximately 19% to reflect decreased fuel expenses primarily related to a decrease in the price of natural gas used to generate power. The decrease in the Texas fixed fuel factor became effective beginning with the November 2017 billing month and will continue thereafter until changed by the PUCT. At December 31, 2017, the Company had a net fuel over-recovery balance of approximately $5.8 million in Texas.

Fuel Reconciliation Proceeding . On September 27, 2016, the Company filed an application with the PUCT, designated as PUCT Docket No. 46308, to reconcile $436.6 million of Texas fuel and purchased power expenses incurred during the period of April 1, 2013 through March 31, 2016. On June 29, 2017, the PUCT approved a settlement in this proceeding. The settlement provides for the reconciliation of fuel and purchased power costs incurred from April 1, 2013 through March 31, 2016. Additionally, the settlement modifies and tightens the Palo Verde performance rewards measurement bands beginning with the 2018 performance period. The financial results for the twelve months ended December 31, 2017 include a $5.0 million , pre-tax increase to income reflecting the settlement of the Texas fuel reconciliation proceeding. This amount represents Palo Verde performance rewards associated with the 2013 to 2015 performance periods net of disallowed fuel and purchased power costs as approved in the settlement. Texas jurisdictional fuel and purchased power costs subject to prudence review are costs from April 1, 2016 through December 31, 2017 that total approximately $250.9 million .

Community Solar. On June 8, 2015, the Company filed a petition with the PUCT to initiate a community solar program that includes the construction and ownership of a 3 MW solar photovoltaic system located at the Company's MPS . Participation is on a voluntary basis, and customers 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 approving the program, and the PUCT approved the settlement agreement and program on September 1, 2016. On April 19, 2017, the Company announced that the entire 3 MW program was fully subscribed by approximately 1,500 Texas customers. The Community Solar facility began commercial operation on May 31, 2017 .

Four Corners Generating Station . On February 17, 2015 , the Company and APS entered into the Purchase and Sale Agreement providing for the sale of the Company's interest in Four Corners to APS. The sale of the Company's interest in Four Corners closed on July 6, 2016 . See Part II, Item 8, " Financial Statements and Supplementary Data, Note E of Notes to Financial Statements" for further details on the sale of Four Corners.

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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 was subject to numerous procedural matters, including a March 23, 2016 order in which the PUCT determined not to dismiss the reasonableness and public interest issues in this docket but to consider the requested rate and accounting findings, including coal mine reclamation costs, in a rate case proceeding. On September 1, 2016, a motion by parties in the proceeding to suspend the procedural schedule in order to pursue settlement was approved. On March 3, 2017, the Company filed a Joint Motion to Implement Stipulation and Agreement (the "Stipulation and Agreement"), and PUCT Staff filed its recommendation that the Company’s disposition of its interest in Four Corners was reasonable and consistent with the public interest. Additionally, the signatories of the Stipulation and Agreement agreed to support the recovery of the Company's Four Corners decommissioning costs in the 2017 Texas Retail Rate Case. A final order approving the Stipulation and Agreement was adopted by the PUCT on March 30, 2017. The approval to recover Four Corners decommissioning costs was included in the 2017 PUCT Final Order.

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

New Mexico Regulatory Matters

2015 New Mexico Rate Case Filing . On May 11, 2015, the Company filed a request with the NMPRC, in Case No. 15-00127-UT, for an annual increase in non-fuel base rates. On June 8, 2016, the NMPRC issued its final order in Case No. 15-00127-UT (the "NMPRC Final Order") which approved an annual increase in non-fuel base rates of approximately $0.6 million , an increase of approximately $0.5 million in other service fees and a decrease in the Company's allowed return on equity to 9.48% . The NMPRC Final Order concluded that all of the Company's new plant in service was reasonable and necessary and therefore would be recoverable in rates. The Company's rates were approved by the NMPRC effective July 1, 2016 and implemented at such time.

Future New Mexico Rate Case Filing. NMPRC Case No. 15-00109-UT required the Company to make a rate filing in New Mexico in the second quarter of 2017 using a historical test year ended December 31, 2016. On March 24, 2017, the Company, NMPRC Utility Division Staff and the New Mexico Attorney General filed a Joint Motion to Modify Filing Date Stated in Final Order requesting that the rate filing date be changed to no later than July 31, 2019, using the appropriate historical test year period. The joint request was approved by the NMPRC on April 12, 2017. The NMPRC has initiated an investigation into the impact of the TCJA on utility customers that may require earlier action by the Company. The Company is evaluating possible approaches to begin providing a refund credit for the TCJA income tax rate decrease to New Mexico customers.

Fuel and Purchased Power Costs. Historically, fuel and purchased power costs were recovered through base rates and a Fuel and Purchased Power Cost Adjustment Clause (the "FPPCAC") that accounts for changes in the costs of fuel relative to the amount included in base rates. Effective July 1, 2016, with the implementation of the NMPRC Final Order, fuel and purchased power costs are no longer recovered through base rates but are recovered through the FPPCAC. The Company's request to reconcile its fuel and purchased power costs for the period January 1, 2013 through December 31, 2014 was approved in Case No. 15-00127-UT. New Mexico jurisdictional costs subject to prudence review are costs from January 1, 2015 through December 31, 2017 that total approximately $173.1 million . At December 31, 2017, the Company had a net fuel over-recovery balance of approximately $0.4 million in New Mexico. As required, the Company filed a request to continue use of its FPPCAC with the NMPRC on January 5, 2018 which was assigned NMPRC Case No. 18-00006-UT.

5 MW HAFB Facility Certificate of Convenience and Necessity ("CCN"). On October 7, 2015, in NMPRC Case No. 15-00185-UT, the NMPRC issued a final order approving a CCN for a 5 MW solar power generation facility located on HAFB in the Company's service territory in New Mexico. The Company and HAFB negotiated a retail contract, which includes a power sales agreement for the facility, to replace the existing load retention agreement which was approved by final order issued October 5, 2016 in NMPRC Case No. 16-00224-UT. Construction of the solar generation facility is expected to be completed in the third quarter of 2018.

New Mexico Efficient Use of Energy Recovery Factor. On July 1, 2016, the Company filed its annual application requesting approval of its 2017 Energy Efficiency and Load Management Plan and to establish energy efficiency cost recovery factors for 2017. In addition to projected energy efficiency costs for 2017, the Company requested approval of a $0.4 million incentive for 2017 energy efficiency programs in accordance with NMPRC rules. This case was assigned Case No. 16-00185-UT. On February 22, 2017, the NMPRC issued a Final Order approving the Company’s 2017 Energy Efficiency and Load Management Plan and authorizing recovery in 2017 of a base incentive of $0.4 million . The Company’s energy efficiency cost recovery factors were approved and effective in customer bills beginning on March 1, 2017.

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the $0.3 million approved incentive in operating revenues in the first quarter of 2017. In addition, on June 30, 2017, the Company filed its 2016 Annual Report for Energy Efficiency Programs, which included an incentive for verified 2016 program performance of $0.4 million that was approved in Case No. 13-00176-UT. The Company recorded the $0.4 million approved incentive in operating revenues in the third quarter of 2017.

Revolving Credit Facility, Issuance of Long-Term Debt, and Securities Financing. On October 7, 2015, the Company received approval in NMPRC Case No. 15-00280-UT to guarantee the issuance of up to $65.0 million of long-term debt by the Rio Grande Resources Trust (" RGRT ") to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations, which remains effective. On October 4, 2017, the Company received additional approval in NMPRC Case No. 17-00217-UT to amend and extend its Revolving Credit Facility (" RCF ") , issue up to $350.0 million in long-term debt and to redeem and refinance the $63.5 million 2009 Series A 7.25% Pollution Control Bonds and the $37.1 million 2009 Series B 7.25% Pollution Control Bonds, which have optional redemptions beginning in 2019. The NMPRC approval to issue $350.0 million in long-term debt supersedes its prior approval.

Other Required Approvals . The Company has obtained other required approvals for tariffs and other approvals as required by the New Mexico Public Utility Act and the NMPRC.

Federal Regulatory Matters

Revolving Credit Facility; Issuance of Long-Term Debt, Securities Financing, and Guarantee of Debt. On October 31, 2017, the FERC issued an order in Docket No. ES17-54-000 approving the Company’s filing to (i) amend and extend the RCF; (ii) issue up to $350.0 million in long-term debt; (iii) guarantee the issuance of up to $65.0 million of long-term debt by the RGRT; and (iv) redeem and refinance the $63.5 million 2009 Series A 7.25% Pollution Control Bonds and the $37.1 million 2009 Series B 7.25% Pollution Control Bonds, which have optional redemptions beginning in 2019. The order also approves the Company's request to continue to utilize the Company's existing RCF with the ability to amend and extend at a future date. The authorization is effective from November 15, 2017 through November 14, 2019 and supersedes prior FERC approvals.

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

United States Department of Energy. The DOE regulates the Company's exports of power to Mexico pursuant to a DOE grant of export authorization. In addition, the Company is the holder of two presidential permits issued by the DOE under which the Company constructed and operates border facilities crossing the United States/Mexico border.

The DOE is authorized to assess operators of nuclear generating facilities a share of the costs of decommissioning the DOE's uranium enrichment facilities and for the ultimate costs of disposal of spent nuclear fuel. See "Facilities – Palo Verde" for discussion of spent fuel storage and disposal costs.

Sales for Resale and Network Transmission Service to Rio Grande Electric Cooperative

The Company provides firm capacity and associated energy to the Rio Grande Electric Cooperative ("RGEC") pursuant to an ongoing contract with a two -year notice to terminate provision. The Company also provides network integrated transmission service to the RGEC pursuant to the Company's Open Access Transmission Tariff ("OATT"). The contract includes a formula-based rate that is updated annually to recover non-fuel generation costs and a fuel adjustment clause designed to recover all eligible fuel and purchased power costs allocable to the RGEC. The Company's service to RGEC is regulated by FERC.

Power Sales Contracts

The Company has entered into several short-term (three months or less) off-system sales contracts throughout 2017.

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Franchises and Significant Customers

Franchises

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

The Company does not have a written franchise agreement with Las Cruces, New Mexico, the second largest city in its service territory. The Company utilizes public rights-of-way necessary to service its customers within Las Cruces under an implied franchise by satisfying all obligations under the franchise agreement that expired on April 30, 2009 . The Company pays the City of Las Cruces a franchise fee of 2.00% of gross revenues the Company receives from services within the City of Las Cruces.

Military Installations

The Company serves HAFB, White Sands and Fort Bliss. These military installations represent approximately 2.5% of the Company's annual retail revenues. In July 2014, the Company signed an agreement with Fort Bliss under which Fort Bliss takes retail electric service from the Company under the applicable Texas tariffs . The Company serves White Sands under the applicable New Mexico tariffs. In August 2016, the Company signed a contract with HAFB under which the Company provides retail electric service and limited wheeling services to HAFB under the applicable New Mexico tariffs. As stated in the contract, HAFB will purchase the full output of a Company-owned 5 MW solar facility upon its completed construction, with HAFB's other power requirements and limited wheeling services provided under the applicable New Mexico tariffs.

Other Information

Investors should note that we announce material financial information in our filings with the SEC, press releases and public conference calls. Based on guidance from the SEC, we may also use the Investor Relations section of our website (www.epelectric.com) to communicate with investors about the Company. It is possible that the financial information we post there could be deemed to be material information. The information contained on or accessible from our website is not incorporated by reference into and does not constitute a part of this Annual Report on Form 10-K.

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Item 1A. Risk Factors

Like other companies in our industry, our financial results are impacted by weather, the economy of our service territory, market prices for power, fuel prices, and the decisions of regulatory agencies. Our common stock price and creditworthiness will be affected by local, regional and national macroeconomic trends, general market conditions and the expectations of the investment community, all of which are largely beyond our control. In addition, the following statements highlight risk factors that may affect our financial condition and results of operations. These are not intended to be an exhaustive discussion of all such risks, and the statements below must be read together with factors discussed elsewhere in this Annual Report on Form 10-K and in our other filings with the SEC.

Our Revenues and Profitability Depend Upon Regulated Rates

Our retail rates are subject to regulation by incorporated municipalities in Texas, the PUCT, the NMPRC and the FERC. The 2017 PUCT Final Order established our current retail base rates in Texas, effective July 18, 2017. In addition, the NMPRC Final Order established rates in New Mexico that became effective in July 2016.

Our profitability depends on our ability to recover the costs, including a reasonable return on invested capital, of providing electric service to our customers through base rates approved by our regulators. These rates are generally established based on an analysis of the expenses we incur in a historical test year, and as a result, the rates ultimately approved by our regulators may or may not match our expenses at any given time and recovery of expenses may lag behind the occurrence of those expenses. Rates in New Mexico may be established using projected costs and investment for a future test year period in certain instances. While rate regulation is based on the assumption that we will have a reasonable opportunity to recover our costs and earn a reasonable rate of return on our invested capital, there can be no assurance that our future Texas rate cases or New Mexico rate cases will result in base rates that will allow us to fully recover our costs including a reasonable return on invested capital. There can be no assurance that regulators will determine that all of our costs are reasonable and have been prudently incurred including costs associated with future plant retirements. It is also likely that third parties will intervene in any rate cases and challenge whether our costs are reasonable and necessary. If all of our costs are not recovered, or timely recovered, through the retail base rates ultimately approved by our regulators, our profitability and cash flow could be adversely affected which, over time, could adversely affect our ability to meet our financial obligations.

We May Not Be Able To Recover All Costs of New Generation and Transmission Assets

We received approval, both from the PUCT and the NMPRC, to construct Units 3 and 4, two 89 MW simple-cycle aeroderivative combustion turbines at MPS. In 2016, we completed construction of these units, which began commercial operation in May 2016 and September 2016, respectively. The PUCT approved the inclusion of the Texas jurisdictional portion of MPS Units 3 and 4 in base rates in the 2017 PUCT Final Order. However, the New Mexico jurisdiction portion of MPS Units 3 and 4 have not yet been approved by the NMPRC for inclusion in customer base rates. Accordingly, we are exposed to the risk of failing to recover these costs as well as costs associated with the construction of other new units and transmission and distribution assets.

In addition, if future units are not completed on time, we may be required to purchase power or operate less efficient generating units to meet customer requirements. Any replacement purchased power or fuel costs will be subject to regulatory review by the PUCT and the NMPRC. We face financial risks to the extent that recovery is not allowed for any replacement fuel costs resulting from delays in the completion of these new units or other new units.

Weakness in the Economy and Uncertainty in the Financial Markets Could Reduce Our Sales, Hinder Our Capital Programs and Increase Our Funding Obligations for Pensions and Decommissioning

The global credit and equity markets and the overall economy can be extremely volatile which could have a number of adverse effects on our operations and capital programs. For example, tight credit and capital markets could make it difficult and more expensive to raise capital to fund our operations and capital programs. If we are unable to access the credit markets, we could be required to defer or eliminate important capital projects in the future. In addition, declines in the stock market performance may reduce the value of our financial assets and decommissioning trust investments. Similarly, inflationary increases will increase our future decommission obligations. Such market results may also increase our funding obligations for our pension plans, other post-retirement benefit plans and nuclear decommissioning trusts. Changes in the corporate interest rates that we use as the discount rate to determine our pension and other post-retirement liabilities may have an impact on our funding obligations for such plans and trusts. Further, continued economic volatility may result in reduced customer demand, both in the retail and wholesale markets, and increases in customer delinquencies and write-offs. Uncertainty in the credit markets may negatively impact the ability of our customers to finance purchases of our services and could adversely affect the collectability of our receivables. Similarly, actions or inaction of Congress and of governmental agencies can impact our operations. For example, during 2013, sales to public authorities and small commercial and industrial customers were negatively impacted by the federal government sequestration and

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shutdown. The credit markets and overall economy (including inflationary increases) may also adversely impact our ability to arrange future financings on acceptable terms and therefore our ability to refinance our existing indebtedness could be limited. Furthermore, the credit markets and overall economy may also adversely impact the financial health of our suppliers. If that were to occur, our access to and prices for inventory, supplies and capital equipment could be adversely affected. Our power trading counterparties could also be adversely impacted by the market and economic conditions which could result in reduced wholesale power sales or increased counterparty credit risk. Declines in revenues, earnings and cash flow from these events could impact our ability to fund construction expenditures and impact the level of dividend payments.

There are Inherent Risks in the Ownership of Nuclear Facilities

Our 15.8% ownership interest in Palo Verde, which is the largest nuclear electric generating facility in the United States, subjects us to a number of risks. A significant percentage of our generating capacity, off-system sales margins, assets and operating expenses is attributable to Palo Verde. Our interest in each of the three Palo Verde units totals approximately 633 MW of generating capacity. Palo Verde represents approximately 30% of our available net generating capacity and provided approximately 49% of our energy requirements for the twelve months ended December 31, 2017. Palo Verde comprises approximately 25% of our total net plant-in-service and Palo Verde expenses comprise a significant portion of operation and maintenance expenses. APS is the operating agent for Palo Verde, and we have limited ability under the ANPP Participation Agreement to influence operations and costs at Palo Verde. Palo Verde operated at a capacity factor of 93.8% and 93.2% in the twelve months ended December 31, 2017 and 2016, respectively.

We participate in Palo Verde with one or more parties who may not have the same goals, strategies, priorities or resources as we do and may compete with us. Furthermore, regulatory compliance issues and financial restraints could cause these parties to make decisions that could potentially be adverse to us.

As Palo Verde is a nuclear electric generating facility, it is subject to environmental, health and financial risks, such as the ability to obtain adequate supplies of nuclear fuel and water; the ability to dispose of spent nuclear fuel; increases in decommissioning costs due to inflation and regulatory changes, the ability to maintain adequate trust fund reserves for decommissioning; potential liabilities arising out of the operation of these facilities; the costs of securing the facilities against possible terrorist attacks; cyber attacks, or other causes; and unscheduled outages due to equipment and other problems. If a nuclear incident were to occur at Palo Verde, it could materially and adversely affect our results of operations and financial condition. A major incident at a nuclear facility anywhere in the world could cause regulatory bodies to limit or prohibit the operation or licensing of any domestic nuclear unit and to promulgate new regulations that could require significant capital expenditures and/or increase operating costs.

We May Not Be Able to Recover All of Our Fuel Expenses from Customers On a Timely Basis Or at All

In general, by law, we are entitled to recover our reasonable and necessary fuel and purchased power expenses from our customers in Texas and New Mexico. NMPRC Case No. 13-00380-UT provides for energy delivered to New Mexico customers from the deregulated Palo Verde Unit 3 to be recovered through fuel and purchased power costs based upon a previous purchased power contract. Fuel and purchased power expenses in Texas and New Mexico are subject to reconciliation by the PUCT and NMPRC. Prior to the completion of a reconciliation, we record fuel and purchased power costs such that fuel revenues equal recoverable fuel and purchased power expense including the re-priced energy costs for Palo Verde Unit 3 in New Mexico. In the event that recovery of fuel and purchased power expenses is denied in any reconciliation proceeding, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we would incur a loss to the extent of the disallowance.

In New Mexico, the FPPCAC allows us to reflect current fuel and purchased power expenses in the FPPCAC and to adjust for under-recoveries and over-recoveries with a two-month lag. In Texas, fuel costs are recovered through a fixed fuel factor. In Texas, we can seek to revise our fixed fuel factor based upon our approved formula at least four months after our last revision except in the month of December. If we materially under-recover fuel costs, we may seek a surcharge to recover those costs at any time the balance exceeds a threshold material amount and is expected to continue to be materially under-recovered. During periods of significant increases in natural gas prices, we realize a lag in the ability to reflect increases in fuel costs in our fuel recovery mechanisms in Texas. As a result, cash flow is impacted due to the lag in payment of fuel costs and collection of fuel costs from customers. To the extent the fuel and purchased power recovery processes in Texas and New Mexico do not provide for the timely recovery of such costs, we could experience a material negative impact on our cash flow.

Weather Conditions Affect the Demand for Electricity or Could Result in Unplanned Outages

Our service territory is in west Texas and southern New Mexico and is particularly susceptible to dry and hot temperatures in the summer months. These seasonal weather patterns result in temperatures that can lead to daytime highs exceeding 100 degrees Fahrenheit for extended periods during the summer when we typically experience peak kWh sales at higher summer rates. Milder

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temperatures during this period will occur occasionally and result in less kWh sales which will adversely affect our results of operations. From time to time, we experience extreme weather conditions, including high winds (usually in the spring months but can occur during other months), that may result in unplanned outages. Under such conditions, we may incur additional costs to repair and, or, to replace equipment. Depending upon the length and extent of the damage, we may also incur additional purchase power costs. Fallen power lines and poles can cause severe damage to customer property and subject us to claims, all of which could have a material adverse effect on our results of operations and cash flows.

Equipment Failures and Other External Factors Can Adversely Affect Our Results

The generation and transmission of electricity require the use of expensive and complex equipment. While we have a maintenance program in place, generating plants are subject to unplanned outages because of equipment failure and severe weather conditions. The advanced age of several of our gas-fired generating units in or near El Paso increases the vulnerability of these units. In the event of unplanned outages, we must acquire power from other sources at unpredictable costs in order to supply our customers and comply with our contractual agreements. This additional purchased power cost would be subject to review and approval of the PUCT and the NMPRC in reconciliation proceedings. As noted above, in the event that recovery for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, we would incur a loss to the extent of the disallowance. Unplanned outages could also prevent us from selling excess power at wholesale. In addition, actions of other utilities may adversely affect our ability to use transmission lines to deliver or import power, thus subjecting us to unexpected expenses or to the cost and uncertainty of public policy initiatives. We may also incur additional capital and operating costs in connection with the physical security and cyber security of transmission lines and generation facilities. Damage to certain transmission and generation facilities due to vandalism or other deliberate acts, or damage due to severe weather could lead to outages or other adverse effects. We are particularly vulnerable to this because a significant portion of our available energy (at Palo Verde) is located hundreds of miles from El Paso and Las Cruces and must be delivered to our customers over long distance transmission lines. In addition, Palo Verde’s availability is an important factor in realizing off-system sales margins. These factors, as well as interest rates, economic conditions, fuel prices and price volatility could have a material adverse effect on our earnings, cash flow and financial position. While we believe that we maintain adequate insurance coverage for such incidents, there is no assurance that all costs in excess of deductible amounts will be reimbursed or that we can maintain such coverage limits in the future at competitive market rates. In the event future insurance costs and/or deductible amounts increase, our financial condition, operating results and cash flows could be materially adversely affected.

Competition and Deregulation Could Result in a Loss of Customers and Increased Costs

As a result of changes in federal law, our wholesale and large retail customers have access to, in varying degrees, alternative sources of power, including co-generation of electric power. Deregulation legislation is in effect in Texas requiring us to separate our transmission and distribution functions, which would remain regulated, from our power generation and energy services businesses, which would operate in a competitive market, in the future. In 2004, the PUCT approved a rule delaying retail competition in our Texas service territory. This rule was codified in the PURA in June 2011. The PURA identifies various milestones that we must reach before retail competition can begin. The first milestone calls for the development, approval by the FERC, and commencement of independent operation of a regional transmission organization in the area that includes our service territory. This and other milestones are not likely to be achieved for a number of years, if at all. There is substantial uncertainty about both the regulatory framework and market conditions that would exist if and when retail competition is implemented in our Texas service territory, and we may incur substantial preparatory, restructuring and other costs that may not ultimately be recoverable. There can be no assurance that deregulation would not adversely affect our future operations, cash flow and financial condition.

Future Costs of Compliance with Environmental Laws and Regulations Could

Adversely Affect Our Operations and Financial Results

We are subject to extensive federal, state and local environmental laws and regulations relating to discharges into the air, air quality, discharges of effluents into water, water quality, the use of water, the handling, disposal and clean-up of hazardous and non-hazardous substances and wastes, natural resources, and health and safety. Compliance with these legal requirements, which change frequently and often become more restrictive, could require us to commit significant capital and operating resources toward permitting, emission fees, environmental monitoring, installation and operation of pollution control equipment and purchases of air emission allowances and/or offsets. These laws and regulations could also result in limitations in operating hours and/or changes in construction schedules for future generating units.

Cost of compliance with environmental laws and regulations or fines or penalties resulting from non-compliance, if not recovered in our rates, could adversely affect our operations and financial results, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increase. We cannot estimate our compliance costs or any possible fines or penalties with certainty, or

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the degree to which such costs might be recovered in our rates, due to our inability to predict the requirements and timing of implementation of environmental laws or regulations. For example, the EPA has issued in the recent past various proposed regulations regarding air emissions, such as the revision of the primary and secondary ground-level ozone NAAQS. If these regulations become finalized and survive legal challenges, the cost to us to comply could adversely affect our operations and our financial results.

Climate Change and Related Legislation and Regulatory Initiatives Could Affect Demand for

Electricity or Availability of Resources, and Could Result in Increased Compliance Costs

We emit GHG (including carbon dioxide) through the operation of our power plants. Federal legislation had been introduced in both houses of Congress to regulate GHG emissions and numerous states have adopted programs to stabilize or reduce GHG emissions. Additionally, the EPA is proceeding with regulation of GHG under the CAA.

In October 2015, the EPA published a rule establishing guidelines for states to regulate CO2 emissions from existing power plants, known as the Clean Power Plan ("CPP"). Legal challenges to the CPP are ongoing. We cannot at this time determine the impact of the CPP, related proposals and legal challenges may have on our financial condition, results of operations or cash flows. Further, in April 2016, the U.S. signed the 21st Conference of Parties Paris Agreement, which requires countries to set and "represent a progression" in GHG emission reduction goals every five years beginning in 2020. In August 2017, the United States formally documented to the United Nations its intent to withdraw from the Paris Agreement. The earliest possible effective withdrawal date from the Paris Agreement is November 2020. The potential impact of this agreement and GHG rules (if and when finalized) on us is unknown at this time, but they could result in significant costs, limitations on operating hours, and/or changes in construction schedules for future generating units.

It is not possible to predict how any pending, proposed or future GHG legislation by Congress, the states or multi-state regions or any GHG regulations adopted by the EPA or state environmental agencies will impact our business. However, any legislation or regulation of GHG emissions or any future related litigation could result in increased compliance costs or additional operating restrictions or increased or reduced demand for our services, could require us to purchase rights to emit GHG, and could have a material adverse effect on our business, financial condition, reputation or results of operations.

Adverse Regulatory Decisions or Changes in Applicable Regulations Could Have a Material Adverse Effect on Our

Business or Result in Significant Additional Costs

Our business is subject to extensive federal, state and local laws and regulations regarding safety and performance, siting and construction of facilities, customer service and the rates we can charge our customers, among other things. FERC regulates our wholesale operations, provision of transmission services and compliance with federally mandated reliability standards. FERC has issued a number of rules pertaining to preventing undue discrimination in transmission services and electric reliability standards. Under the Energy Policy Act of 2005, FERC can impose penalties (up to $1,238,271 per violation, per day) for failure to comply with statutes, rules and orders within FERC's jurisdiction, including mandatory electric reliability standards. Additional regulatory authorities have jurisdiction over some of our operations and construction projects, including the EPA, the DOE, the PUCT, the NMPRC and various local regulatory districts (including the cities of El Paso and Las Cruces).

We must periodically apply for licenses and permits from these various regulatory authorities and abide by their respective orders. Should we be unsuccessful in obtaining necessary licenses or permits or should these regulatory authorities initiate any investigations or enforcement actions or impose penalties or disallowances on us, our business could be adversely affected. Existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to us or our facilities in a manner that may have a detrimental effect on our business or result in significant additional costs because of our obligation to comply with those requirements.

Security Breaches, Criminal Activity, Terrorist Attacks and Other Disruptions to Our Infrastructure Could Interfere With Our Operations, Could Expose Us or Our Customers or Employees to a Risk of Loss, and Could Expose Us to Liability, Regulatory Penalties, Reputational Damage and Other Harm to Our Business

We rely upon our infrastructure to manage or support a variety of business processes and activities, including the generation, transmission and distribution of electricity, supply chain functions, and the invoicing and collection of payments from our customers. We also use information technology systems for internal accounting purposes and to comply with financial reporting, legal and tax requirements. Our information technology networks and infrastructure may be vulnerable to damage, disruptions or shutdowns due to attacks by hackers, breaches due to employee error or malfeasance, system failures, computer viruses, natural disasters, a physical attack on our facilities, or other catastrophic events. The occurrence of any of these events could impact the reliability of our generation, transmission and distribution systems and energy marketing and trading functions; could expose us or our customers or employees to a risk of loss or misuse of confidential information; and could result in legal claims or proceedings, liability or

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regulatory penalties against us, damage our reputation or otherwise harm our business. In addition, we may be required to incur significant costs to prevent or respond to damage caused by these disruptions or security breaches in the future.

Additionally, we cannot predict the impact that any future information technology or terrorist attack may have on the energy industry in general. The effects of such attacks against us or others in the energy industry could increase the cost of regulatory compliance, increase the cost of insurance coverage or result in a decline in the U.S. economy which could negatively affect our results of operations and financial condition. Ongoing and future governmental efforts to regulate cybersecurity in the energy industry could lead to increased regulatory compliance costs.

The Effects of Technological Advancement, Energy Conservation Measures and Distributed Generation Could Adversely Affect Our Operations and Financial Results

New technologies may emerge that could be superior to, or may not be compatible with, some of our existing technologies, and may require us to make significant expenditures to remain competitive. Our future success will depend, in part, on our ability to anticipate and adapt to technological changes in a cost-effective manner and to offer, on a timely basis, services that meet customer demands and evolving industry standards.

Additionally, the electric utility industry is undergoing other technological advances such as the expanded cost effective utilization of energy efficiency measures, energy storage, and distributed generation including solar rooftop projects. Customers’ increased use of energy efficiency measures, energy storage, and distributed generation could result in lower demand. Reduced demand due to energy efficiency measures, energy storage, and the use of distributed generation, to the extent not substantially offset through ratemaking mechanisms, could have a material adverse impact on our financial condition, results of operations and cash flows.

Inflation Could Adversely Affect Our Financial Results

For the past several years, inflation has been relatively low and, therefore has had little impact on our results of operations and financial condition. However, should we experience increases in costs due to inflationary impacts, any delays in requesting and receiving compensatory increases in our base rates could have a material adverse impact on our financial condition, results of operations and cash flows.

Our Line of Business Is Concentrated Solely to the Electric Industry and to One Region

We are a fully vertically integrated electric utility company whose only business is the generation, transmission and distribution of electricity to customers in an area of approximately 10,000 square miles in west Texas and southern New Mexico. Approximately 90% of revenues are directly related to the retail sales of electric power to approximately 417,900 residential, commercial and public authority customers. As such, risks uniquely associated with the utility industry such as changes in utility legislation and regulations, weather patterns in the region and economic conditions will have a greater effect on our overall operating results than otherwise if our operations were more diversified into other lines of business and in a broader geographical area.

New Laws, Regulations and Policies Announced by the Trump Administration Could Impact Our Operations

President Donald Trump campaigned on a number of issues, including increasing border security and immigration regulations, overhauling federal taxes, repealing the Patient Protection Affordable Care Act, withdrawal from the Trans Pacific Partnership agreement, enacting duties on NAFTA imports and reducing the burdens of environmental and climate change regulations. Since President Trump’s inauguration, he has initiated executive orders towards achieving some of these goals; however it is uncertain to what extent President Trump proposes additional new executive orders and the effect such orders will have on the national, regional and local economies. Our service territory borders with Mexico and as such businesses in our service territory rely heavily on commerce with businesses in Mexico. Changes in regulations restricting such commerce activities could reduce our customer growth rate and materially adversely affect our results of operations, financial condition and cash flows.

On December 22, 2017, the TCJA was signed into law, enacting significant changes to the Internal Revenue Code ("IRC”). Key provisions impacting the Company include a reduction in the corporate income tax rate from 35% to 21% effective January 1, 2018, the discontinuation of bonus depreciation for regulated public utilities for assets acquired and placed into service after September 27, 2017, elimination of corporate alternative minimum tax provisions, limitations on the utilization of net operating losses ("NOL") arising after December 31, 2017 to 80% of taxable income with no carryback but with an indefinite carryforward, and additional limitations on the deductibility of executive compensation. We continue to evaluate the impact of the TCJA as regulations and accounting standards related to the TCJA are finalized to determine whether changes could have a material adverse effect on our results of operations, financial condition, and cash flows.

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The Operation of Transmission Lines on Public and Private Properties, including Indian Lands, Could Result in Uncertainty Related to Continued Easements and Rights-of-way and Significantly Impact Our Business

Portions of our transmission lines are located on public and private properties, including Indian lands, pursuant to easements or other rights-of-way that are effective for specified periods. We are unable to predict the final outcome of pending or future approvals by applicable property owners and governing bodies with respect to renewals of these easements and rights-of-way.

Failure to Successfully Operate Our Facilities or Perform Certain Corporate Functions May Adversely Affect Our Operations and Financial Condition

Our performance depends on the successful operation of our facilities. Operating these facilities involves many risks, including:


•	operator error or failure of equipment or processes, including failure to follow appropriate safety protocols;


•	the handling of hazardous equipment or materials that could result in serious personal injury, loss of life and environmental and property damage;


•	operating limitations that may be imposed by environmental or other regulatory requirements;


•	labor disputes;


•	information technology or financial system failures, including those due to the implementation and integration of new technology, that impair our information technology infrastructure, reporting systems or disrupt normal business operations;


•	information technology failure that affects our ability to access customer information or causes us to lose confidential or proprietary data that materially and adversely affects our reputation or exposes us to legal claims; and


•	catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, natural disasters, terrorism, pandemic health events or other similar occurrences, which may require participation in mutual assistance efforts by us or other utilities to assist in power restoration efforts.

Such events may result in a decrease or elimination of revenue from our facilities, an increase in the cost of operating our facilities or delays in cash collections, any of which could have a material adverse effect on our results of operations, financial condition and/or cash flows.

Our Success Depends on the Availability of the Services of a Qualified Workforce and Our Ability to Attract and Retain Qualified Personnel and Senior Management

Our workforce is aging and many employees have retired in the last few years or are or will become eligible to retire within the next few years. Although we have undertaken efforts to recruit and train new field service personnel, we may be faced with a shortage of experienced and qualified personnel. Our costs, including costs to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be negatively affected.

A substantial number of our employees are covered by a collective bargaining agreement that is scheduled to expire in September 2019. Labor disruptions could occur depending on the outcome of negotiations to renew the terms of this agreement with the union or if a tentative new agreement is not ratified by its members. In addition, some of our non-represented employees could join this union in the future. Labor disruptions, strikes or significant negotiated wage and benefit increases, whether due to union activities, employee turnover or otherwise, could have a material adverse effect on our business, results of operations and/or cash flows.

We depend on our senior management and other key personnel. Our success depends on our ability to attract and retain key personnel. The inability to recruit and retain or effectively transition key personnel or the unexpected loss of key personnel may adversely affect our operations. In addition, because of the reliance on our management team, our future success depends in part on our ability to identify and develop talent to succeed senior management. Any such occurrences could negatively impact our financial condition and results of operations.

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Our Ability to Accurately Report Our Financial Results or Prevent Fraud May Be Adversely Affected if We Fail to Maintain an Effective System of Internal Controls

Effective internal controls are necessary for us to provide reliable financial reports, effectively prevent fraud and operate successfully as a public company. If our efforts to maintain an effective system of internal controls are not successful, we are unable to maintain adequate controls over our financial reporting and processes in the future or we are unable to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, our operating results could be harmed, or we may fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common stock and other securities.

Insufficient Insurance Coverage and Increased Insurance Costs Could Adversely Affect Our Operations and Financial Results

We currently have general liability and property insurance in place to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to restore the loss or damage without negative impact on our results of operations, financial condition and cash flows.

Provisions in Our Corporate Documents, Franchise Agreements and State Law Could Delay or Prevent a Change in Control of the Company, Even if That Change Would Be Beneficial to Our Shareholders

Our Articles of Incorporation and Bylaws contain provisions that may make acquiring control of the Company difficult and could preclude our shareholders from receiving a change of control premium, including:


•	provisions relating to the classification, nomination and removal of our directors;


•	provisions regulating the ability of our shareholders to bring matters for action at annual meetings of our shareholders;


•	provisions limiting the ability to call special meetings of the shareholders to the Chairman of the Board, our President and Chief Executive Officer, our Secretary, the majority of the Board of Directors or the holders of at least 25% of the outstanding shares of our capital stock entitled to vote at such meeting;


•	provisions restricting our ability to engage in a wide range of “Business Combination” transactions with an “Interested Shareholder” (generally, any person who owns 15% or more of our outstanding voting power) or any affiliate or associate of an Interested Shareholder, unless specific conditions are met; and


•	the authorization given to our Board of Directors or any duly designated committee to issue and set the terms of preferred stock.

Our El Paso franchise agreement states that any assignment of the franchise agreement, including a deemed assignment as a result of a change in control of the Company, requires the consent of the City of El Paso. In addition, approval of the NMPRC, PUCT and FERC would likely be required in any transaction involving a change of control.

In addition, Texas law prohibits us from engaging in a business combination with any shareholder for three years from the date that person became an affiliated shareholder by beneficially owning 20% or more of our outstanding common stock, in the absence of certain board of director or shareholder approvals.

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Item 1B.	Unresolved Staff Comments

None.


Item 2.	Properties

The principal properties of the Company are described in Item 1, "Business," and such descriptions are incorporated herein by reference. Transmission lines are located either on company-owned land, private rights-of-way, easements or on streets or highways by public consent.

The Company owns an executive and administrative office building and the Eastside Operations Center (the "EOC") in El Paso County, Texas. The Company leases land in El Paso, Texas, adjacent to Newman under a lease which expires in June 2033, subject to a renewal option of 25 years. The Company has several other leases for office and parking facilities that expire within the next five years.


Item 3.	Legal Proceedings

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.

See

Item 1, "Business – Environmental Matters and Regulation," Item 1, "Regulation," and

Part II, Item 8, "Financial Statements and Supplementary Data, Note C, Note L and Note K of Notes to Financial Statements" for discussion of the effects of government legislation and regulation on the Company as well as certain pending legal proceedings.


Item 4.	Mine Safety Disclosures

Not Applicable.

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PART II


Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

The Company’s common stock trades on the New York Stock Exchange ("NYSE") under the symbol "EE." The intraday high, intraday low and close sales prices for the Company’s common stock, as reported in the consolidated reporting system of the NYSE, and quarterly dividends per share paid by the Company for the periods indicated below were as follows:



	Sales Price
	High		Low		Close		Dividends
					(End of period)
2016
First Quarter	$	46.20	$	37.19	$	45.88	$	0.295
Second Quarter	47.27		42.42		47.27		0.310
Third Quarter	48.75		44.07		46.77		0.310
Fourth Quarter	48.35		42.49		46.50		0.310
2017
First Quarter	$	50.75	$	44.70	$	50.50	$	0.310
Second Quarter	55.45		48.81		51.70		0.335
Third Quarter	56.78		50.25		55.25		0.335
Fourth Quarter	61.15		54.60		55.35		0.335

Performance Graph

The following graph compares the performance of the Company’s common stock to the performance of Edison Electric Institute’s ("EEI") index of investor-owned electric utilities and the NYSE Composite, setting the value of each at December 31, 2012 to a base of 100. The table sets forth the relative yearly percentage change in the Company’s cumulative total shareholder return, assuming reinvestment of dividends, as compared to EEI and the NYSE Composite, as reflected in the graph.



	As of December 31,
	2012	2013	2014	2015	2016	2017
EE	100	113	133	132	164	200
EEI Index	100	113	146	140	164	184
NYSE Composite	100	123	128	120	131	152

As of January 31, 2018, there were 2,232 holders of record of the Company’s common stock. The Company has been paying quarterly cash dividends on its common stock since June 30, 2011 and paid a total of $53.3 million in cash dividends during the twelve months ended December 31, 2017. On February 1, 2018 , the Board of Directors declared a quarterly cash dividend of $0.335 per share payable on March 30, 2018 to shareholders of record as of the close of business on March 16, 2018 . Typically, the Board of Directors reviews the Company’s dividend policy annually in the second quarter of each year. Declaration and payment of dividends is subject to compliance with certain financial tests under Texas law. Since 1999, the Company has also returned cash to shareholders through a stock repurchase program pursuant to which the Company has bought approximately 25.4 million shares at an aggregate cost of $423.6 million, including commissions. Under the Company’s 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. On March 21, 2011, the Board of Directors authorized a repurchase of up to 2.5 million shares of the Company’s outstanding common stock (the "2011 Plan"). No shares of common stock were repurchased during the twelve months ended December 31, 2017 under the 2011 Plan. The table below provides the amount of the fourth quarter issuer purchases of equity securities.



Period	Total Number of Shares Purchased (a)	Average Price Paid per Share (Including Commissions)		Total Number of Shares Purchased as Part of a Publicly Announced Program	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
October 1 to October 31, 2017	—	$	—	—	393,816
November 1 to November 30, 2017	—	—		—	393,816
December 1 to December 31, 2017	8,360	55.35		—	393,816

_____________________

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

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

For Equity Compensation Plan Information see Part III, Item 12 – "Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters."

Item 6. Selected Financial Data

As of and for the following periods (in thousands except for share and per share data):



	Years Ended December 31,
	2017		2016		2015		2014		2013
Operating revenue	$	916,797	$	886,936	$	849,869	$	917,525	$	890,362
Operating income	198,254		$	194,861	$	146,191	$	151,163	$	165,635
Net income	$	98,261	$	96,768	$	81,918	$	91,428	$	88,583
Basic earnings per share:
Net income	$	2.42	$	2.39	$	2.03	$	2.27	$	2.20
Weighted average number of shares outstanding	40,414,556		40,350,688		40,274,986		40,190,991		40,114,594
Diluted earnings per share:
Net income	$	2.42	$	2.39	$	2.03	$	2.27	$	2.20
Weighted average number of shares and dilutive
potential shares outstanding	40,535,191		40,408,033		40,308,562		40,211,717		40,126,647
Dividends declared per share of common stock	$	1.315	$	1.225	$	1.165	$	1.105	$	1.045
Cash additions to utility property, plant and equipment	$	190,305	$	225,361	$	281,458	$	277,078	$	237,411
Total assets (a)	$	3,484,363	$	3,376,278	$	3,200,607	$	3,033,400	$	2,748,139
Long-term debt, net of current portion (a)	$	1,195,988	$	1,195,513	$	1,122,660	$	1,122,235	$	988,436
Common stock equity	$	1,142,165	$	1,074,396	$	1,016,538	$	984,254	$	943,833

________________

(a) The Company implemented Accounting Standards Update ("ASU") 2015-03, Interest- Imputation of Interest (Topic 715) and ASU 2015-17, Balance Sheet Classification of Deferred Taxes in the first quarter of 2016, retrospectively to all periods presented in the table above.

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Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

As you read this Management’s Discussion and Analysis of Financial Condition and Results of Operations, please refer to our Financial Statements and the accompanying notes, which contain our operating results.

Summary of Critical Accounting Policies and Estimates

Our financial statements have been prepared in conformity with U.S. Generally Accepted Accounting Principles ("GAAP"). Part II, Item 8, Financial Statements and Supplementary Data, Note A of Notes to Financial Statements contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions. We believe that of our significant accounting policies, the following are noteworthy because they are based on estimates and assumptions that require complex, subjective assumptions by management, which can materially impact reported results. 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"). Changes in these estimates or assumptions, or actual results that are different, could materially impact our financial condition and results of operation.

Regulatory Accounting

We apply accounting standards that recognize the economic effects of rate regulation in our Texas, New Mexico and FERC jurisdictions. As a result, we record certain costs or obligations as either assets or liabilities on our balance sheet and amortize them in subsequent periods as they are reflected in regulated rates. The deferral of costs as regulatory assets is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific regulatory orders, regulatory precedent and the current regulatory environment. As of December 31, 2017, we had recorded regulatory assets currently subject to recovery in future rates of approximately $96.0 million and regulatory liabilities of approximately $296.7 million as discussed in greater detail in Part II, Item 8, Financial Statements and Supplementary Data, Notes D and J of the Notes to Financial Statements. Regulatory tax assets of approximately $19.6 million related to the regulatory treatment of the equity portion of AFUDC and approximately $20.9 million related to excess deferred state income taxes are included in regulatory assets. Regulatory tax liabilities of approximately $289.0 million, primarily related to the reduction of the corporate tax rate from 35% to 21%, are included in regulatory liabilities and will be refunded to customers.

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

Collection of Fuel Expense

In general, by law and regulation, our actual fuel and purchased power expenses are recovered from our customers. In times of rising fuel prices, we experience a lag in recovery of higher fuel costs. These costs are subject to reconciliation by the PUCT on a periodic basis every one to three years. The NMPRC, in its discretion, may order that a prudence review be conducted to assure that fuel and purchased power costs recovered from customers are prudently incurred. Prior to the completion of a reconciliation proceeding or audit, we record fuel transactions such that fuel revenues, including fuel costs recovered through the FPPCAC in New Mexico, equal fuel expense. In the event that a disallowance of fuel cost recovery occurs during a reconciliation proceeding or an audit, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we could incur a loss to the extent of the disallowance.

On September 27, 2016, the Company filed an application with the PUCT, designated as PUCT Docket No. 46308, to reconcile $436.6 million of Texas fuel and purchased power expenses incurred during the period of April 1, 2013 through March 31, 2016. On June 29, 2017, the PUCT approved a settlement in this proceeding. The settlement provides for the reconciliation of fuel and purchased power costs incurred from April 1, 2013 through March 31, 2016. As of December 31, 2017, Texas jurisdictional fuel and purchased power costs subject to prudence review are costs from April 1, 2016 through December 31, 2017 that total approximately $250.9 million. The Company's request to reconcile its fuel and purchased power costs for the period January 1, 2013 through December 31, 2014 was approved in Case No. 15-00127-UT. New Mexico jurisdictional costs subject to prudence review are costs from January 1, 2015 through December 31, 2017 that total approximately $173.1 million.

The Company recovers fuel and purchased power costs from the RGEC pursuant to an ongoing contract with a two-year notice to terminate provision. The contract includes a fuel adjustment clause designed to recover all eligible fuel and purchased power costs allocable to the RGEC and is updated on an annual basis. This update is reviewed and approved by the RGEC annually

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in February following the prior calendar year. As of December 31, 2017, the RGEC fuel costs subject to prudence review were approximately $1.4 million.

Decommissioning Costs and Estimated Asset Retirement Obligation

Pursuant to the ANPP Participation Agreement, the rules and regulations of the Nuclear Regulatory Commission and federal law, we must fund our share of the estimated costs to decommission Palo Verde Units 1, 2, 3 and associated common areas. The determination of the estimated liability is based on site-specific estimates, which are updated every three years and involve numerous judgments and assumptions, including estimates of future decommissioning costs at current price levels, escalation rates and discount rates. The Palo Verde ARO is approximately $90.6 million and represents approximately 97% of our total ARO balance of $93.0 million as of December 31, 2017. A 10% increase in the estimates of future Palo Verde decommissioning costs at current price levels would have increased the ARO liability by approximately $10.1 million at December 31, 2017. For further details see Part II, Item 8, "Financial Statements and Supplementary Data, Note E of Notes to Financial Statements."

We are required to fund estimated nuclear decommissioning costs over the life of the generating facilities through the use of external trust funds pursuant to rules of the NRC, PUCT and the ANPP Participation Agreement. Historically, in Texas and New Mexico, we have been permitted to collect the funding requirements for our nuclear decommissioning trusts as part of our rates, except for a portion of Palo Verde Unit 3, which is deregulated in the New Mexico jurisdiction. While we periodically attempt to seek to recover the costs of decommissioning obligations through our rates, we are not able to conclude, given the currently available evidence, that it is probable these costs will continue to be collected over the period until decommissioning begins in 2044. We are ultimately responsible for these costs, and our future actions combined with future decisions from regulators will determine how successful we are in this effort.

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

Our decommissioning trust funds consist of equity securities and fixed income instruments and are carried at fair value. We face interest rate risk on the fixed income instruments, which consist primarily of municipal, federal and corporate bonds and which were valued at $130.2 million as of December 31, 2017. A hypothetical 10% increase in interest rates would have reduced the fair values of these funds by $1.6 million at December 31, 2017. Our decommissioning trust funds also include marketable equity securities of approximately $149.8 million at December 31, 2017. A hypothetical 20% decrease in equity prices would have reduced the fair values of these funds by $30.0 million at December 31, 2017. Declines in market prices could require that additional amounts be contributed to our nuclear decommissioning trusts to maintain minimum funding requirements.

We do not anticipate expending monies held in the nuclear decommissioning trusts before 2044 or a later period when decommissioning of Palo Verde begins.

Future Pension and Other Post-retirement Obligations

We maintain a qualified noncontributory defined benefit pension plan, which covers substantially all of our employees, and two non-funded nonqualified supplement plans that provide benefits in excess of amounts permitted under the provisions of the tax law for certain participants in the qualified plan. We also sponsor a plan that provides other post-retirement benefits, such as health and life insurance benefits to retired employees. Our net obligations under these various benefit plans at December 31, 2017 totaled $112.4 million and are recorded as liabilities on our balance sheet. The net periodic benefit costs for these plans totaled $2.6 million for the twelve months ended December 31, 2017.

During October 2016, we approved and communicated a plan amendment that resulted in a remeasurement of our other post-retirement benefit plan. Effective January 1, 2017, retirees and dependents that are less than 65 years of age are offered a choice between a $1,000 and $2,250 deductible plan. Additionally, retirees and dependents that are 65 years of age or greater are covered by a fully insured Medicare advantage plan. The impact of these plan changes was a reduction in the other post-retirement benefit plan obligation of $32.7 million as of December 31, 2016.

Our pension and other post-retirement benefit liabilities and the related net periodic benefit costs are calculated on the basis of a number of actuarial assumptions regarding discount rates, expected return on plan assets, rate of compensation increase, life expectancy of retirees and health care cost inflation. For 2017, the discount rates used to measure our year end liabilities are based on a segmented spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. As of December 31, 2017, the corresponding weighted-average discount rates range from 3.40% to 3.81% depending upon the benefit plan.

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Our overall expected gross long-term rate of return on assets for the pension trust fund is 7.5% effective January 1, 2018, which is both a pre-tax and after-tax rate as pension funds are generally not subject to income tax. Our overall expected gross long-term rate of return on assets for the other post-retirement benefits trust, on an after-tax basis, is 6.12% effective January 1, 2018. Both expected gross long-term rates of return are based on the after-tax weighted average of the expected returns on investments. The expected returns on investments in the pension trust and the other post-retirement benefits trust are based upon the target asset allocations for the two trusts.

Our accrued post-retirement benefit liability and the service and interest components of the related net periodic benefit costs are calculated using an actuarial assumption regarding health care cost inflation. For measurement purposes, a 6.25%, 7.25%, 4.5% and 10.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2018 for pre-65 medical, pre-65 drug, post-65 medical and post-65 drug, respectively. The health care cost trend rates are assumed to decline steadily to an ultimate rate of 4.5% by 2025 for pre-65 medical and by 2026 for pre-65 and post-65 drug. Post-65 medical trend is assumed to be 4.5% for all years into the future. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan.

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

In 2016, we changed the method used to estimate the service and interest components of net periodic benefit cost for pension and other post-retirement benefits . This change, compared to the previous method, resulted in a decrease in the service cost and interest cost components of net periodic benefit cost for pension and other post-retirement benefits in 2016 by approximately $2.9 million and $0.8 million, respectively. Historically, we estimated service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. In 2016, we elected to utilize a full yield curve approach to estimate these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows. We believe the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plan’s liability cash flows to the corresponding spot rates on the yield curve. We accounted for this change as a change in accounting estimate and accordingly, accounted for this prospectively.

The following table reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2017 reported pension liability and our 2017 reported pension expense (in thousands):



	Increase (Decrease)
Actuarial Assumption	Impact on Pension Liability			Impact on Pension Expense
Discount rate:
Increase 1%	$	(48,577	)	$	(3,751	)
Decrease 1%	60,731			4,537
Expected long-term rate of return on plan assets:
Increase 1%	N/A			(2,742		)
Decrease 1%	N/A			2,742
Compensation rate:
Increase 1%	10,044			1,318
Decrease 1%	(9,007		)	(1,148		)

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The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2017 other post-retirement benefit obligations and our 2017 reported other post-retirement benefit expense (in thousands):



	Increase (Decrease)
Actuarial Assumption	Impact on Other Post-retirement Benefit Obligation			Impact on Other Post-retirement Benefit Expense			Impact on Other Post-retirement Service and Interest Cost
Discount rate:
Increase 1%	$	(9,582	)	$	(1,212	)	$	(277	)
Decrease 1%	12,444			1,383			359
Healthcare cost trend rate:
Increase 1%	11,315			2,141			1,117
Decrease 1%	(8,828		)	(1,666		)	(848		)
Expected long-term rate of return on plan assets:
Increase 1%	N/A			(391		)	N/A
Decrease 1%	N/A			391			N/A

Tax Accruals

We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The application of income tax law and regulations is complex and we make judgments regarding income tax exposures. Changes in these judgments, due to changes in law, regulation, interpretation or audit adjustments can materially affect amounts we recognize in our financial statements. On December 22, 2017, the TCJA was enacted. Substantially all of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes significant changes to the IRC, including amendments which significantly change the taxation of business entities and includes specific provisions related to regulated public utilities. See Note J of the Notes to Financial Statements for more information.

When appropriate, we record a valuation allowance against deferred tax assets to reflect that these tax assets may not be realized. In assessing the likelihood of the realization of deferred tax assets, management considers the estimated amount and character of future taxable income. Significant changes in these judgments and estimates could have a material impact on the results of operations and financial position of the Company. There were no valuation allowances for deferred tax assets as of December 31, 2017.

We recognize tax benefits that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50% likely to be realized upon settlement. The unrecognized tax benefits that do not meet the recognition and measurement standards were $3.2 million as of December 31, 2017.

Overview

The following is an overview of our results of operations for the years ended December 31, 2017 , 2016 and 2015 . Net income and basic earnings per share for the years ended December 31, 2017 , 2016 and 2015 are shown below:



	Years Ended December 31,
	2017		2016		2015
Net income (in thousands)	$	98,261	$	96,768	$	81,918
Basic earnings per share	2.42		2.39		2.03

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Financial Effect of the PUCT Final Order

On December 18, 2017, the PUCT issued the 2017 PUCT Final Order. See Part II, Item 8, "Financial Statements and Supplementary Data, Note C of Notes to Financial Statements."

The increase (decrease) on operations resulting from the 2017 PUCT Final Order is categorized in the following periods based on consumption (in thousands):



	Three Months Ended										Twelve Months Ended
Category	March 31, 2017		June 30, 2017		September 30, 2017			December 31, 2017			December 31, 2017
Retail non-fuel base rate increase:
Relate back	$	—	$	—	$	4,753		$	4,023		$	8,776
Depreciation and amortization expense	—		—		(278		)	(435		)	(713		)
Rate case expense	—		—		—			(58		)	(58		)
Pre-tax increase	$	—	$	—	$	4,475		$	3,530		$	8,005
Income tax expense	—		—		1,566			1,236			2,802
After-tax increase	$	—	$	—	$	2,909		$	2,294		$	5,203

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The following table and accompanying explanations show the primary factors affecting the after-tax change in income between the calendar years ended December 31, 2017 and 2016 , 2016 and 2015 , and 2015 and 2014 (in thousands):



	2017				2016				2015
Prior year December 31 net income	$	96,768			$	81,918			$	91,428
Changes (net of tax):
Increased retail non-fuel base revenues	8,651			(a)	28,802			(b)	9,290			(c)
Effective tax rate	3,379			(d)	(5,343		)	(e)	1,540			(f)
Increased (decreased) non-base revenue, net of energy expense	3,213			(g)	804				(5,370		)	(h)
Increased (decreased) investment and interest income	2,825			(i)	(2,784		)	(i)	3,084			(i)
Decreased allowance for funds used during construction	(5,303		)	(j)	(4,887		)	(k)	(4,953		)	(l)
(Increased) decreased depreciation and amortization	(4,242		)	(m)	3,580			(n)	(4,214		)	(o)
Increased taxes other than income taxes	(3,465		)	(p)	(1,168		)	(q)	(641		)
Increased interest on long-term debt (net of capitalized interest)	(927		)		(3,700		)	(r)	(4,516		)	(s)
Other	(2,638		)		(454		)		(3,730		)
Current year December 31 net income	$	98,261			$	96,768			$	81,918

______________________

Footnotes reflect pre-tax amounts

(a)

Increased retail non-fuel base revenues primarily due to the non-fuel base rate increase approved in the 2017 PUCT Final Order. 2017 included approximately $8.8 million of retail non-fuel base revenues for the period from July 18, 2017 through December 31, 2017, which was recognized when the 2017 PUCT Final Order was approved in December 2017. Excluding the $8.8 million 2017 PUCT Final Order impact, retail non-fuel base revenues increased $4.5 million, or 0.7%, in 2017 compared to 2016.


(b)	Increased retail non-fuel base revenues primarily due to the recognition of $40.9 million related to the 2016 PUCT Final Order.


(c)	Retail non-fuel base revenues increased, primarily due to hotter weather in the third quarter of 2015 contributing to an increase in kWh sales and an increase in the average number of customers.


(d)	The effective tax rate decreased primarily due to a reduction in state income taxes primarily due to audit settlements.


(e)	The effective tax rate increased due to the change to normalize state income taxes in accordance with the 2016 PUCT Final Order and the NMPRC Final Order.


(f)	The effective tax rate decreased due to a decrease in state income taxes and an increase in decommissioning income. These decreases were partially offset by a decrease in the allowance for equity funds used during construction ("AEFUDC") and the loss of the domestic production activities deduction in 2015.

(g)

Non-base revenues, net of energy expenses increased due to: (i) the recognition of Palo Verde performance rewards of $5.0 million associated with the 2013 to 2015 performance periods, net of disallowed fuel and purchased power costs related to the resolution for the Texas fuel reconciliation proceeding designated as PUCT Docket No. 46308; (ii) an increase of $1.1 million in other revenues primarily due to an increase in Texas miscellaneous service revenues; (iii) an increase of $1.0 million in deregulated Palo Verde Unit 3 revenues; and (iv) an increase of $1.0 million in energy efficiency bonuses awarded. These increases were partially offset by a decrease of $3.9 million in transmission wheeling revenues due to the expiration of a contract.

(h)

Non-base revenues, net of energy expenses decreased due to: (i) a decrease of $5.3 million in deregulated Palo Verde Unit 3 revenues; (ii) the recognition in 2014 of Palo Verde performance rewards of $2.2 million associated with the 2009 to 2012 performance periods, net of disallowed fuel and purchased power costs related to the resolution for the Texas fuel reconciliation proceeding designated as PUCT Docket No. 41852; and (iii) a decrease of $0.7 million in energy efficiency bonuses awarded. These decreases were partially offset by an increase of $1.7 million in transmission wheeling revenues.


(i)	Investment and interest income increased in 2017, decreased in 2016 and increased in 2015, primarily due to changes in realized gains on securities sold from the Company’s Palo Verde decommissioning trust. Sales of such securities are primarily the result of the Company's efforts to re-balance and further diversify the trust fund investments.


(j)	AFUDC decreased due to lower balances of construction work in progress ("CWIP"), primarily due to MPS Units 3 and 4 being placed in service in May and September 2016, respectively, and a reduction in the AFUDC rate effective January 2017.


(k)	AFUDC decreased due to lower balances of CWIP, primarily due to the MPS units and the Eastside Operations Center ("EOC") being placed in service in 2015 and 2016, and a reduction in the AFUDC rate effective January 2016 as a result of the 2016 PUCT Final Order.

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(l)	AFUDC decreased primarily due to lower balances of CWIP primarily due to MPS Units 1 and 2, and the EOC being placed in service during the first quarter of 2015 and a reduction in the AFUDC rate.


(m)	Depreciation and amortization increased primarily due to increases in plant, including MPS Units 3 and 4, which were placed in service in 2016. These increases were partially offset by the sale of the Company's interest in Four Corners in July 2016.

(n)

Depreciation and amortization decreased primarily due to (i) a reduction of approximately $10.9 million resulting from changes in depreciation rates approved in the 2016 PUCT Final Order and the NMPRC Final Order and (ii) the sale of the Company's interest in Four Corners in 2016. These decreases were partially offset by an increase in plant, primarily due to MPS Units 1 and 2 and the EOC each being placed in service in March 2015, and MPS Units 3 and 4 being placed in service in May 2016 and September 2016, respectively.


(o)	Depreciation and amortization increased due to increased depreciable plant balances including MPS Units 1 and 2 and the EOC which began commercial operation in the first quarter of 2015, partially offset by a change in the estimated useful life of certain large intangible software systems.


(p)	Taxes other than income taxes increased primarily due to increased property valuations in Texas as a result of MPS Units 3 and 4 being placed in service in 2016 and increased revenue related taxes in Texas.


(q)	Taxes other than income taxes increased primarily due to increased property tax rates and valuations in Texas as a result of MPS Units 1 and 2 and the EOC being placed in service during the first quarter of 2015 and increased billed revenues for Texas revenue related taxes. These increases were partially offset by decreased property taxes in Arizona due to lower property values.


(r)	Interest on long-term debt increased, primarily due to the $150.0 million principal amount of senior notes issued in March 2016.


(s)	Interest on long-term debt increased, primarily due to the $150.0 million principal amount of senior notes issued in December 2014.

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Historical Results of Operations

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

Operating revenues

We realize revenue from the sale of electricity to retail customers at regulated rates and the sale of energy in the wholesale power market generally at market-based prices. Sales for resale (which are FERC regulated cost-based wholesale sales within our service territory), accounted for less than 1% of revenues in each of 2017, 2016 and 2015.

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 NMPRC Final Order, fuel costs are no longer recovered through base rates. Beginning July 1, 2016, all fuel costs are recovered through a fuel adjustment mechanism. We record deferred fuel revenues for the difference between actual fuel costs and recoverable fuel revenues until such amounts are collected from or refunded to customers. "Non-fuel base revenues" refers to our revenues from the sale of electricity excluding such fuel costs.

Retail non-fuel base revenue percentages by customer class are presented below:



	Years Ended December 31,
	2017		2016		2015
Residential	46	%	46	%	44	%
Commercial and industrial, small	32		32		33
Commercial and industrial, large	6		6		7
Sales to public authorities	16		16		16
Total retail non-fuel base revenues	100	%	100	%	100	%

No retail customer accounted for more than 3% of our non-fuel base revenues during such periods. As shown in the table above, residential and small commercial customers represent approximately 78% 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. The following table sets forth the percentage of our retail non-fuel base revenues derived during each quarter for the periods presented:



	Years Ended December 31,
	2017		2016		2015
January 1 to March 31	18	%	17	%	18	%
April 1 to June 30	27		25		26
July 1 to September 30	34		38		35
October 1 to December 31	21		20		21
Total	100	%	100	%	100	%

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. The table below shows heating and cooling degree days compared to a 10-year average for 2017, 2016 and 2015.



	2017	2016	2015	10-year Average
Cooling degree days	2,917	2,811	2,839	2,773
Heating degree days	1,522	1,851	2,095	2,081

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Customer growth is a key driver of the growth of retail sales. The average number of retail customers grew 1.7% and 1.5% in 2017 and 2016, respectively. See the tables presented on pages 38 and 39 which provide detail on the average number of retail customers and the related revenues and kWh sales.

Retail non-fuel base revenues . For the twelve months ended December 31, 2017, retail non-fuel base revenues increased primarily due to the recognition of $8.8 million approved in the 2017 PUCT Final Order. Excluding the $8.8 million 2017 PUCT Final Order impact, for the twelve months ended December 31, 2017, retail non-fuel base revenues increased $4.5 million, or 0.7%, compared to the twelve months ended December 31, 2016. This increase was primarily due to increased revenues from residential customers of $2.5 million driven by a 1.6% increase in the average number of residential customers served and increased revenues from small commercial and industrial customers of $2.1 million driven by a 2.4% increase in the average number of small commercial and industrial customers served. The Company experienced an overall 1.7% increase in the average number of customers served, partially offset by milder weather when compared to the twelve months ended December 31, 2016. Heating degree days decreased 17.8% in the twelve months ended December 31, 2017, when compared to the twelve months ended December 31, 2016. During our peak summer cooling season, cooling degree days in 2017 were comparable to the same period in 2016.

For the twelve months ended December 31, 2016, retail non-fuel base revenues increased primarily due to the recognition of $40.9 million related to the 2016 PUCT Final Order. Excluding the $40.9 million 2016 PUCT Final Order impact, for the twelve months ended December 31, 2016, retail non-fuel base revenues increased $3.4 million, or 0.6%, compared to the twelve months ended December 31, 2015. This increase was primarily due to increased revenues from residential customers of $3.5 million due to a 1.3% increase in kWh sales and increased revenues from small commercial and industrial customers of $2.5 million due to a 0.8% increase in kWh sales. Increased kWh sales from residential customers and small commercial and industrial customers were driven by a 1.4% and 1.9% increase in the average number of customers, respectively, offset in part by milder weather during the twelve months ended December 31, 2016 compared to the twelve months ended December 31, 2015. Revenues decreased $2.4 million from large commercial and industrial customers during the twelve months ended December 31, 2016 compared to the twelve months ended December 31, 2015 due to a 3.0% decrease in kWh sales, due primarily to reduced demand by the steel manufacturing industry, and a decrease in surcharges billed to a large customer in 2016 compared to 2015. Revenues decreased $0.2 million from public authority customers reflecting a 0.8% decrease in kWh sales. Cooling degree days were relatively consistent with 2015 and were 2.9% over the 10-year average. Heating degree days decreased 11.6% in 2016, compared to 2015, and were 14.2% below the 10-year average.

Fuel revenues . Fuel revenues consist of (i) revenues collected from customers under fuel recovery mechanisms approved by the state commissions and the FERC, (ii) deferred fuel revenues which are comprised of the difference between fuel costs and fuel revenues collected from customers and (iii) prior to July 1, 2016, fuel costs recovered in base rates in New Mexico. In New Mexico, effective July 1, 2016, with the implementation of the NMPRC Final Order, fuel and purchased power costs are no longer recovered through base rates, as it was historically, but are 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. In Texas, fuel costs are recovered through a fixed fuel factor. We can seek to revise our Texas 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 March 2017 and March 2016, $1.4 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.

We over-recovered fuel costs by $17.1 million in the twelve months ended December 31, 2017. We under-recovered fuel costs by $14.9 million and over-recovered fuel costs by $13.3 million in the twelve months ended December 31, 2016 and 2015, respectively. At December 31, 2017, we had a net fuel over-recovery balance of $6.2 million, including an over-recovery of $5.8 million and $0.4 million in Texas and in New Mexico, respectively. On October 13, 2017, we filed a request to decrease our Texas fixed fuel factor by approximately 19.0% to reflect decreased fuel expenses primarily related to a decrease in the price of natural gas used to generate power. The decrease in our Texas fixed fuel factor became effective beginning with the November 2017 billing month and will continue thereafter until changed by the PUCT.

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 in PUCT Docket No. 41852) 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, could not exceed 10% of the total margins assignable to the Texas retail jurisdiction on all off-system sales. 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.

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

The table below shows MWhs, sales revenue, fuel cost, total margins and retained margins made on off-system sales for the twelve months ended December 31, 2017 , 2016 and 2015 (in thousands, except for MWhs).



	Years Ended December 31,
	2017		2016		2015
MWh sales	2,042,884		1,927,508		2,500,947
Sales revenue	$	58,986	$	45,702	$	64,816
Fuel cost	$	46,258	$	38,933	$	52,406
Total margins	$	12,728	$	6,769	$	12,410
Retained margins	$	1,673	$	1,137	$	1,362

Off-system sales revenue increased $13.3 million, or 29.1%, and the related retained margins increased $0.5 million, or 47.1%, for the twelve months ended December 31, 2017 when compared to 2016 as a result of higher average market prices for power and a 6.0% increase in MWh sales. Off-system sales revenue decreased $19.1 million, or 29.5%, and the related retained margins decreased $0.2 million, or 16.5%, for the twelve months ended December 31, 2016 when compared to 2015 as a result of lower average market prices for power and a 22.9% decrease in MWh sales.

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Comparisons of kWh sales and operating revenues are shown below:



						Increase (Decrease)
Years Ended December 31:	2017			2016		Amount			Percent
kWh sales (in thousands):
Retail:
Residential	2,823,260			2,805,789		17,471			0.6	%
Commercial and industrial, small	2,410,710			2,403,447		7,263			0.3
Commercial and industrial, large	1,045,319			1,030,745		14,574			1.4
Sales to public authorities	1,564,670			1,572,510		(7,840		)	(0.5	)
Total retail sales	7,843,959			7,812,491		31,468			0.4
Wholesale:
Sales for resale	62,887			62,086		801			1.3
Off-system sales	2,042,884			1,927,508		115,376			6.0
Total wholesale sales	2,105,771			1,989,594		116,177			5.8
Total kWh sales	9,949,730			9,802,085		147,645			1.5
Operating revenues (in thousands):
Non-fuel base revenues:
Retail:
Residential	$	287,884		$	278,774	$	9,110		3.3	%
Commercial and industrial, small	198,799			194,942		3,857			2.0
Commercial and industrial, large	38,403			39,070		(667		)	(1.7	)
Sales to public authorities	97,890			96,881		1,009			1.0
Total retail non-fuel base revenues (1)	622,976			609,667		13,309			2.2
Wholesale:
Sales for resale	2,730			2,407		323			13.4
Total non-fuel base revenues	625,706			612,074		13,632			2.2
Fuel revenues:
Recovered from customers during the period	218,380			148,397		69,983			47.2
Under (over) collection of fuel (2)	(17,133		)	14,893		(32,026		)	-
New Mexico fuel in base rates (3)	—			33,279		(33,279		)	-
Total fuel revenues (4) (5)	201,247			196,569		4,678			2.4
Off-system sales:
Fuel cost	46,258			38,933		7,325			18.8
Shared margins	11,055			5,632		5,423			96.3
Retained margins	1,673			1,137		536			47.1
Total off-system sales	58,986			45,702		13,284			29.1

Other (6)
Wheeling revenues	18,114			21,966		(3,852		)	(17.5	)
Miscellaneous service revenues and other (7)	12,744			10,625		2,119			19.9
Total other	30,858			32,591		(1,733		)	(5.3	)

Total operating revenues	$	916,797		$	886,936	$	29,861		3.4
Average number of retail customers (8):
Residential	368,044			362,138		5,906			1.6	%
Commercial and industrial, small	41,978			41,014		964			2.4
Commercial and industrial, large	48			49		(1		)	(2.0	)
Sales to public authorities	5,532			5,303		229			4.3
Total	415,602			408,504		7,098			1.7

___________________________


(1)	2017 includes $8.8 million of relate back revenues in Texas from July 18, 2017 through December 31, 2017, which was recorded in the fourth quarter of 2017 related to the 2017 PUCT Final Order.


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


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


(4)	2017 includes $5.0 million related to the Palo Verde performance rewards, net.


(5)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $9.8 million and $8.7 million in 2017 and 2016, respectively.


(6)	Represents revenues with no related kWh sales.


(7)	Includes an Energy Efficiency Bonus of $1.5 million and $0.5 million in 2017 and 2016, respectively.


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

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						Increase (Decrease)
Years Ended December 31:	2016		2015			Amount			Percent
kWh sales (in thousands):
Retail:
Residential	2,805,789		2,771,138			34,651			1.3	%
Commercial and industrial, small	2,403,447		2,384,514			18,933			0.8
Commercial and industrial, large	1,030,745		1,062,662			(31,917		)	(3.0	)
Sales to public authorities	1,572,510		1,585,568			(13,058		)	(0.8	)
Total retail sales	7,812,491		7,803,882			8,609			0.1
Wholesale:
Sales for resale	62,086		63,347			(1,261		)	(2.0	)
Off-system sales	1,927,508		2,500,947			(573,439		)	(22.9	)
Total wholesale sales	1,989,594		2,564,294			(574,700		)	(22.4	)
Total kWh sales	9,802,085		10,368,176			(566,091		)	(5.5	)
Operating revenues (in thousands):
Non-fuel base revenues:
Retail:
Residential	$	278,774	$	246,265		$	32,509		13.2	%
Commercial and industrial, small	194,942		187,436			7,506			4.0
Commercial and industrial, large	39,070		40,411			(1,341		)	(3.3	)
Sales to public authorities	96,881		91,244			5,637			6.2
Total retail non-fuel base revenues (1)	609,667		565,356			44,311			7.8
Wholesale:
Sales for resale	2,407		2,455			(48		)	(2.0	)
Total non-fuel base revenues	612,074		567,811			44,263			7.8
Fuel revenues:
Recovered from customers during the period	148,397		127,765			20,632			16.1
Under (over) collection of fuel (2)	14,893		(13,342		)	28,235			-
New Mexico fuel in base rates (3)	33,279		72,129			(38,850		)	(53.9	)
Total fuel revenues (4)	196,569		186,552			10,017			5.4
Off-system sales:
Fuel cost	38,933		52,406			(13,473		)	(25.7	)
Shared margins	5,632		11,048			(5,416		)	(49.0	)
Retained margins	1,137		1,362			(225		)	(16.5	)
Total off-system sales	45,702		64,816			(19,114		)	(29.5	)

Other (5)
Wheeling revenues	21,966		21,002			964			4.6
Miscellaneous service revenues and other (6) (7)	10,625		9,688			937			9.7
Total other	32,591		30,690			1,901			6.2

Total operating revenues	$	886,936	$	849,869		$	37,067		4.4
Average number of retail customers (8):
Residential	362,138		356,969			5,169			1.4	%
Commercial and industrial, small	41,014		40,250			764			1.9
Commercial and industrial, large	49		49			—			-
Sales to public authorities	5,303		5,250			53			1.0
Total	408,504		402,518			5,986			1.5

_______________________


(1)	Includes a $40.9 million increase resulting from the 2016 PUCT Final Order.


(2)	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.


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


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


(5)	Represents revenues with no related kWh sales.


(6)	Includes $1.5 million increase resulting from the 2016 PUCT Final Order.


(7)	Includes an Energy Efficiency Bonus of $0.5 million and $1.3 million in 2016 and 2015, respectively.


(8)	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 and natural gas generating plants and purchased power. After adding natural gas generating units MPS Units 1 and 2 in March 2015 and MPS Units 3 and 4 in May 2016 and September 2016, respectively, into the Company's system generating resources, Palo Verde represents approximately 30% of our net dependable generating capacity and approximately 57% of our Company-generated energy for the twelve months ended December 31, 2017. Fluctuations in the price of natural gas, which is also the primary factor influencing the price of purchased power, have had a significant impact on our cost of energy.

Energy expenses increased $11.3 million, or 4.8%, for the twelve months ended December 31, 2017 compared to the twelve months ended December 31, 2016, primarily due to increased natural gas costs of $18.4 million due to an 8.2% increase in the MWhs generated with natural gas and a 6.2% increase in the average cost of MWhs generated. This increase in energy expenses was partially offset by decreased coal costs of $5.6 million as a result of the sale of our interest in Four Corners, a coal-fired generation station, in July 2016.

Energy expenses decreased $8.5 million, or 3.5%, for the twelve months ended December 31, 2016 compared to the twelve months ended December 31, 2015, primarily due to (i) decreased natural gas costs of $10.6 million due to a 6.3% decrease in the MWhs generated with natural gas and (ii) decreased coal costs of $7.8 million as a result of the sale of our interest in Four Corners, a coal-fired generation station, on July 6, 2016. These decreases in energy expenses were partially offset by (i) increased total purchased power of $6.2 million due to an 11.6% increase in the MWhs purchased and (ii) increased nuclear fuel expense of $3.7 million due to a $4.6 million reduction in the 2016 DOE refund compared to 2015.

The table below details the sources and costs of energy for 2017, 2016 and 2015.



	2017						2016
Fuel Type	Cost			MWh	Cost per MWh		Cost			MWh	Cost per MWh
	(in thousands)						(in thousands)
Natural Gas	$	142,227		3,841,550	$	37.02	$	123,806		3,550,904	$	34.87
Coal	575		(a)	—	—		6,154		(a)	175,258	35.11
Nuclear	42,267		(b)	5,109,325	8.58		43,778		(b)	5,093,844	8.94
Total	185,069			8,950,875	20.85		173,738			8,820,006	19.90
Purchase Power:
Photovoltaic	23,784			292,157	81.41		23,413			289,800	80.79
Other	35,898			1,248,684	28.75		36,314			1,262,451	28.76
Total purchased power	59,682			1,540,841	38.73		59,727			1,552,251	38.48
Total energy	$	244,751		10,491,716	23.48		$	233,465		10,372,257	22.68


	2015
Fuel Type	Cost			MWh	Cost per MWh
	(in thousands)
Natural Gas	$	134,361		3,790,659	$	35.45
Coal	13,913			657,744	21.15
Nuclear	40,126		(b)	5,136,686	9.06
Total	188,400			9,585,089	20.32
Purchase Power:
Photovoltaic	22,495			277,241	81.14
Other	31,050			1,113,705	27.88
Total purchased power	53,545			1,390,946	38.50
Total energy	$	241,945		10,976,035	22.63

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(a) The sale of our interest in Four Corners, a coal-fired generation station, closed on July 6, 2016. The cost includes the amortization of deferred coal mine reclamation obligations.

(b) Costs includes a DOE refund related to spent fuel storage of $1.6 million, $1.8 million, and $6.4 million recorded in 2017, 2016, and 2015, respectively. Cost per MWh excludes these refunds.

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Other operations expense

Other operations expense increased $0.6 million, or 0.3%, in 2017 compared to 2016, primarily due to a $4.1 million increase in Palo Verde administrative and general ("A&G") expenses in 2017 compared to 2016, and a $3.0 million increase in various other operating costs. This increase was partially offset by a $6.5 million decrease in operating costs as a result of the sale of our interest in Four Corners in July 2016.

Other operations expense decreased $0.9 million, or 0.4%, in 2016 compared to 2015, primarily due to (i) a $2.7 million decrease in pension and benefits costs due to an amendment to the other post-retirement benefit plan and changes in actuarial assumptions used to calculate expenses for the post-retirement benefit plans, partially offset by higher medical and other employee benefit costs, (ii) decreased operations expense of $0.9 million at our fossil-fuel generating plants, primarily due to lower operating costs as a result of the sale of our interest in Four Corners in July 2016 offset by increased operating expenses at MPS, and (iii) decreased other A&G expenses of $0.5 million. These decreases were partially offset by (i) a $2.3 million increase in regulatory expenses, primarily related to the portion of the 2015 New Mexico and Texas rate cases that were expensed, and (ii) increased transmission and distribution expenses of $0.8 million.

Maintenance expense

Maintenance expense increased $2.7 million, or 4.1%, in 2017 compared to 2016, primarily due to a $7.1 million increase in maintenance outages at Newman Units 1, 3, & 4, and a $3.9 million increase in routine maintenance at Newman and MPS. These increases were offset by a $5.6 million decrease in maintenance costs as a result of the sale of our interest in Four Corners in July 2016 and a $1.7 million decrease in Palo Verde maintenance costs. Maintenance expense increased $1.5 million, or 2.3%, in 2016 compared to 2015, primarily due to an increase in the level of maintenance at Rio Grande and a planned outage at Four Corners, which was partially offset by a decrease in maintenance at Newman.

Depreciation and amortization expense

Depreciation and amortization expense increased $6.5 million or 7.7%, in 2017 compared to 2016, primarily due to increases in plant, including MPS Units 3 and 4, which were placed in service in May 2016 and September 2016, respectively. These increases were partially offset by the sale of the Company's interest in Four Corners in July 2016.

Depreciation and amortization expense decreased $5.5 million or 6.1%, in 2016 compared to 2015, primarily due to reductions of approximately $10.9 million resulting from changes in depreciation rates approved in the 2016 PUCT Final Order and the NMPRC Final Order, and the sale of the Company's interest in Four Corners in July 2016. These decreases were partially offset by an increase in plant, primarily due to MPS Units 1 and 2 and the EOC being placed in service in March 2015, and MPS Units 3 and 4 being placed in service in 2016.

Taxes other than income taxes

Taxes other than income taxes increased $5.3 million, or 8.1%, in 2017 compared to 2016, primarily due to increased property tax rates and valuations in Texas as a result of MPS Units 3 and 4 being placed in service in 2016 and increased billed revenues in Texas. Taxes other than income taxes increased $1.8 million, or 2.8%, in 2016 compared to 2015, primarily due to increased property tax rates and valuations in Texas as a result of MPS Units 1 and 2 and the EOC being placed in service during the first quarter of 2015 and increased billed revenues in Texas. These increases were partially offset by decreased property taxes in Arizona due to decreased property values.

Other income (deductions)

Other income (deductions) decreased $0.3 million, or 1.7%, in 2017 compared to 2016, primarily due to decreased AEFUDC resulting from lower average balances of CWIP and a reduction in the AEFUDC rate. This decrease was partially offset by increased investment and interest income due to higher realized gains in our decommissioning trust funds.

Other income (deductions) decreased $7.2 million, or 27.8%, in 2016 compared to 2015, primarily due to (i) decreased AEFUDC resulting from lower average balances of CWIP and a reduction in the AEFUDC rate, and (ii) decreased investment and interest income due to lower realized gains from our decommissioning trust funds.

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Interest charges (credits)

Interest charges (credits) increased by $4.5 million, or 7.1%, in 2017 compared to 2016 , primarily due to decreased allowance for borrowed funds used during construction ("ABFUDC") as a result of lower average balances of CWIP and a reduction in the ABFUDC rate and interest expense on the $150.0 million aggregate principal amount of 5.00% Senior Notes due 2044 issued in March 2016.

Interest charges (credits) increased by $7.6 million, or 13.8%, in 2016 compared to 2015 primarily due to interest expense on the $150.0 million aggregate principal amount of 5.00% Senior Notes due 2044 issued in March 2016 and decreased ABFUDC as a result of lower balances of CWIP and a reduction in the ABFUDC rate.

Income tax expense

Income tax expense decreased by $ 2.9 million, or 5.4% , in 2017 compared to 2016 , primarily due to a decrease in state income tax due to audit settlements in Texas and Arizona. Income tax expense increased by $19.0 million, or 54.5%, in 2016 compared to 2015 , primarily due to (i) an increase in the pre-tax income, (ii) an increase in state income taxes due to normalization as discussed in Note J of the Notes to Financial Statements and (iii) decreases in decommissioning trust income, which is taxed at a lower rate.

New accounting standards

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. We adopted the new standard effective January 1, 2017. The adoption of the new standard did not have a material impact on our financial condition, results of operations or cash flows. The cumulative effect of the adoption of the new standard was to increase net operating loss carryforward deferred tax assets and retained earnings by $0.2 million on January 1, 2017.

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, and has since modified the standard with several ASUs. The standard 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. More specifically, the standard requires entities to recognize revenue through the application of a five-step model, which includes the: (i) identification of the contract; (ii) identification of the performance obligations; (iii) determination of the transaction price; (iv) allocation of the transaction price to the performance obligations; and (v) the recognition of revenue as the entity satisfies the performance obligations. We will adopt the new standard for reporting periods beginning on January 1, 2018, and intend use the modified retrospective approach.

We have analyzed the impact of the new standard on our various revenue and cash flow streams, and the impact on changes to business processes, systems and controls to support recognition under the new guidance. Tariff sales to customers are determined to be in the scope of the new standard and represent a significant portion of our total operating revenues. We have determined that the timing or pattern of revenue recognition from tariff sales will not change. Implementation of the new standard will also not significantly change the timing or pattern of revenue recognition from other revenue streams. Upon adoption of the standard, we expect our disclosures to disaggregate revenues primarily by tariff based categories and off-system sales.

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 provisions of this ASU become effective for reporting periods beginning after December 15, 2017. Upon adoption of the new standard, we expect to record the cumulative effects as of January 1, 2018 which will result in a net reduction to accumulated other comprehensive income of $41.0 million , net of tax, and a corresponding increase in retained earnings for unrealized gains (losses) related to equity securities owned by us.

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the distinction under previous leases guidance for capital leases and operating leases. The impact of leases reported in our 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 guidance. The lessee is permitted to make an accounting policy election to not recognize lease assets and lease liabilities for short-term leases. Implementation of the standard will be required for reporting periods beginning after December 15, 2018. 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 in the process of evaluating the impact of the new standard, which includes continuing to monitor activities of the FASB, including the impact of the recently issued ASU 2018-01, and the proposed project to allow entities to adopt the standard with a cumulative effect adjustment as of the beginning of the adoption year, while maintaining prior year comparative financial information and disclosures as reported. ASU 2018-01, Land Easement Practical expedient for Transition to Topic 842, provides an optional practical expedient to not evaluate existing or expired land easements under Topic 842, if those land easements were not previously accounted for as leases under Accounting Standards Codification Topic 840. We currently anticipate that we will apply the practical expedient under ASU 2018-01 to our existing or expired land easements as part of our transition to Topic 842. Our evaluation process also includes evaluating the impact, if any, on changes to business processes, systems and controls to support recognition and disclosure under the new guidance; however, at this time we are unable to determine the impact this standard will have on the financial statements and related disclosures.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326). ASU 2016-13 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. The provisions of ASU 2016-13 will be required for reporting periods beginning after December 15, 2019. 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 ASU 2016-13.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) Classification of Certain Cash Receipts and Cash Payments to reduce diversity in practice in how certain cash receipts and cash payments are classified in the statement of cash flows. The provisions of ASU 2016-15 will be required for reporting periods beginning after December 15, 2017. ASU 2016-15 will be applied using a retrospective transition method to each period presented. If it is impracticable to apply ASU 2016-15 retrospectively for some of the issues, the amendments for those issues may be applied prospectively as of the earliest date practicable. We are currently assessing the future impact of this ASU.

In March 2017, the FASB issued ASU 2017-07, Compensation - Retirement Benefits (Topic 715) Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. ASU 2017-07 amends Accounting Standards Codification 715, Compensation - Retirement Benefits, to require companies to present the service cost component of net benefit cost in the income statement line items where compensation cost is reported. Companies will present all other components of net benefit cost separately from the line item(s) that includes the service cost and outside of any subtotal of operating income. In addition, only the service cost component will be eligible for capitalization in assets. The amendments in ASU 2017-07 will be required for reporting periods beginning after December 15, 2017. The amendments in ASU 2017-07 should be applied retrospectively for the income statement presentation of the service cost component and the other components of net benefit costs and prospectively, on and after the effective date, for the capitalization of the service cost component. We expect that the retrospective impact of implementing this ASU on the Statement of Operations for the twelve months ended December 31, 2017 would be an increase in (i) Other operations of $8.2 million , (ii) Other interest of $15.8 million , (iii) Miscellaneous non-operating income of $32.4 million , and (iv) Miscellaneous non-operating deductions of $8.4 million .

In May 2017, the FASB issued ASU 2017-09, Compensation - Stock Compensation (Topic 718), Scope of Modification Accounting, to provide guidance about when to account for a change to the terms or conditions of a share-based payment award as a modification. Under ASU 2017-09, modification accounting is required only if the fair value, the vesting conditions, or the classification of the award (as equity or liability) changes as a result of the change in terms or conditions. The amendments of ASU 2017-09 will be required for reporting periods beginning after December 15, 2017. ASU 2017-09 should be applied prospectively to an award modified on or after the adoption date. We are assessing the future impact of ASU 2017-09; however, we currently do not expect the impact of this ASU to be significant to our financial conditions, results of operations or cash flows.

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ASU 2018-02 allows companies to reclassify stranded taxes from AOCI to retained earnings. The amount of the reclassification would be the difference between the historical corporate income tax rate of 35% and the newly enacted 21% corporate income tax rate. The provisions of ASU 2018-02 are effective for fiscal years and interim periods within that reporting period beginning after December 15, 2018. Early adoption is permitted, including adoption in any interim periods for reporting periods for which financial statements have not been issued. We are currently in the process of evaluating the impact of ASU 2018-02 and its impact on regulated utilities. At December 31, 2017, we have $7.2 million in stranded taxes in AOCI.

Inflation

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

Liquidity and Capital Resources

We continue to maintain a strong balance of common stock equity in our capital structure, which supports our bond ratings, allowing us to obtain financing from the capital markets at a reasonable cost. At December 31, 2017, our capital structure, including common stock, long-term debt, current maturities of long-term debt, and short-term borrowings under our RCF, consisted of 45.5% common stock equity and 54.5% debt. As of December 31, 2017, we had a balance of $7.0 million of cash and cash equivalents. Based on current projections, we believe that we will have adequate liquidity through the issuance of long-term debt, our current cash balances, cash from operations and available borrowings under 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, operating expenses including fuel costs, maintenance costs, security, compliance initiative and taxes.

Capital Requirements. During the twelve months ended December 31, 2017, our capital requirements primarily consisted of expenditures for the construction and purchase of electric utility plant, debt retirements, payments of common stock dividends, and purchases of nuclear fuel. Projected utility construction expenditures are to add new generation, expand and update our transmission and distribution systems, make capital improvements and replacements at Palo Verde and other generating facilities, and make investments in other property and equipment. Estimated cash construction expenditures for all capital projects for 2018 are expected to be approximately $236 million. See Part I, Item 1, "Business - Construction Program." Cash capital expenditures for new electric plant were $190.3 million, net of insurance proceeds, in the twelve months ended December 31, 2017 compared to $225.4 million in the twelve months ended December 31, 2016. Capital requirements for purchases of nuclear fuel were $38.5 million for the twelve months ended December 31, 2017, as compared to $42.4 million for the twelve months ended December 31, 2016.

On December 29, 2017, we paid a quarterly cash dividend of $0.335 per share, or $13.6 million, to shareholders of record as of the close of business on December 15, 2017. We paid a total of $53.3 million in cash dividends during the twelve months ended December 31, 2017. On February 1, 2018, our Board of Directors declared a quarterly cash dividend of $0.335 per share payable on March 30, 2018 to shareholders of record as of the close of business on March 16, 2018. Typically, the Board of Directors reviews the Company's dividend policy annually in the second quarter of each year. In addition, while we do not currently anticipate repurchasing shares of our common stock in 2018, 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 twelve months ended December 31, 2017. As of December 31, 2017, a total of 393,816 shares remain eligible for repurchase under the repurchase program.

We expect to continue to maintain a prudent level of liquidity and monitor market conditions for debt and equity securities. We primarily utilize the distribution of dividends to maintain a balanced capital structure and supplement this effort with share repurchases when appropriate. Our liquidity needs can fluctuate quickly based on fuel prices and other factors and we are continuing to make investments in new electric plant and other assets in order to reliably serve our customers.

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. The following summary describes the major impacts of the TCJA on our liquidity. We continue to evaluate the TCJA and have made assumptions based on information currently available.

The TCJA discontinued bonus depreciation for regulated utilities for property acquired and placed in service after September 27, 2017, which discontinuance will reduce the tax deductions previously available to us for 2017, 2018 and 2019. The decrease

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in tax deductions will result in the utilization of our net operating loss carryforwards (“NOL carryforwards”) approximately two years earlier than anticipated and is expected to result in higher income tax payments beginning in 2019, after the full utilization of NOL carryforwards. However, due to the lower federal corporate income tax rate enacted by the TCJA, our future federal corporate income tax payments will be made at the reduced rate of 21% beginning in 2018. Due to NOL carryforwards, minimal tax payments are expected for 2018, which are mostly related to state income taxes.

However, we expect that the effect of the TCJA on our rates will be beneficial to our customers. Following the enactment of the TCJA and the reduction of the federal corporate income tax rate, revenues collected from our customers in 2018 will be reduced in an amount that approximates the savings in tax expense. This reduction in revenues is expected to negatively impact our cash flows by approximately $26 million to $31 million during 2018.

We continually evaluate our funding requirements related to our retirement plans, other post-retirement benefit plans, and decommissioning trust funds. We contributed $9.8 million and $9.2 million to our retirement plans during both the twelve months ended December 31, 2017 and 2016, respectively. We contributed $0.5 million and $1.7 million to our other post-retirement benefit plans during the twelve months ended December 31, 2017 and 2016, respectively. We contributed $3.8 million and $4.5 million to our decommissioning trust funds in 2017 and 2016, respectively. 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, we and the 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 and 2017, $15.0 million and $50.0 million, respectively, of these senior notes matured and were paid with borrowings under the RCF.

Capital Resources. Cash provided by operations, $288.6 million for the twelve months ended December 31, 2017 and $231.2 million for the twelve months ended December 31, 2016, is a significant source for funding capital requirements. The primary factors affecting the change in cash flows from operations were the change in net over-collection and under-collection of fuel revenues and accounts receivable. 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 and 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 October 13, 2017, we filed a request to decrease our Texas fixed fuel factor by approximately 19% to reflect decreased fuel expenses primarily related to a decrease in the price of natural gas used to generate power. The decrease in our Texas fixed fuel factor became effective with the November 2017 billing month and will continue thereafter until changed by the PUCT. During the twelve months ended December 31, 2017, we had over-recoveries of fuel costs of $17.1 million compared to under-recoveries of fuel costs of $14.9 million during the twelve months ended December 31, 2016. At December 31, 2017, we had a net fuel over-recovery balance of $6.2 million, including an over-recovery of $5.8 million in the Texas jurisdiction and an over-recovery of $0.4 million in the New Mexico jurisdiction.

We maintain the RCF for working capital and general corporate purposes and financing nuclear fuel through RGRT. RGRT, the trust through which we finance our portion of nuclear fuel for Palo Verde, is consolidated in our financial statements. On January 9, 2017, we exercised our option to extend the maturity of the RCF by one year to January 14, 2020 and to increase the size of the facility by $50.0 million to $350.0 million. We still have the option to extend the facility by one additional year to January 2021 and to increase the RCF by up to $50.0 million (up to a total of $400.0 million) upon the satisfaction of certain conditions including obtaining commitments from lenders or third party financial institutions. In August 2017, RGRT's $50.0 million Series B 4.47% Senior Notes matured and were paid utilizing funds borrowed under the RCF. The total amount borrowed for nuclear fuel by RGRT, excluding debt issuance costs, was $133.5 million at December 31, 2017, of which $88.5 million had been borrowed under the RCF, and $45.0 million was borrowed through the issuance of senior notes. At December 31, 2016, the total amounts borrowed for nuclear fuel by RGRT, excluding debt issuance costs, were $132.6 million of which $37.6 million had been borrowed under the RCF and $95.0 million was borrowed through the issuance of senior notes. Interest costs on borrowings to finance nuclear fuel are accumulated by RGRT and charged to us as fuel is consumed and recovered through fuel recovery charges. In September 2017, the $33.3 million 2012 Series A 1.875% Pollution Control Bonds which were subject to mandatory tender for purchase were redeemed and retired utilizing funds borrowed under the RCF. The outstanding balance for working

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capital and general corporate purposes was $85.0 million at December 31, 2017 and $44.0 million at December 31, 2016. Total aggregate borrowings under the RCF as of December 31, 2017 were $173.5 million with an additional $176.4 million available to borrow.

We received approval from the NMPRC on October 7, 2015, to guarantee the issuance of up to $65.0 million of long-term debt by the RGRT to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations, which remains effective. We received additional approval from the NMPRC on October 4, 2017 to amend and extend the RCF, issue up to $350.0 million in long-term debt and to redeem and refinance the $63.5 million 2009 Series A 7.25% Pollution Control Bonds and the $37.1 million 2009 Series B 7.25% Pollution Control Bonds, which have optional redemptions in 2019. The NMPRC approval to issue up to $350.0 million in long-term debt supersedes its prior approval. We requested similar approval from the FERC on September 1, 2017 and received approval on October 31, 2017. The approval requested from the FERC also includes requests to guarantee the issuance of up to $65.0 million of long-term debt by the RGRT and to continue to utilize our existing RCF with the ability to amend and extend the RCF at a future date. The authorization approved by the FERC is effective from November 15, 2017 through November 14, 2019 and supersedes prior FERC approvals.

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Contractual Obligations. Our contractual obligations as of December 31, 2017 are as follows (in thousands):



	Payments due by period
	Total		2018		2019 and 2020		2021 and 2022		2023 and Beyond
Long-term debt (including interest):
Senior notes (1)	$	2,080,375	$	55,200	$	110,400	$	260,400	$	1,654,375
Pollution control bonds (2)	390,578		9,959		19,918		19,918		340,783
RGRT senior notes (3)	51,804		2,268		49,536		—		—
Financing obligations (including interest):
Revolving credit facility (4)	178,061		178,061		—		—		—
Purchase obligations:
Power contracts	17,282		17,282		—		—		—
Fuel contracts:
Gas (5)	373,814		43,519		68,875		71,474		189,946
Nuclear fuel (6)	77,554		19,228		22,485		16,581		19,260
Retirement plans and other post-retirement benefits (7)	9,904		9,904		—		—		—
Nuclear Decommissioning Trust Funds (8)	59,701		2,132		4,264		4,264		49,041
Operating leases (9)	10,491		951		1,713		1,270		6,557
Total	$	3,249,564	$	338,504	$	277,191	$	373,907	$	2,259,962

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(1)

We have four outstanding issuances of senior notes. In May 2005, we issued $400.0 million aggregate principal amount of 6% Senior Notes due May 15, 2035. In June 2008, we issued $150.0 million aggregate principal amount of 7.5% Senior Notes due March 15, 2038. In December 2012, we issued $150.0 million aggregate principal amount of 3.3% Senior Notes due December 15, 2022. In December 2014, we issued $150.0 million aggregate principal amount of 5.0% Senior Notes due December 1, 2044. In March 2016, we issued an additional $150.0 million aggregate principal amount of 5.0% Senior Notes due December 1, 2044, for a total principal amount outstanding of 5.0% Senior Notes due December 1, 2044 of $300.0 million.


(2)	We have three series of pollution control bonds outstanding that are scheduled for remarketing and/or mandatory tender two in 2040, and one in 2042. In September 2017, the $33.3 million 2012 Series A 1.875% pollution control bonds, which were subject to mandatory tender for purchase, were redeemed and retired utilizing funds borrowed under the RCF.

(3)

In 2010, the Company and RGRT entered into a note purchase agreement for $110.0 million aggregate principal amount of senior notes consisting of: (a) $15.0 million aggregate principal amount of 3.67% RGRT Senior Notes, Series A, which matured and were repaid on August 15, 2015; (b) $50.0 million aggregate principal amount of 4.47% RGRT Senior Notes, Series B, which matured and were repaid on August 15, 2017; and (c) $45.0 million aggregate principal amount of 5.04% RGRT Senior Notes, Series C, due August 15, 2020.


(4)	This reflects obligations outstanding under the $350.0 million RCF. At December 31, 2017, $85.0 million was borrowed for working capital and general corporate purposes and $88.5 million was borrowed by RGRT for nuclear fuel. This balance includes interest based on actual interest rates at the end of 2017 and assumes this amount will be outstanding for the entire year of 2018.


(5)	Amount is based on the minimum volumes per the contract and market and/or contract price at the end of 2017. Gas obligation includes a gas storage contract and a gas transportation contract.


(6)	Some of the nuclear fuel contracts are based on a fixed price, adjusted for a market index. The index used here is the index at the end of 2017.

(7)

This obligation is based on our expected contributions and includes our minimum contractual funding requirements for the non-qualified retirement income plan and the other post-retirement benefits for 2018. We have no minimum cash contractual funding requirement related to our retirement income plan or other post-retirement benefits for 2018. However, we are subject to minimum funding requirements of ERISA. We also may decide to fund at higher levels and expect to contribute $9.9 million to our retirement plans in 2018. Minimum funding requirements for 2019 and beyond are not included due to the uncertainty of the applicable interest rates and the related return on assets.


(8)	This obligation is based on the decommissioning funding allowed in PUCT Docket No. 46831, effective August 1, 2017. We have no minimum funding obligation in the New Mexico jurisdiction effective July 1, 2016 with NMPRC Case No.

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15-00127-UT. It is possible that our funding requirements could change based on the amounts allowed in future rate filings.


(9)	We lease land in El Paso, Texas, adjacent to Newman under a lease that expires in June 2033, subject to a renewal option of 25 years. We also have several other leases for office, parking facilities and equipment that expire within the next five years.

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 7A.	Quantitative and Qualitative Disclosures About Market Risk

The following discussion regarding our market-risk sensitive instruments contains forward-looking information involving risks and uncertainties. The statements regarding potential gains and losses are only estimates of what could occur in the future. Actual future results may differ materially from those estimates presented due to the characteristics of the risks and uncertainties involved.

We are exposed to market risk due to changes in interest rates, equity prices and commodity prices. Substantially all financial instruments and positions we hold are for purposes other than trading and are described below.

Interest Rate Risk

Our long-term debt obligations are all fixed-rate obligations, except for the RCF, which is based on floating rates.

To the extent the RCF is utilized for nuclear fuel purchases, interest rate risk, if any, related to the RCF is substantially mitigated through the operation of the PUCT and the NMPRC rules, which establish energy cost recovery clauses. Under these rules, actual energy costs, including interest expense on nuclear fuel financing, are recovered from our customers.

Equity Price Risk

Our decommissioning trust funds include marketable equity securities of approximately $149.8 million and $129.8 million at December 31, 2017 and 2016, respectively. A hypothetical 20% decrease in equity prices would have reduced the fair values of these funds by $30.0 million and $26.0 million based on their fair values at December 31, 2017 and 2016, respectively. Declines in market prices could require that additional amounts be contributed to our nuclear decommissioning trusts to maintain minimum funding requirements. We do not expect to expend monies held in trust before 2044 or a later period when decommissioning of Palo Verde begins.

Commodity Price Risk

We utilize contracts of various durations for the purchase of natural gas and uranium concentrates to effectively manage our available fuel portfolio. These agreements contain variable pricing provisions and are settled by physical delivery. The fuel contracts with variable pricing provisions, as well as substantially all of our purchased power requirements, are exposed to fluctuations in prices due to unpredictable factors, including weather and various other worldwide events, which impact supply and demand. However, our exposure to fuel and purchased power price risk is substantially mitigated through the operation of the PUCT and NMPRC rules and our fuel clauses, as discussed previously.

In the normal course of business, we enter into contracts of various durations for the forward sales and purchases of electricity to effectively manage our available generating capacity and supply needs. Such contracts include forward contracts for the sale of generating capacity and energy during periods when our available power resources are expected to exceed the requirements of our retail native load and sales for resale. We also enter into forward contracts for the purchase of wholesale capacity and energy during periods when the market price of electricity is below our expected incremental power production costs or to supplement our generating capacity when demand is anticipated to exceed such capacity. As of January 31, 2018, we had entered into forward sales and purchase contracts for energy as discussed in Part I, Item 1, "Business – Energy Sources – Purchased Power." These agreements are generally fixed-priced contracts that qualify for the "normal purchases and normal sales" exception provided in the FASB guidance for accounting for derivative instruments and hedging activities and are not recorded at their fair value in our financial statements. Because of the operation of the PUCT and the NMPRC rules and our fuel clauses, these contracts do not expose us to significant commodity price risk.

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Management Report on Internal Control Over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and affected by the Company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:


•	pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company;


•	provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and the receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and


•	provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2017. In making this assessment, the Company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission's 2013 Internal Control - Integrated Framework. Based on its assessment, management believes that, as of December 31, 2017, the Company’s internal control over financial reporting is effective based on those criteria.

The Company’s independent registered public accounting firm, KPMG LLP, has issued an audit report on the Company’s internal control over financial reporting. This report appears on page 52 of this report.

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Item 8. Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS



	Page

Report of Independent Registered Public Accounting Firm	52

Balance Sheets as of December 31, 2017 and 2016	53

Statements of Operations for the years ended December 31, 2017, 2016 and 2015	55

Statements of Comprehensive Operations for the years ended December 31, 2017, 2016 and 2015	56

Statements of Changes in Common Stock Equity for the years ended December 31, 2017, 2016 and 2015	57

Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015	58

Notes to Financial Statements	59

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Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors

El Paso Electric Company:

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying balance sheets of El Paso Electric Company (the "Company") as of December 31, 2017 and 2016 , and the related statements of operations, comprehensive operations, changes in common stock equity, and cash flows for each of the years in the three-year period ended December 31, 2017 , and the related notes (collectively, the "financial statements"). We also have audited the Company’s internal control over financial reporting as of December 31, 2017 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016 , and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Basis for Opinions

The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also include evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ KPMG LLP

We have served as the Company’s auditor since 1983.

Houston, Texas

February 28, 2018

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EL PASO ELECTRIC COMPANY

BALANCE SHEETS



ASSETS (In thousands)	December 31,
	2017			2016
Utility plant:
Electric plant in service	$	3,982,095		$	3,791,566
Less accumulated depreciation and amortization	(1,320,175		)	(1,244,332		)
Net plant in service	2,661,920			2,547,234
Construction work in progress	146,059			154,738
Nuclear fuel; includes fuel in process of $59,689 and $57,315, respectively	194,933			194,842
Less accumulated amortization	(74,475		)	(75,602		)
Net nuclear fuel	120,458			119,240
Net utility plant	2,928,437			2,821,212
Current assets:
Cash and cash equivalents	6,990			8,420
Accounts receivable, principally trade, net of allowance for doubtful accounts of $2,300 and $2,156, respectively	88,585			88,452
Inventories, at cost	50,910			47,216
Under-collection of fuel revenues	—			11,123
Prepayments and other	10,307			8,988
Total current assets	156,792			164,199
Deferred charges and other assets:
Decommissioning trust funds	286,866			255,708
Regulatory assets	96,036			118,861
Other	16,232			16,298
Total deferred charges and other assets	399,134			390,867
Total assets	$	3,484,363		$	3,376,278

See accompanying notes to financial statements.

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EL PASO ELECTRIC COMPANY

BALANCE SHEETS (Continued)



CAPITALIZATION AND LIABILITIES (In thousands except for share data)	December 31,
	2017			2016
Capitalization:
Common stock, stated value $1 per share, 100,000,000 shares authorized, 65,694,829 and 65,685,615 shares issued, and 133,859 and 137,017 restricted shares, respectively	$	65,829		$	65,823
Capital in excess of stated value	326,117			322,643
Retained earnings	1,159,667			1,114,561
Accumulated other comprehensive income (loss), net of tax	11,058			(7,116		)
	1,562,671			1,495,911
Treasury stock, 25,244,350 and 25,304,914 shares, respectively, at cost	(420,506		)	(421,515		)
Common stock equity	1,142,165			1,074,396
Long-term debt, net of current portion	1,195,988			1,195,513
Total capitalization	2,338,153			2,269,909
Current liabilities:
Current maturities of long-term debt	—			83,143
Short-term borrowings under the revolving credit facility	173,533			81,574
Accounts payable, principally trade	59,270			62,953
Taxes accrued	35,660			32,488
Interest accrued	12,470			13,287
Over-collection of fuel revenues	6,225			255
Other	29,067			29,709
Total current liabilities	316,225			303,409
Deferred credits and other liabilities:
Accumulated deferred income taxes	305,023			555,066
Accrued pension liability	83,838			92,768
Accrued post-retirement benefit liability	26,417			34,400
Asset retirement obligation	93,029			81,800
Regulatory liabilities	296,685			18,435
Other	24,993			20,491
Total deferred credits and other liabilities	829,985			802,960
Commitments and contingencies
Total capitalization and liabilities	$	3,484,363		$	3,376,278

See accompanying notes to financial statements.

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EL PASO ELECTRIC COMPANY

STATEMENTS OF OPERATIONS

(In thousands except for share data)



	Years Ended December 31,
	2017			2016			2015
Operating revenues	$	916,797		$	886,936		$	849,869
Energy expenses:
Fuel	185,069			173,738			188,400
Purchased and interchanged power	59,682			59,727			53,545
	244,751			233,465			241,945
Operating revenues net of energy expenses	672,046			653,471			607,924
Other operating expenses:
Other operations	242,628			242,014			242,950
Maintenance	69,458			66,746			65,223
Depreciation and amortization	90,843			84,317			89,824
Taxes other than income taxes	70,863			65,533			63,736
	473,792			458,610			461,733
Operating income	198,254			194,861			146,191
Other income (deductions):
Allowance for equity funds used during construction	3,025			7,023			10,639
Investment and interest income, net	17,757			14,083			17,508
Miscellaneous non-operating income	715			1,292			2,062
Miscellaneous non-operating deductions	(3,125		)	(3,699		)	(4,328		)
	18,372			18,699			25,881
Interest charges (credits):
Interest on long-term debt and revolving credit facility	72,970			71,544			65,851
Other interest	2,388			1,303			1,313
Capitalized interest	(5,022		)	(4,990		)	(4,968		)
Allowance for borrowed funds used during construction	(2,975		)	(4,983		)	(6,937		)
	67,361			62,874			55,259
Income before income taxes	149,265			150,686			116,813
Income tax expense	51,004			53,918			34,895
Net income	$	98,261		$	96,768		$	81,918

Basic earnings per share	$	2.42		$	2.39		$	2.03

Diluted earnings per share	$	2.42		$	2.39		$	2.03

Dividends declared per share of common stock	$	1.315		$	1.225		$	1.165
Weighted average number of shares outstanding	40,414,556			40,350,688			40,274,986
Weighted average number of shares and dilutive potential shares outstanding	40,535,191			40,408,033			40,308,562

See accompanying notes to financial statements.

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EL PASO ELECTRIC COMPANY

STATEMENTS OF COMPREHENSIVE OPERATIONS

(In thousands)



	Years Ended December 31,
	2017			2016			2015
Net income	$	98,261		$	96,768		$	81,918
Other comprehensive income (loss):
Unrecognized pension and post-retirement benefit costs:
Net gain (loss) arising during period	12,634			(20,053		)	5,429
Prior service benefit	—			32,697			824
Reclassification adjustments included in net income for amortization of:
Prior service benefit	(9,657		)	(7,407		)	(6,574		)
Net loss	6,776			4,965			8,622
Net unrealized gains/losses on marketable securities:
Net holding gains (losses) arising during period	25,275			8,444			(2,906		)
Reclassification adjustments for net gains included in net income	(10,626		)	(7,640		)	(11,114		)
Net losses on cash flow hedges:
Reclassification adjustment for interest expense included in net income	532			498			467
Total other comprehensive income (loss) before income taxes	24,934			11,504			(5,252		)
Income tax benefit (expense) related to items of other comprehensive income (loss):
Unrecognized pension and post-retirement benefit costs	(3,615		)	(4,261		)	(3,286		)
Net unrealized (gains) losses on marketable securities	(2,922		)	(106		)	2,828
Losses on cash flow hedges	(223		)	(339		)	(203		)
Total income tax expense	(6,760		)	(4,706		)	(661		)
Other comprehensive income (loss), net of tax	18,174			6,798			(5,913		)
Comprehensive income	$	116,435		$	103,566		$	76,005

See accompanying notes to financial statements.

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EL PASO ELECTRIC COMPANY

STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

(In thousands except for share data)



	Common Stock					Capital in Excess of Stated Value			Retained Earnings			Accumulated Other Comprehensive Income (Loss), Net of Tax			Treasury Stock					Common Stock Equity

	Shares		Amount												Shares		Amount
Balances at December 31, 2014	65,849,543		$	65,850		$	318,515		$	1,032,537		$	(8,001	)	25,492,919		$	(424,647	)	$	984,254
Restricted common stock grants and deferred compensation	6,356		6			2,266									(93,455	)	1,557			3,829
Stock awards withheld for taxes	(15,031	)	(15		)	(556		)												(571		)
Forfeited restricted common stock	(12,215	)	(12		)										871		(14		)	(26		)
Deferred taxes on stock incentive plan						(475		)												(475		)
Compensation paid in shares						323									(15,501	)	258			581
Net income									81,918											81,918
Other comprehensive income (loss)												(5,913		)						(5,913		)
Dividends declared									(47,059		)									(47,059		)
Balances at December 31, 2015	65,828,653		65,829			320,073			1,067,396			(13,914		)	25,384,834		(422,846		)	1,016,538
Restricted common stock grants and deferred compensation						3,017									(74,181	)	1,235			4,252
Stock awards withheld for taxes	(5,723	)	(6		)	(261		)												(267		)
Forfeited restricted common stock	(298	)													197		(3		)	(3		)
Deferred taxes on stock incentive plan						(364		)												(364		)
Compensation paid in shares						178									(5,936	)	99			277
Net income									96,768											96,768
Other comprehensive income (loss)												6,798								6,798
Dividends declared									(49,603		)									(49,603		)
Balances at December 31, 2016	65,822,632		65,823			322,643			1,114,561			(7,116		)	25,304,914		(421,515		)	1,074,396
Restricted common stock grants and deferred compensation						2,989									(70,273	)	1,171			4,160
Performance share awards vested	11,314		11			921														932
Stock awards withheld for taxes	(5,258	)	(5		)	(568		)							8,360		(139		)	(712		)
Forfeited restricted common stock															4,961		(83		)	(83		)
Compensation paid in shares						132									(3,612	)	60			192
Cumulative effect adjustment for stock compensation									182											182
Net income									98,261											98,261
Other comprehensive income (loss)												18,174								18,174
Dividends declared									(53,337		)									(53,337		)
Balances at December 31, 2017	65,828,688		$	65,829		$	326,117		$	1,159,667		$	11,058		25,244,350		$	(420,506	)	$	1,142,165

See accompanying notes to financial statements.

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EL PASO ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(In thousands)



	Years Ended December 31,
	2017			2016			2015
Cash Flows From Operating Activities:
Net income	$	98,261		$	96,768		$	81,918
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service	90,843			84,317			89,824
Amortization of nuclear fuel	42,476			43,748			43,099
Deferred income taxes, net	49,394			50,510			30,846
Allowance for equity funds used during construction	(3,025		)	(7,023		)	(10,639		)
Other amortization and accretion	18,954			17,295			17,707
Gain on sale of property, plant and equipment	—			(545		)	(658		)
Net gains on sale of decommissioning trust funds	(10,626		)	(7,640		)	(11,114		)
Other operating activities	(692		)	1,279			517
Change in:
Accounts receivable	(138		)	(17,511		)	4,839
Inventories	(3,073		)	265			(2,859		)
Net over-collection (under-collection) of fuel revenues	17,093			(14,891		)	13,344
Prepayments and other	(692		)	(1,184		)	(3,984		)
Accounts payable	1,407			(2,140		)	(11,235		)
Taxes accrued	1,840			1,945			4,512
Other current liabilities	(917		)	2,022			3,719
Deferred charges and credits	(12,544		)	(16,065		)	(3,165		)
Net cash provided by operating activities	288,561			231,150			246,671
Cash Flows From Investing Activities:
Cash additions to utility property, plant and equipment	(190,305		)	(225,361		)	(281,458		)
Cash additions to nuclear fuel	(38,481		)	(42,383		)	(41,966		)
Capitalized interest and AFUDC:
Utility property, plant and equipment	(6,000		)	(12,006		)	(17,576		)
Nuclear fuel and other	(5,022		)	(4,990		)	(4,968		)
Allowance for equity funds used during construction	3,025			7,023			10,639
Decommissioning trust funds:
Purchases, including funding of $3.8 million, $4.5 million and $4.5 million, respectively	(102,920		)	(99,497		)	(110,223		)
Sales and maturities	97,037			91,268			102,567
Proceeds from sale of property, plant and equipment	281			4,841			721
Other investing activities	(1,559		)	5,373			(470		)
Net cash used for investing activities	(243,944		)	(275,732		)	(342,734		)
Cash Flows From Financing Activities:
Dividends paid	(53,337		)	(49,603		)	(47,059		)
Borrowings under the revolving credit facility:
Proceeds	638,458			355,607			344,398
Payments	(546,499		)	(415,771		)	(217,192		)
Payment on maturing RGRT senior notes	(50,000		)	—			(15,000		)
Payment on maturing pollution control bonds	(33,300		)	—			—
Proceeds from issuance of senior notes	—			157,052			—
Other financing activities	(1,369		)	(2,432		)	(1,439		)
Net cash provided by (used for) financing activities	(46,047		)	44,853			63,708
Net increase (decrease) in cash and cash equivalents	(1,430		)	271			(32,355		)
Cash and cash equivalents at beginning of period	8,420			8,149			40,504
Cash and cash equivalents at end of period	$	6,990		$	8,420		$	8,149

See accompanying notes to financial statements.

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INDEX TO NOTES TO FINANCIAL STATEMENTS



	Page
Note A. Summary of Significant Accounting Policies	60

Note B. New Accounting Standards	64

Note C. Regulation	66

Note D. Regulatory Assets and Liabilities	70

Note E. Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant	72

Note F. Accounting for Asset Retirement Obligations	75

Note G. Common Stock	76

Note H. Accumulated Other Comprehensive Income (Loss)	81

Note I. Long-Term Debt and Financing Obligations	83

Note J. Income Taxes	85

Note K. Commitments, Contingencies and Uncertainties	88

Note L. Litigation	90

Note M. Employee Benefits	91

Note N. Franchises and Significant Customers	104

Note O. Financial Instruments and Investments	105

Note P. Supplemental Statements of Cash Flow Disclosures	110

Note Q. Selected Quarterly Financial Data (Unaudited)	111

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

A. Summary of Significant Accounting Policies

General. El Paso Electric Company is a public utility engaged in the generation, transmission and distribution of electricity in an area of approximately 10,000 square miles in west Texas and southern New Mexico. The Company also serves a full requirements wholesale customer in Texas.

Basis of Presentation . The Company maintains its accounts in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (the "FERC").

Use of Estimates . The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company evaluates its estimates on an on-going basis, including those related to depreciation, unbilled revenue, income taxes, fuel costs, pension and other post-retirement obligations and asset retirement obligations ("ARO"). Actual results could differ from those estimates.

Application of the Financial Accounting Standards Board (the "FASB" ) Guidance for Regulated Operations. Regulated electric utilities typically prepare their financial statements in accordance with the FASB guidance for regulated operations. The FASB guidance for regulated operations requires the Company to include an allowance for equity and borrowed funds used during construction ("AEFUDC" and "ABFUDC") as a cost of construction of electric plant in service. AEFUDC is recognized as income and ABFUDC is shown as capitalized interest charges in the Company’s statements of operations. The FASB guidance for regulated operations also requires the Company to show certain recoverable costs as either assets or liabilities on a utility’s balance sheet if the regulator provides assurance that these costs will be charged to and collected from the utility’s customers (or has already permitted such cost recovery) or will be credited or refunded to the utility’s customers. The resulting regulatory assets or liabilities are amortized in subsequent periods based upon the respective amortization periods reflected in a utility’s regulated rates. See Part II, Item 8, Financial Statements and Supplementary Data, Note D. The Company applies the FASB guidance for regulated operations for all three of the jurisdictions in which it operates.

Comprehensive Income. Certain gains and losses that are not recognized currently in the statements of operations are reported as other comprehensive income in accordance with the FASB guidance for reporting comprehensive income.

Utility Plant. Utility plant is generally reported at cost. The cost of renewals and betterments are capitalized and the costs of repairs and minor replacements are charged to the appropriate operating expense accounts. Depreciation is provided on a straight-line basis over the estimated remaining lives of the assets (ranging in average from 5 to 48 years). The average composite depreciation rate utilized in 2017 , 2016 and 2015 was 2.27% , 2.28% , and 2.64% , respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its cost together with the cost of removal, less salvage is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized. During 2016, depreciation and amortization decreased due to changes in depreciation rates approved by the Public Utility Commission of Texas ("PUCT") in the final order in Docket No. 44941 ("2016 PUCT Final Order") and the New Mexico Public Regulation Commission ("NMPRC") in the final order in Case No. 15-00127-UT ("NMPRC Final Order") and changes in the estimated life of certain intangible software assets.

The cost of nuclear fuel is amortized to fuel expense on a units-of-production basis. The Company is also amortizing its share of costs associated with on-site spent fuel storage casks at Palo Verde Generating Station ("Palo Verde") over the burn period of the fuel that will necessitate the use of the storage casks. See Part II, Item 8, Financial Statements and Supplementary Data, Note E.

Impairment of Long-Lived Assets. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge is recognized for the amount by which the carrying amount of the asset exceeds the fair value of the asset.

Allowance for Funds Used During Construction ("AFUDC") and Capitalized Interest . The Company capitalizes interest (ABFUDC) and common equity (AEFUDC) costs to construction work in progress and capitalizes interest to nuclear fuel in process in accordance with the FERC Uniform System of Accounts as provided for in the FASB guidance. AFUDC is a non-cash component of income and is calculated monthly and charged to all new eligible construction and capital improvement projects.

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AFUDC is compounded on a semi-annual basis. The average AFUDC rates used in 2017 , 2016 and 2015 were 5.38% , 6.43% and 7.18% , respectively.

Asset Retirement Obligation. The FASB guidance sets forth accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. An ARO associated with long-lived assets included within the scope of the FASB guidance is that for which a legal obligation exists under enacted laws, statutes, written or oral contracts, including obligations arising under the doctrine of promissory estoppel and legal obligations to perform an asset retirement activity even if the timing and/or settlement are conditioned on a future event that may or may not be within the control of an entity. See Part II, Item 8, Financial Statements and Supplementary Data, Note F. Under the FASB guidance, these liabilities are recognized as incurred if a reasonable estimate of fair value can be established and are capitalized as part of the cost of the related tangible long-lived assets. The Company records the increase in the ARO due to the passage of time as an operating expense (accretion expense).

Cash and Cash Equivalents . Temporary cash investments with an original maturity of three months or less are considered cash equivalents. The Company's cash and cash equivalents do not include amounts held in trust by the nuclear decommissioning or the pension and other post-retirement benefit trust funds.

Investments . The Company’s marketable securities, included in decommissioning trust funds in the balance sheet, are reported at fair value and consist of cash, equity securities and municipal, federal and corporate bonds in trust funds established for decommissioning of its interest in Palo Verde. Such marketable securities are classified as "available-for-sale" securities and, as such, unrealized gains and losses are included in accumulated other comprehensive loss as a separate component of common stock equity. However, if declines in the fair value of marketable securities below original cost basis are determined to be other than temporary, the declines are reported as losses in the statements of operations and a new cost basis is established for the affected securities at fair value. Gains and losses are determined using the cost of the security based on the specific identification basis. See Part II, Item 8, Financial Statements and Supplementary Data, Note O.

Derivative Accounting. Accounting for derivative instruments and hedging activities requires the recognition of derivatives as either assets or liabilities in the balance sheet with measurement of those instruments at fair value. Any changes in the fair value of these instruments are recorded in earnings or other comprehensive income. See Part II, Item 8, Financial Statements and Supplementary Data, Note O.

Inventories . Inventories, primarily parts, materials, supplies, fuel oil and natural gas are stated at average cost, which is not to exceed recoverable cost.

Operating Revenues Net of Energy Expenses . The Company accrues revenues for services rendered, including unbilled electric service revenues. Energy expenses are stated at actual cost incurred. The Company’s Texas retail customers are billed under base rates and a fixed fuel factor approved by the PUCT. The Company’s New Mexico retail customers are billed under base rates and a fuel adjustment clause which is adjusted monthly, as approved by the NMPRC. The Company's FERC sales for resale customers are billed under formula base rates and fuel factors and a fuel adjustment clause which is adjusted monthly. The Company’s recovery of energy expenses is subject to periodic reconciliations of actual energy expenses incurred to actual fuel revenues collected. The difference between energy expenses incurred and fuel revenues charged to customers is reflected as over/under-collection of fuel revenues in the balance sheets. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.

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 customers 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 $22.2 million and $21.0 million as of December 31, 2017 and 2016 , respectively. The Company presents revenues net of sales taxes in its statements of operations.

Allowance for Doubtful Accounts. The allowance for doubtful accounts represents the Company’s estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections environment. Additions, deductions and balances for allowance for doubtful accounts for 2017 , 2016 and 2015 are as follows (in thousands):

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	2017		2016		2015
Balance at beginning of year	$	2,156	$	2,046	$	2,253
Additions:
Charged to costs and expense	3,141		2,427		2,057
Recovery of previous write-offs	1,122		1,395		1,613
Uncollectible receivables written off	4,119		3,712		3,877
Balance at end of year	$	2,300	$	2,156	$	2,046

Income Taxes . The Company accounts for federal and state income taxes under the asset and liability method of accounting for income taxes. Deferred income taxes are recognized for the estimated future tax consequences of "temporary differences" by applying enacted statutory tax rates for each taxable jurisdiction applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. Certain temporary differences are accorded flow-through treatment by the Company's regulators and impact the Company's effective tax rate. The FASB guidance requires that rate-regulated companies record deferred income taxes for temporary differences accorded flow-through treatment at the direction of the regulatory commission. The resulting deferred tax assets and liabilities are recorded at the expected cash flow to be reflected in future rates. Because the Company's regulators have consistently permitted the recovery of tax effects previously flowed-through earnings, the Company has recorded regulatory liabilities and assets offsetting such deferred tax assets and liabilities. During the third quarter of 2016, the Company changed its accounting for state income taxes from the flow-through method to the normalization method in accordance with the final orders from the PUCT and the NMPRC in its 2015 rate cases, effective January 1, 2016. See Part II, Item 8, Financial Statements and Supplementary Data, Note C for further discussion. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date, unless those deferred taxes will be returned to customers in which case they are recorded as a regulatory asset or liability. See further discussion in Part II, Item 8, Financial Statements and Supplementary Data, Note J. The Company recognizes tax assets and liabilities for uncertain tax positions in accordance with the recognition and measurement criteria of the FASB guidance for uncertainty in income taxes. See Part II, Item 8, Financial Statements and Supplementary Data, Note J.

On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (“TCJA”) was enacted. Substantially all of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017, with the exception of the discontinuance of bonus depreciation for regulated public utilities which was effective for assets acquired and placed into service after September 27, 2017. The TCJA includes significant changes to the Internal Revenue Code of 1986 (as amended, the "IRC"), including amendments which significantly changed the taxation of business entities and includes specific provisions related to regulated public utilities. The more significant changes that impact the Company included in the TCJA are reductions in the corporate federal income tax rate from 35% to 21% , elimination of the corporate alternative minimum tax provisions, additional limitations on deductions of executive compensation, and limiting the utilization of net operating losses ("NOL") arising after December 31, 2017 to 80% of taxable income with no carryback but with an indefinite carryforward. The specific provisions related to regulated public utilities in the TCJA generally provide for the continued deductibility of interest expense, the elimination of bonus depreciation for property acquired and placed into service after September 27, 2017 and the continuance of rate normalization requirements for accelerated depreciation benefits and changes to deferred tax balances as a result of the change in corporate federal income tax rate.

The tax effects of changes in tax laws must be recognized in the period in which the law is enacted. GAAP also requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. Thus, at the date of enactment of the TCJA, the Company’s deferred taxes were re-measured based upon the new corporate federal income tax rate. The decrease in deferred taxes was recorded as a regulatory liability as it will be subject to refund to customers and is recorded at the expected cash flow to be reflected in future rates. See Part II, Item 8, Financial Statements and Supplementary Data, Note J for further discussion.

Earnings per Share . The Company’s restricted stock awards are participating securities and earnings per share must be calculated using the two-class method in both the basic and diluted earnings per share calculations. For the basic earnings per share calculation, net income is allocated to the weighted average number of restricted stock awards and to the weighted average number of shares outstanding. The net income allocated to the weighted average number of shares outstanding is then divided by the weighted average number of shares outstanding to derive the basic earnings per share. For the diluted earnings per share, net income is allocated to the weighted average number of restricted stock awards and to the weighted average number of shares and dilutive potential shares outstanding. The Company’s dilutive potential shares outstanding amount is calculated using the treasury stock method for the unvested performance shares. Net income allocated to the weighted average number of shares and dilutive

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potential shares is then divided by the weighted average number of shares and dilutive potential shares outstanding to derive the diluted earnings per share. See Part II, Item 8, Financial Statements and Supplementary Data, Note G.

Stock-Based Compensation . The Company has a stock-based long-term incentive plan. The Company is required under the FASB guidance to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. Such costs are recognized over the period during which an employee is required to provide service in exchange for the award (the "requisite service period") which typically is the vesting period. Compensation cost is not recognized for anticipated forfeitures prior to vesting of equity instruments. See Part II, Item 8, Financial Statements and Supplementary Data, Note G.

Pension and Post-retirement Benefit Accounting . See Part II, Item 8, Financial Statements and Supplementary Data, Note M for a discussion of the Company's accounting policies for its employee benefits.

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B. New Accounting Standards

In March 2016, the FASB issued Accounting Standards Update ("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. The Company adopted the new standard effective January 1, 2017. The adoption of the new standard did not have a material impact on the Company's financial condition, results of operations or cash flows. The cumulative effect of the adoption of the new standard was to increase net operating loss carryforward deferred tax assets and retained earnings by $0.2 million on January 1, 2017.

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, and has since modified the standard with several ASUs. The standard 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. More specifically, the standard requires entities to recognize revenue through the application of a five-step model, which includes the: (i) identification of the contract; (ii) identification of the performance obligations; (iii) determination of the transaction price; (iv) allocation of the transaction price to the performance obligations; and (v) the recognition of revenue as the entity satisfies the performance obligations. The Company will adopt the new standard for reporting periods beginning on January 1, 2018, and intends use the modified retrospective approach.

The Company has analyzed the impact of the new standard on its various revenue and cash flow streams, and the impact on changes to business processes, systems and controls to support recognition under the new guidance. Tariff sales to customers are determined to be in the scope of the new standard and represent a significant portion of the Company’s total operating revenues. The Company has determined that the timing or pattern of revenue recognition from tariff sales will not change. Implementation of the new standard will also not significantly change the timing or pattern of revenue recognition from other revenue streams. Upon adoption of the standard, the Company expects its disclosures to disaggregate revenues primarily by tariff based categories and off-system sales.

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 provisions of this ASU become effective for reporting periods beginning after December 15, 2017. Upon adoption of the new standard, the Company expects to record the cumulative effects as of January 1, 2018 which will result in a net reduction to accumulated other comprehensive income of $41.0 million , net of tax, and a corresponding increase in retained earnings for unrealized gains (losses) related to equity securities owned by the Company.

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 guidance. The lessee is permitted to make an accounting policy election to not recognize lease assets and lease liabilities for short-term leases. Implementation of the standard will be required for reporting periods beginning after December 15, 2018. Adoption of the new lease accounting standard will require the Company to apply the new standard to the earliest period using a modified retrospective approach. The Company is currently in the process of evaluating the impact of the new standard, which includes continuing to monitor activities of the FASB, including the impact of the recently issued ASU 2018-01, and the proposed project to allow entities to adopt the standard with a cumulative effect adjustment as of the beginning of the adoption year, while maintaining prior year comparative financial information and disclosures as reported. ASU 2018-01, Land Easement Practical expedient for Transition to Topic 842, provides an optional practical expedient to not evaluate existing or expired land easements under Topic 842, if those land easements were not previously accounted for as leases under Accounting Standards Codification ("ASC") Topic 840. The Company currently anticipate s that it will apply the practical

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expedient under ASU 2018-01 to its existing or expired land easements as part of its transition to Topic 842. The Company's evaluation process also includes evaluating the impact, if any, on changes to business processes, systems and controls to support recognition and disclosure under the new guidance; however, at this time the Company is unable to determine the impact this standard will have on the financial statements and related disclosures.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326). ASU 2016-13 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. The provisions of ASU 2016-13 will be required for reporting periods beginning after December 15, 2019. 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 ASU 2016-13.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) Classification of Certain Cash Receipts and Cash Payments to reduce diversity in practice in how certain cash receipts and cash payments are classified in the statement of cash flows. The provisions of ASU 2016-15 will be required for reporting periods beginning after December 15, 2017. ASU 2016-15 will be applied using a retrospective transition method to each period presented. If it is impracticable to apply ASU 2016-15 retrospectively for some of the issues, the amendments for those issues may be applied prospectively as of the earliest date practicable. The Company is currently assessing the future impact of this ASU.

In March 2017, the FASB issued ASU 2017-07, Compensation - Retirement Benefits (Topic 715) Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. ASU 2017-07 amends Accounting Standards Codification 715, Compensation - Retirement Benefits, to require companies to present the service cost component of net benefit cost in the income statement line items where compensation cost is reported. Companies will present all other components of net benefit cost separately from the line item(s) that includes the service cost and outside of any subtotal of operating income. In addition, only the service cost component will be eligible for capitalization in assets. The amendments in ASU 2017-07 will be required for reporting periods beginning after December 15, 2017. The amendments in ASU 2017-07 should be applied retrospectively for the income statement presentation of the service cost component and the other components of net benefit costs and prospectively, on and after the effective date, for the capitalization of the service cost component. The Company expects that the retrospective impact of implementing this ASU on the Statement of Operations for the twelve months ended December 31, 2017 would be an increase in (i) Other operations of $8.2 million , (ii) Other interest of $15.8 million , (iii) Miscellaneous non-operating income of $32.4 million , and (iv) Miscellaneous non-operating deductions of $8.4 million .

In May 2017, the FASB issued ASU 2017-09, Compensation - Stock Compensation (Topic 718), Scope of Modification Accounting, to provide guidance about when to account for a change to the terms or conditions of a share-based payment award as a modification. Under ASU 2017-09, modification accounting is required only if the fair value, the vesting conditions, or the classification of the award (as equity or liability) changes as a result of the change in terms or conditions. The amendments of ASU 2017-09 will be required for reporting periods beginning after December 15, 2017. ASU 2017-09 should be applied prospectively to an award modified on or after the adoption date. The Company is assessing the future impact of ASU 2017-09; however, it currently do es not expect the impact of this ASU to be significant to the Company's financial conditions, results of operations or cash flows.

In February 2018, the FASB issued ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220) as a result of concerns raised by stakeholders due to the TCJA. More specifically, the concerns raised are that because the adjustment due to the reduction of the historical corporate income tax rate of 35% to the newly enacted corporate income tax rate of 21% is required to be made for accumulated deferred income taxes, the tax effect of items within accumulated other comprehensive income (“AOCI”) do not reflect the appropriate tax rate under current accounting standards which would result in "stranded taxes". ASU 2018-02 allows companies to reclassify stranded taxes from AOCI to retained earnings. The amount of the reclassification would be the difference between the historical corporate income tax rate of 35% and the newly enacted 21% corporate income tax rate. The provisions of ASU 2018-02 are effective for fiscal years and interim periods within that reporting period beginning after December 15, 2018. Early adoption is permitted, including adoption in any interim periods for reporting periods for which financial statements have not been issued. The Company is currently in the process of evaluating the impact of ASU 2018-02 and its impact on regulated utilities. At December 31, 2017, the Company has $7.2 million in stranded taxes in AOCI.

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C. Regulation

General

Texas Regulatory Matters

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

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The 2017 PUCT Final Order requires the Company to file a refund tariff if the federal statutory income tax rate, as it relates to the Company, is decreased before the Company files its next rate case. Following the enactment of the TCJA on December 22, 2017, and in compliance with the 2017 PUCT Final Order, the Company will reduce the recognition of Texas jurisdictional revenues beginning January 1, 2018, to approximate the tax savings resulting from the TCJA and will file a refund tariff which the Company will ask to be implemented in the first half of 2018. The refund tariff is expected to be reflected in rates over a period of a year and will be updated annually until new base rates are implemented pursuant to the Company's next rate case filing. See Part II, Item 8, Financial Statements and Supplementary Data, Note J for further details.

Community Solar. On June 8, 2015, the Company filed a petition with the PUCT to initiate a community solar program that includes the construction and ownership of a 3 MW solar photovoltaic system located at the Company's Montana Power Station ("MPS") . Participation is on a voluntary basis, and customers 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 approving the program, and the PUCT approved the settlement agreement and program on September 1, 2016. On April 19,

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2017, the Company announced that the entire 3 MW program was fully subscribed by approximately 1,500 Texas customers. The Community Solar facility began commercial operation on May 31, 2017 .

Four Corners Generating Station . 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 sale of the Company's interest in Four Corners to APS. The sale of the Company's interest in Four Corners closed on July 6, 2016 . See Part II, Item 8, Financial Statements and Supplementary Data, Note E for further details on the sale of Four Corners.

Other Required Approvals . The Company has obtained other required approvals for tariffs and other approvals required by the Texas Public Utility Regulatory Act and the PUCT.

New Mexico Regulatory Matters

2015 New Mexico Rate Case Filing . On May 11, 2015, the Company filed a request with the NMPRC, in Case No. 15-00127-UT, for an annual increase in non-fuel base rates. On June 8, 2016, the NMPRC issued the NMPRC Final Order which approved an annual increase in non-fuel base rates of approximately $0.6 million , an increase of approximately $0.5 million in other service fees and a decrease in the Company's allowed return on equity to 9.48% . The NMPRC Final Order concluded that all of the Company's new plant in service was reasonable and necessary and therefore would be recoverable in rates. The Company's rates were approved by the NMPRC effective July 1, 2016 and implemented at such time.

5 MW Holloman Air Force Base ("HAFB") Facility Certificate of Convenience and Necessity ("CCN"). On October 7, 2015, in NMPRC Case No. 15-00185-UT, the NMPRC issued a final order approving a CCN for a 5 MW solar power generation facility located on HAFB in the Company's service territory in New Mexico. The Company and HAFB negotiated a retail contract, which includes a power sales agreement for the facility, to replace the existing load retention agreement which was approved by final order issued October 5, 2016 in NMPRC Case No. 16-00224-UT. Construction of the solar generation facility is expected to be completed in the third quarter of 2018.

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On July 1, 2016, the Company filed its 2015 Annual Report for Energy Efficiency Programs, which included an incentive for verified 2015 program performance of $0.3 million , which was approved in Case No. 13-00176-UT. The Company recorded the $0.3 million approved incentive in operating revenues in the first quarter of 2017. In addition, on June 30, 2017, the Company filed its 2016 Annual Report for Energy Efficiency Programs, which included an incentive for verified 2016 program performance of $0.4 million that was approved in Case No. 13-00176-UT. The Company recorded the $0.4 million approved incentive in operating revenues in the third quarter of 2017.

Other Required Approvals . The Company has obtained other required approvals for tariffs and other approvals as required by the New Mexico Public Utility Act and the NMPRC.

Federal Regulatory Matters

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

United States Department of Energy ("DOE"). The DOE regulates the Company's exports of power to Mexico pursuant to a DOE grant of export authorization. In addition, the Company is the holder of two presidential permits issued by the DOE under which the Company constructed and operates border facilities crossing the United States/Mexico border.

Part II, Item 8, Financial Statements and Supplementary Data, Note E for discussion of spent fuel storage and disposal costs.

Sales for Resale and Network Transmission Service to Rio Grande Electric Cooperative

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D. Regulatory Assets and Liabilities

The Company's operations are regulated by the PUCT, the NMPRC and the FERC. Regulatory assets represent probable future recovery of previously incurred costs, which will be collected from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Regulatory assets and liabilities reflected in the Company's balance sheet are presented below (in thousands):



	Amortization Period Ends	December 31, 2017		December 31, 2016
Regulatory assets
Regulatory tax assets	(a)	$	40,512	$	66,670
Loss on reacquired debt (b)	May 2035	14,926		15,780
Final coal reclamation	(c)(d)	4,726		8,181
Four Corners decommissioning	(e)	6,604		1,400
Nuclear fuel postload daily financing charge	(d)	3,536		3,831
Unrecovered issuance costs due to reissuance of PCBs (b)	August 2042	761		794
Texas 2015 rate case costs (f)	January 2021	1,144		2,670
Texas 2017 rate case costs	January 2021	3,642		246
Texas relate back surcharge (g)	January 2019	8,591		6,455
Texas demand response program	(h)	133		—
Texas military base discount and recovery factor	(i)	213		—
New Mexico renewable energy credits and related costs (j)	June 2022	5,823		6,937
New Mexico 2010 FPPCAC audit	June 2019	326		398
New Mexico Palo Verde deferred depreciation	(k)	4,263		4,415
New Mexico 2015 rate case costs	June 2019	644		1,074
New Mexico 2017 rate case costs		—		10
New Mexico demand response program	(l)	192		—
Total regulatory assets		$	96,036	$	118,861
Regulatory liabilities
Regulatory tax liabilities	(m)	$	289,013	$	10,648
Accumulated deferred investment tax credit	(n)	4,816		3,328
Texas energy efficiency	(o)	895		1,288
New Mexico energy efficiency	(o)	1,394		2,159
Texas military base discount and recovery factor	(i)	—		184
New Mexico gain on sale of assets (p)	June 2019	567		828
Total regulatory liabilities		$	296,685	$	18,435

______________________________

(a)

This item relates to (i) the regulatory treatment of the equity portion of AFUDC which is recovered in rate base by an offset with the related accumulated deferred income tax liability, and (ii) excess deferred state income taxes which are recovered through amortization to tax expense in cost of service. The amortization period for the excess deferred state income taxes is 15 years as established in the 2016 PUCT Final Order and the NMPRC Final Order.


(b)	This item is recovered as a component of the weighted cost of debt and amortized over the life of the related debt issuance.


(c)	This item relates to coal reclamation costs associated with Four Corners. The Texas portion was approved for recovery in the 2016 Texas Fuel Reconciliation and will be recovered over seven years through June 2023. The New Mexico amortization period is anticipated to be established in the next general rate case.


(d)	This item is recovered through fuel recovery mechanisms established by tariffs.


(e)	This item relates to the decommissioning of Four Corners. The Texas portion was approved for recovery in the 2017 PUCT Final Order and will be recovered over seven years through July 2024. The New Mexico amortization period is anticipated to be established in the next general rate case.


(f)	The 2017 PUCT Final Order approved a new recovery period for these costs, beginning January 10, 2018.

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(g)

This item relates to the recovery of revenues through two separate surcharges; one for the 2015 Texas Retail Rate Case relate back revenues beginning October 1, 2016 and ending September 30, 2017, and a second surcharge for the 2017 Texas Retail Rate Case relate back revenues beginning January 10, 2018 and ending January 9, 2019. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.


(h)	Recovery of this item will be addressed in the next EECRF filing.


(i)	This item represents the net asset/net liability related to the military discount which is recovered from non-military customers through a recovery factor that is set annually.


(j)	This item relates to renewable energy credits and procurement plan costs, of which a component has been approved for recovery in the NMPRC Final Order. The remaining balance will be requested for recovery in the next general rate case.


(k)	The amortization period for this item is based upon the Nuclear Regulatory Commission license life for each unit at Palo Verde.


(l)	Amortization period is anticipated to be established in next general rate case.


(m)	This item primarily relates to the reduction in the federal corporate income tax rate from 35% to 21% as enacted by the TCJA. The amortization period for the recovery on this item will be addressed in the next base rate filings in all jurisdictions. See Part II, Item 8, Financial Statements and Supplementary Data, Note J for further details.


(n)	The amortization period is based upon the life of the associated assets.


(o)	This item is recovered or credited through a recovery factor that is set annually.


(p)	This item relates to the gains on the sales of assets the Company shares with its New Mexico customers over a three year period.

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NOTES TO FINANCIAL STATEMENTS

E. Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant

The table below presents the balance of each major class of depreciable assets at December 31, 2017 (in thousands):



	Gross Plant		Accumulated Depreciation			Net Plant
Nuclear production	$	994,075	$	(338,699	)	$	655,376
Steam and other	952,672		(214,551		)	738,121
Total production	1,946,747		(553,250		)	1,393,497
Transmission	520,126		(264,480		)	255,646
Distribution	1,183,289		(374,438		)	808,851
General	226,325		(66,347		)	159,978
Intangible	105,608		(61,660		)	43,948
Total	$	3,982,095	$	(1,320,175	)	$	2,661,920

The Company owns a 15.8% interest in each of the three nuclear generating units and common facilities at Palo Verde, in Wintersburg, Arizona. The Palo Verde Participants include the Company and six other utilities: APS, Southern California Edison Company ("SCE"), PNM, Southern California Public Power Authority, Salt River Project Agricultural Improvement and Power District ("SRP") and the Los Angeles Department of Water and Power.

A summary of the Company’s investment in jointly-owned utility plant, excluding fuel inventories, at December 31, 2017 and 2016 is as follows (in thousands):



	December 31, 2017						December 31, 2016
	Palo Verde			Other (a)			Palo Verde			Other (a)
Electric plant in service	$	994,075		$	97,603		$	948,382		$	97,652
Accumulated depreciation	(338,699		)	(72,822		)	(320,000		)	(74,408		)
Construction work in progress	40,946			1,014			50,598			1,895
Total	$	696,322		$	25,795		$	678,980		$	25,139

_______________

(a) Includes three jointly-owned transmission lines.

Amortization of intangible plant (software) is provided on a straight-line basis over the estimated useful life of the asset (ranging from 3 to 15 years). The table below presents the actual and estimated amortization expense for intangible plant for the previous three years and for the next five years (in thousands):



2015	$	6,482
2016	5,302
2017	6,409
2018 (estimated)	6,835
2019 (estimated)	6,485
2020 (estimated)	6,048
2021 (estimated)	5,128
2022 (estimated)	4,328

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NOTES TO FINANCIAL STATEMENTS

Palo Verde

The operation of Palo Verde and the relationship among the Palo Verde Participants is governed by the Arizona Nuclear Power Project Participation Agreement (the "ANPP Participation Agreement"). APS serves as operating agent for Palo Verde, and under the ANPP Participation Agreement, the Company has limited ability to influence operations and costs at Palo Verde. Pursuant to the ANPP Participation Agreement, the Palo Verde Participants share costs and generating entitlements in the same proportion as their percentage interests in the generating units, and each participant is required to fund its share of fuel, other operations, maintenance and capital costs. The Company’s share of direct expenses in Palo Verde and other jointly-owned utility plants is reflected in fuel expense, other operations expense, maintenance expense, miscellaneous other deductions, and taxes other than income taxes in the Company’s statements of operations. The ANPP Participation Agreement provides that if a participant fails to meet its payment obligations, each non-defaulting participant shall pay its proportionate share of the payments owed by the defaulting participant. Because it is impracticable to predict defaulting participants, the Company cannot estimate the maximum potential amount of future payment, if any, which could be required under this provision.

Nuclear Regulatory Commission . The Nuclear Regulatory Commission ("NRC") regulates the operation of all commercial nuclear power reactors in the United States, including Palo Verde. The NRC periodically conducts inspections of nuclear facilities and monitors performance indicators to enable the agency to arrive at objective conclusions about a licensee’s safety performance.

Palo Verde Operating Licenses. Operation of each of the three Palo Verde Units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987 and issued renewed operating licenses for each of the three units in April 2011, which extended the licenses for Units 1, 2 and 3 to June 2045, April 2046 and November 2047, respectively.

Decommissioning . Pursuant to the ANPP Participation Agreement and federal law, the Company funds its share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities, through the term of their respective operating licenses and is required to maintain a minimum accumulation and funding level in its decommissioning account at the end of each annual reporting period during the life of the plant. The Company has established external trusts with an independent trustee, which enables the Company to record a current deduction for federal income tax purposes for most of the amounts funded. At December 31, 2017 , the Company’s decommissioning trust fund had a balance of $286.9 million , which is above its minimum funding level. The Company monitors the status of its decommissioning funds and adjusts deposits, if necessary.

Decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers retained by APS. In April 2017, the Palo Verde Participants approved the 2016 Palo Verde decommissioning study (“2016 Study”). The 2016 Study estimated that the Company must fund approximately $432.8 million (stated in 2016 dollars) to cover its share of decommissioning costs which was an increase in decommissioning costs of $52.1 million (stated in 2016 dollars) from the 2013 Palo Verde decommissioning study. The effect of this change increased the ARO by $3.5 million , which was recorded during the second quarter of 2017, and increased annual expenses starting in April 2017. Although the 2016 Study was based on the latest available information, there can be no assurance that decommissioning cost estimates will not increase in the future or that regulatory requirements will not change. In addition, until a new low-level radioactive waste repository opens and operates for a number of years, estimates of the cost to dispose of low-level radioactive waste are subject to uncertainty. As provided in the ANPP Participation Agreement, the participants are required to conduct a new decommissioning study every three years. While the Company attempts to seek amounts in rates to meet its decommissioning obligations, it is not able to conclude given the evidence available to it now that it is probable these costs will continue to be collected over the period until decommissioning begins in 2044. The Company is ultimately responsible for these costs and its future actions combined with future decisions from regulators will determine how successful the Company is in this effort.

Spent Fuel and Waste Disposal . Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "NWPA"), 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. Pursuant to the terms of the August 18, 2014 settlement agreement, APS files annual claims for the period July 1 of the then-previous year to June 30 of the then-current year. The settlement agreement, as amended, provides APS with a method for submitting claims and receiving recovery for costs incurred through December 31, 2016, which has been extended to December 31, 2019. The Company's share of costs recovered are presented

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NOTES TO FINANCIAL STATEMENTS

below (in thousands):



			Amount Credited
			to Customers
			through Fuel		Period Credited
Costs Recovery Period	Amount Refunded		Adjustment Clauses		to Customers

January 2007 - June 2011	$	9,076	$	7,944	September 2014
July 2011 - June 2014	6,643		5,759		March 2015
July 2014 - June 2015	1,884		1,581		March 2016
July 2015 - June 2016	1,779		1,432		March 2017

DOE’s Construction Authorization Application for Yucca Mountain. The DOE had planned to meet its disposal obligations by designing, licensing, constructing and operating a permanent geologic repository in Yucca Mountain, Nevada. In March 2010, the DOE filed a motion to dismiss with prejudice its Yucca Mountain construction authorization application that was pending before the NRC. Several interested parties have intervened in the NRC proceeding. The Company cannot predict when spent fuel shipments to the DOE will commence.

Palo Verde has sufficient capacity at its on-site independent spent fuel storage installation (“ISFSI”) to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027. Additionally, Palo Verde has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047. If uncertainties regarding the United States government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation.

Liability and Insurance Matters . The Palo Verde Participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law, which is currently at $13.4 billion . This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $450.0 million , and the balance is covered by an industry-wide retrospective assessment program. If a loss at a nuclear power plant covered by the programs exceeds the accumulated funds in the primary level of protection, the Company could be assessed retrospective premium adjustments on a per incident basis. Under federal law, the maximum assessment per reactor under the program for each nuclear incident is approximately $127.3 million , subject to an annual limit of $19.0 million . Based upon the Company's 15.8% interest in the three Palo Verde units, the Company's maximum potential assessment per incident for all three units is approximately $60.4 million , with an annual payment limitation of approximately $9.0 million .

The Palo Verde Participants maintain $2.75 billion of "all risk" nuclear property insurance. The insurance provides coverage for property damage and decontamination at Palo Verde. For covered incidents involving property damage not accompanied by a release of radioactive material, the policy's coverage limit is $2.25 billion . The Company has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions. A mutual insurance company whose members are utilities with nuclear facilities issues these policies. If losses at any nuclear facility covered by this mutual insurance company were to exceed the accumulated funds for these insurance programs, the Company could be assessed retrospective premium adjustments of up to $ 13.0 million for the current policy period.

Palo Verde Operations and Maintenance Expense . Included in other operations and maintenance expenses are expenses associated with Palo Verde as follows (in thousands):



Years Ended December 31,
2017		2016		2015
$	99,364	$	96,914	$	97,639

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NOTES TO FINANCIAL STATEMENTS

Four Corners

On July 6, 2016, the Company sold its interests in Four Corners for $32.0 million to 4C Acquisition, LLC, an affiliate of APS ("APS's affiliate"), and Pinnacle West Capital Corporation ("Pinnacle West"), the parent company of APS and APS's affiliate. No significant gain or loss was recorded for this sale. APS's affiliate assumed responsibility for all Four Corners capital expenditures made after July 6, 2016, which assumption is guaranteed by Pinnacle West. In addition, APS's affiliate will indemnify the Company against certain liabilities and costs related to the future operation of Four Corners, which indemnification is guaranteed by Pinnacle West. See Part II, Item 8, Financial Statements and Supplementary Data, Note C for a discussion of regulatory filings associated with Four Corners.

F. Accounting for Asset Retirement Obligation

The Company records its ARO in accordance with the FASB guidance. This guidance affects the accounting for the decommissioning of Palo Verde and the method used to report the decommissioning obligation. The Company also complies with the FASB guidance for conditional ARO which primarily affects the accounting for the disposal obligations of the Company’s fuel oil storage tanks, water wells, evaporative ponds and asbestos found at the Company’s gas-fired generating plants. The Company’s ARO are subject to various assumptions and determinations such as: (i) whether a legal obligation exists to remove assets; (ii) estimation of the fair value of the costs of removal; (iii) when final removal will occur; (iv) future changes in decommissioning cost escalation rates; and (v) the credit-adjusted interest rates to be utilized in discounting future liabilities. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as an expense for ARO. The Company records the increase in the ARO due to the passage of time as an operating expense (accretion expense). If the Company incurs or assumes any liability in retiring any asset at the end of its useful life without a legal obligation to do so, it will record such retirement costs as incurred.

The ARO liability for Palo Verde is based upon the estimated cost of decommissioning the plant from the 2016 Palo Verde decommissioning study. See Part II, Item 8, Financial Statements and Supplementary Data, Note E. The ARO liability is calculated by adjusting the estimated decommissioning costs for spent fuel storage and a profit margin and market-risk premium factor. The resulting costs are escalated over the remaining life of the plant and finally discounted using a credit-risk adjusted discount rate. As Palo Verde approaches the end of its estimated useful life, the difference between the ARO liability and future current cost estimates will narrow over time due to the accretion of the ARO liability. Because the DOE is obligated to assume responsibility for the permanent disposal of spent fuel, such costs have not been included in the ARO calculation. The Company maintains six external trust funds with an independent trustee that are legally restricted to settling its ARO at Palo Verde. The fair value of the funds at December 31, 2017 is $286.9 million .

The FASB guidance requires the Company to revise its previously recorded ARO for any changes in estimated cash flows including changes in estimated probabilities related to timing of settlements. Any changes that result in an upward revision to estimated cash flows shall be treated as a new liability. Any downward revisions to the estimated cash flows result in a reduction to the previously recorded ARO. The 2013 Study resulted in a downward revision of $1.9 million . In the second quarter of 2017, the Company implemented the results of the 2016 Palo Verde decommissioning study and revised its ARO related to Palo Verde to increase its estimated cash flows from the 2013 Study to the 2016 Study. See Part II, Item 8, Financial Statements and Supplementary Data, Note E. The assumptions used to calculate the increases to the Palo Verde ARO liability are as follows:



	Escalation Rate		Credit-Risk Adjusted Discount Rate
Original ARO liability	3.60	%	9.50	%
Incremental ARO liability (2010)	3.60	%	6.20	%
Incremental ARO liability (2016)	3.25	%	4.34	%

An analysis of the activity of the Company’s total ARO liability from January 1, 2015 through December 31, 2017 , including the effects of each year’s estimate revisions, is presented below (in thousands). In 2017, the estimate revision reflects increases in the estimated cash flows related to Palo Verde's decommissioning due to implementing the 2016 Palo Verde decommissioning study. In 2016, the settled liabilities reflect the sale of the Company's interest in Four Corners including the related ARO.

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NOTES TO FINANCIAL STATEMENTS



	2017			2016			2015
ARO liability at beginning of year	$	81,800		$	81,621		$	74,577
Liabilities incurred	138			—			189
Liabilities settled	(19		)	(6,993		)	—
Revisions to estimate	3,461			—			—
Accretion expense	7,649			7,172			6,855
ARO liability at end of year	$	93,029		$	81,800		$	81,621

The Company has transmission and distribution lines which are operated under various land rights agreements. Upon the expiration of any non-perpetual land rights agreement, the Company may have a legal obligation to remove the lines; however, the Company has assessed the likelihood of this occurring as remote. The majority of these agreements are perpetual or include renewal options which the Company routinely exercises. The amount of cost of removal collected in rates for non-legal liabilities has not been material.

G. Common Stock

Overview

The Company’s common stock has a stated value of $1 per share, with no cumulative voting rights or preemptive rights. Holders of the common stock have the right to elect the Company’s directors and to vote on other matters.

Long-Term Incentive Plan

On May 29, 2014 , the Company’s shareholders approved an amended and restated stock-based long-term incentive plan (the "Amended and Restated 2007 LTIP") and authorized the issuance of up to 1.7 million shares of the Company's common stock for the benefit of directors and employees. Under the Amended and Restated 2007 LTIP, shares of the Company's common stock may be issued through the award or grant of non-statutory stock options, incentive stock options, stock appreciation rights, restricted stock, bonus stock, performance stock, cash-based awards and other stock-based awards. The Company may issue new shares, purchase shares on the open market, or issue shares from shares of the Company's common stock the Company has repurchased to meet the share requirements of the Amended and Restated 2007 LTIP. Beginning in 2015, shares of the Company's common stock issued for employee benefit and stock incentive plans have been issued from the shares repurchased and held in treasury stock. As discussed in Part II, Item 8, Financial Statements and Supplementary Data, Note A, the Company accounts for its stock-based long-term incentive plan under the FASB guidance for stock-based compensation.

Restricted Stock with Service Condition and Other Stock-Based Awards . The Company has awarded restricted stock and other stock-based awards under its long-term incentive plan. Restrictions from resale on restricted stock awards generally lapse and awards vest over periods of one to three years, subject to continuous service requirements. The market value of the unvested restricted stock at the date of grant is amortized to expense over the restriction period net of anticipated forfeitures. Other stock-based awards, granted to directors in lieu of cash for retainers and meeting fees, are fully vested and are expensed at fair value on the date of grant and are not included in the tables below.

The expense, deferred tax benefit, and current tax expense recognized related to restricted stock and other stock-based awards in 2017 , 2016 and 2015 is presented below (in thousands):



	2017		2016		2015

Expense (a)	$	2,997	$	2,594	$	2,755
Deferred tax benefit	1,049		908		964
Current tax benefit recognized	318		183		43

_____________________

(a) Any capitalized costs related to these expenses is less than $0.3 million for all years.

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NOTES TO FINANCIAL STATEMENTS

The aggregate intrinsic value and fair value at grant date of restricted stock and other stock-based awards which vested in 2017 , 2016 and 2015 is presented below (in thousands):



	2017		2016		2015

Aggregated intrinsic value	$	3,711	$	2,515	$	3,451
Fair value at grant date	2,803		1,993		3,327

The unvested restricted stock transactions for 2017 are presented below:



	Total Shares		Weighted Average Grant Date Fair Value		Unrecognized Compensation Expense (a)		Aggregate Intrinsic Value
					(In thousands)		(In thousands)
Restricted shares outstanding at December 31, 2016 (b)	109,393		$	39.90
Stock awards	70,273		49.78
Vested	(68,470	)	40.93
Forfeitures	(4,961	)	40.18
Restricted shares outstanding at December 31, 2017 (b)	106,235		45.76		$	2,005	$	5,880

_______________________

(a) The unrecognized compensation expense is expected to be recognized over the weighted average remaining contractual term of the outstanding restricted stock of approximately one year.

(b) Excludes the stock based retention grant to the President and Chief Executive Officer ("CEO") of 27,624 shares. See "Restricted Stock with a Market Condition (Performance Shares)" section below for further details.

The weighted average fair value per share at grant date for restricted stock and other stock-base awards granted during 2017 , 2016 and 2015 were:



	2017		2016		2015
Weighted average fair value per share	$	49.78	$	40.95	$	37.17

The holder of a restricted stock award has rights as a shareholder of the Company, including the right to vote and receive cash dividends on restricted stock.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

Restricted Stock with a Market Condition (Performance Shares) . The Company has granted performance share awards to certain officers under the Company’s Amended and Restated 2007 LTIP, which provides for issuance of Company stock based on the achievement of certain performance criteria over a three -year period. The payout varies between 0% to 200% of performance share awards.

Detail of performance shares vested follows:



Date Vested	Payout Ratio		Performance Shares Awarded	Compensation Costs Expensed		Period Compensation Costs Expensed	Aggregated Intrinsic Value
				(In thousands)			(In thousands)
January 31, 2018	175	%	68,379	$	1,499	2015-2017	$	3,569
January 25, 2017	32	%	11,314	932		2014-2016	512
January 27, 2016	0	%	0	851		2013-2015	—
February 20, 2015	0	%	0	1,502		2012-2014	—

In 2018, 2019 and 2020, subject to meeting certain performance criteria and continuous service requirements, additional performance shares could vest. In accordance with the FASB guidance related to stock-based compensation, the Company recognizes the related compensation expense by ratably amortizing the grant date fair value of awards over the requisite service period and the compensation expense is only adjusted for forfeitures. As of December 31, 2017, the maximum number of shares that can be issued under the plan are 280,159 shares.

The fair value at the date of each separate grant of performance shares was based upon a Monte Carlo simulation . The Monte Carlo simulation reflected the structure of the performance plan which calculates the share payout on performance of the Company relative to a defined peer group over a three -year performance period based upon total return to shareholders. The fair value was determined as the average payout of one million simulation paths discounted to the grant date using a risk-free interest rate based upon the constant maturity treasury rate yield curve at the grant date. The expected volatility of total return to shareholders is calculated in accordance with the performance shares' term structure and includes the volatilities of all members of the defined peer group.

The outstanding performance share awards at the 100% performance level is summarized below:



	Number Outstanding		Weighted Average Grant Date Fair Value		Unrecognized Compensation Expense (b)		Aggregate Intrinsic Value
					(In thousands)		(In thousands)
Performance shares outstanding at December 31, 2016 (a)	166,444		$	34.40
Performance share awards	51,493		42.62
Performance shares vested	(11,314	)	26.36
Performance shares expired	(24,057	)	26.36
Performance shares forfeited	(9,975	)	39.53
Performance shares outstanding at December 31, 2017 (a)	172,591		38.21		$	2,048	$	9,553

_______________________

(a) On December 15, 2015, the Company issued a stock based retention grant to the President and CEO of 27,624 shares in accordance with the Amended and Restated 2007 LTIP that is eligible for vesting based on the achievement of certain performance conditions and a five year service period, as stated in the CEO's employment agreement. The performance condition was met as of November 2016 as determined by the Compensation Committee, and has been included in the beginning and ending balance in the table above.

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NOTES TO FINANCIAL STATEMENTS

(b) The unrecognized compensation expense is expected to be recognized over the weighted average remaining contractual term of the awards of approximately one year, except for the CEO retention grant.

A summary of information related to performance shares for 2017 , 2016 and 2015 is presented below:



	2017		2016		2015
Weighted average per share grant date fair value per share of performance shares awarded	$	42.62	$	38.11	$	35.72
Fair value of performance shares vested (in thousands)	298		—		—
Intrinsic value of performance shares vested (in thousands) (a)	512		—		—
Compensation expense (in thousands) (b) (c)	2,012		1,655		1,042
Deferred tax benefit related to compensation expense (in thousands) (b)	704		579		365

_____________________

(a) Based on a 100% performance level.

(b) Includes adjustments for estimated forfeitures.

Repurchase Program

No shares of the Company's common stock were repurchased during the twelve months ended December 31, 2017 . Detail regarding the Company's stock repurchase program are presented below:

______________________


(a)	Represents repurchased shares and cost since inception of the stock repurchase program in 1999.

(b)

Shares repurchased does not include 86,735 treasury shares related to employee compensation arrangements outside of the Company's repurchase programs. Beginning in 2015, shares of the Company's common stock issued for employee benefit and stock incentive plans have been issued from the shares repurchased and held in treasury stock. The Company awarded 256,929 shares, net of shares withheld for taxes, out of treasury stock during 2017.

The Company may in the future make purchases of shares of its common stock pursuant to its authorized program in open market transactions at prevailing prices and may engage in private transactions where appropriate. The repurchased shares will be available for issuance under employee benefit and stock incentive plans, or may be retired.

Dividend Policy

On December 29, 2017, the Company paid $13.6 million in quarterly cash dividends to shareholders. The Company paid a total of $53.3 million , $49.6 million and $47.1 million in cash dividends during the twelve months ended December 31, 2017 , 2016 and 2015 , respectively. On February 1, 2018 , the Board of Directors declared a quarterly cash dividend of $0.335 per share payable on March 30, 2018 to shareholders of record as of the close of business on March 16, 2018 .

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NOTES TO FINANCIAL STATEMENTS

Basic and Diluted Earnings Per Share

The FASB guidance requires the Company to include share-based compensation awards that qualify as participating securities in both basic and diluted earnings per share to the extent they are dilutive. A share-based compensation award is considered a participating security if it receives non-forfeitable dividends or may participate in undistributed earnings with common stock. The Company awards unvested restricted stock which qualifies as a participating security. The basic and diluted earnings per share are presented below:



	Years Ended December 31,
	2017			2016			2015
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	40,414,556			40,350,688			40,274,986
Dilutive effect of unvested performance awards	120,635			57,345			33,576
Diluted number of common shares outstanding	40,535,191			40,408,033			40,308,562
Basic net income per common share:
Net income	$	98,261		$	96,768		$	81,918
Income allocated to participating restricted stock	(368		)	(321		)	(243		)
Net income available to common shareholders	$	97,893		$	96,447		$	81,675
Diluted net income per common share:
Net income	$	98,261		$	96,768		$	81,918
Income reallocated to participating restricted stock	(368		)	(321		)	(243		)
Net income available to common shareholders	$	97,893		$	96,447		$	81,675
Basic net income per common share:
Distributed earnings	$	1.315		$	1.225		$	1.165
Undistributed earnings	1.105			1.165			0.865
Basic net income per common share	$	2.420		$	2.390		$	2.030
Diluted net income per common share:
Distributed earnings	$	1.315		$	1.225		$	1.165
Undistributed earnings	1.105			1.165			0.865
Diluted net income per common share	$	2.420		$	2.390		$	2.030

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:



	Year Ended December 31,
	2017	2016	2015
Restricted stock awards	67,739	53,703	56,375
Performance shares (a)	—	47,246	66,804

_____________________


(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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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

H. Accumulated Other Comprehensive Income (Loss)



Changes in Accumulated Other Comprehensive Income (Loss) (net of tax) by component are presented below (in thousands):
		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 December 31, 2014		$	(34,884	)	$	38,957		$	(12,074	)	$	(8,001	)
	Other comprehensive income (loss) before reclassifications	3,777			(2,255		)	—			1,522
	Amounts reclassified from accumulated other comprehensive income (loss)	1,238			(8,937		)	264			(7,435		)
Balance at December 31, 2015		(29,869		)	27,765			(11,810		)	(13,914		)
	Other comprehensive income before reclassifications	7,363			6,904			—			14,267
	Amounts reclassified from accumulated other comprehensive income (loss)	(1,422		)	(6,206		)	159			(7,469		)
Balance at December 31, 2016		(23,928		)	28,463			(11,651		)	(7,116		)
	Other comprehensive income before reclassifications	7,951			20,251			—			28,202
	Amounts reclassified from accumulated other comprehensive income (loss)	(1,813		)	(8,524		)	309			(10,028		)
Balance at December 31, 2017		$	(17,790	)	$	40,190		$	(11,342	)	$	11,058

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

Amounts reclassified from Accumulated Other Comprehensive Income (Loss) for the twelve months ended December 31, 2017 , 2016 and 2015 are as follows (in thousands):



Details about Accumulated Other Comprehensive Income (Loss) Components		2017			2016			2015			Affected Line Item in the Statements of Operations

Amortization of pension and post-retirement benefit costs:
	Prior service benefit	$	9,657		$	7,407		$	6,574		(a)
	Net loss	(6,776		)	(4,965		)	(8,622		)	(a)
		2,881			2,442			(2,048		)	(a)
	Income tax effect	(1,068		)	(1,020		)	810			Income tax expense
		1,813			1,422			(1,238		)	Net income

Marketable securities:
	Net realized gain on sale of securities	10,626			7,640			11,114			Investment and interest income, net
		10,626			7,640			11,114			Income before income taxes
	Income tax effect	(2,102		)	(1,434		)	(2,177		)	Income tax expense
		8,524			6,206			8,937			Net income

Loss on cash flow hedge:
	Amortization of loss	(532		)	(498		)	(467		)	Interest on long-term debt and revolving credit facility
		(532		)	(498		)	(467		)	Income before income taxes
	Income tax effect	223			339			203			Income tax expense
		(309		)	(159		)	(264		)	Net income

	Total reclassifications	$	10,028		$	7,469		$	7,435

(a) These items are included in the computation of net periodic benefit cost. See Part II, Item 8, Financial Statements and Supplementary Data, Note M for additional information.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

I. Long-Term Debt and Financing Obligations

Outstanding long-term debt and financing obligations, net of issuance costs, are as follows:



	December 31,
	2017			2016
	(In thousands)
Long-Term Debt:
Pollution Control Bonds (1):
7.25% 2009 Series A refunding bonds, due 2040 (7.46% effective interest rate)	$	62,657		$	62,619
4.50% 2012 Series A refunding bonds, due 2042 (4.63% effective interest rate)	58,501			58,471
7.25% 2009 Series B refunding bonds, due 2040 (7.49% effective interest rate)	36,518			36,492
1.875% 2012 Series A refunding bonds, due 2032 (2.35% effective interest rate)	—			33,193
Total Pollution Control Bonds	157,676			190,775
Senior Notes (2):
6.00% Senior Notes, net of discount, due 2035 (6.58% effective interest rate)	394,040			393,861
7.50% Senior Notes, net of discount, due 2038 (7.67% effective interest rate)	147,384			147,331
3.30% Senior Notes, net of discount, due 2022 (3.43% effective interest rate)	149,101			148,939
5.00% Senior Notes, net of discount, due 2044 (4.93% effective interest rate)	302,901			302,955
Total Senior Notes	993,426			993,086
RGRT Senior Notes (3):
4.47% Senior Notes, Series B, due 2017 (4.62% effective interest rate)	—			49,950
5.04% Senior Notes, Series C, due 2020 (5.16% effective interest rate)	44,886			44,845
Total RGRT Senior Notes	44,886			94,795
Total long-term debt	1,195,988			1,278,656
Financing Obligations:
Revolving Credit Facility (4)	173,533			81,574
Total long-term debt and financing obligations	1,369,521			1,360,230
Current Portion (amount due within one year):
Current maturities of long term debt	—			(83,143		)
Short-term borrowings under the revolving credit facility	(173,533		)	(81,574		)
	$	1,195,988		$	1,195,513

_____________________


(1)	Pollution Control Bonds ("PCBs")

The Company had four series of tax exempt unsecured PCBs in aggregate principal amount of $193.1 million . In September 2017, the $33.3 million 2012 Series A 1.875% PCBs, which were subject to mandatory tender for purchase, were redeemed and retired utilizing funds borrowed under the RCF. As of December 31, 2017, the Company's aggregate principal amount on PCBs was $159.8 million . The 7.25% 2009 Series A and the 7.25% 2009 Series B PCBs with an aggregate principal amount, together, of $100.6 million have optional redemptions beginning in February 2019 and April 2019, respectively.


(2)	Senior Notes

The Senior Notes are unsecured obligations of the Company. They were issued pursuant to bond covenants that provide limitations on the Company’s ability to enter into certain transactions. The 6.00% Senior Notes have an aggregate principal amount of $400.0 million and were issued in May 2005 . The proceeds, net of a $2.3 million discount, were used to fund the retirement of the Company's first mortgage bonds. The Company amortizes the loss associated with a cash flow hedge recorded in accumulated other comprehensive income to earnings as interest expense over the life of the 6.00% Senior Notes. See Part II, Item 8, Financial Statements and Supplementary Data, Note O. This amortization is included in the effective interest rate of the 6.00% Senior Notes.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The 7.50% Senior Notes have an aggregate principal amount of $150.0 million and were issued in June 2008 . The proceeds, net of a $1.3 million discount, were used to repay short-term borrowings of $44.0 million , fund capital expenditures and for other general corporate purposes.

The 3.30% Senior Notes have an aggregate principal amount of $150.0 million were issued in December 2012 . The proceeds, net of a $0.3 million discount, were used to fund construction expenditures and for working capital and general corporate purposes.

In December 2014 , the Company issued 5.00% Senior Notes with an aggregate principal amount of $150.0 million . The proceeds, net of a $0.5 million discount, were used to fund construction expenditures and for working capital and general corporate purposes. In March 2016 , the Company issued additional 5.00% Senior Notes with an aggregate principal amount of $150.0 million . The proceeds from this issuance, after deducting the underwriters' commission, were $158.1 million . These proceeds included accrued interest of $2.4 million and a $7.1 million premium before expenses. The net proceeds, from the sale of these senior notes were used to repay outstanding short-term borrowings under the RCF. After the March 2016 issuance, the Company's 5.00% Senior Notes due 2044 had a total principal amount outstanding of $300.0 million .


(3)	RGRT Senior Notes

In 2010, the Company and RGRT, a Texas grantor trust through which the Company finances its 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 million aggregate principal amount of Senior Notes ("RGRT Notes"). In August 2015 and 2017, $15.0 million and $50.0 million of these RGRT Notes, respectively, matured and were paid with borrowings from the RCF. The Company guarantees the payment of principal and interest on the RGRT Notes. In the Company’s financial statements, the assets and liabilities of RGRT are reported as assets and liabilities of the Company.

RGRT pays interest on the RGRT Notes on February 15, and August 15 of each year until maturity. RGRT may redeem the RGRT Notes, in whole or in part, at any time at a redemption price equal to 100% of the principal amount to be redeemed together with the interest on such principal amount accrued to the date of redemption, plus a make-whole amount based on the prevailing market interest rates. The agreement requires compliance with certain covenants, including a total debt to capitalization ratio. The Company was in compliance with these requirements throughout 2017.

The sale of the RGRT Notes was made by RGRT in reliance on a private placement exemption from registration under the Securities Act of 1933, as amended. The proceeds of $109.4 million , net of issuance costs, from the sale of the RGRT Notes was used by RGRT to repay amounts borrowed under the RCF and will enable future nuclear fuel financing requirements of RGRT to be met with a combination of the RGRT Notes and amounts borrowed from the RCF.


(4)	Revolving Credit Facility

On January 14, 2014, the Company and RGRT entered into a second amended and restated credit agreement related to the RCF with JP Morgan Chase Bank, N.A., as administrative agent and issuing bank, and Union Bank, N.A., as syndication agent, and various lending banks party thereto. As of December 31, 2016, the Company had available $300 million and the ability to increase the RCF by up to $100 million with a term ending January 2019 . On January 9, 2017, the Company exercised its option to extend the maturity of the RCF by one year to January 14, 2020 and to increase the size of the facility by $50 million to $350 million . The Company still has the option to extend the facility by one additional year to January 2021 and to increase the RCF by up to $50 million (up to a total of $400 million ) upon the satisfaction of certain conditions, more fully set forth in the agreement, including obtaining commitments from lenders or third party financial institutions.

The RCF provides that amounts borrowed by the Company may be used for, among other things, working capital and general corporate purposes. Any amounts borrowed by RGRT may be used, among other things, to finance the acquisition and processing of nuclear fuel. Amounts borrowed by RGRT are guaranteed by the Company and the balance borrowed under the RCF is recorded as short-term borrowings on the balance sheet. The RCF is unsecured. The RCF requires compliance with certain covenants, including a total debt to capitalization ratio. The Company was in compliance with these requirements throughout 2017. In August 2015 and 2017, $15.0 million aggregate principal amount of Series A 3.67% Senior Notes and $50.0 million aggregate principal amount of Series B 4.47% Senior Notes of RGRT, respectively, matured and were paid with borrowings from the RCF. As of December 31, 2017 , the total amount borrowed by RGRT was $88.5 million for nuclear fuel

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

under the RCF. As of December 31, 2017 , $85.0 million of borrowings were outstanding under this facility for working capital and general corporate purposes. The weighted average interest rate on the RCF was 2.7% as of December 31, 2017 .

As of December 31, 2017 , the principal amount of scheduled maturities for the next five years of long-term debt are as follows (in thousands):



2018	$	—
2019	—
2020	45,000
2021	—
2022	—

J. Income Taxes

On December 22, 2017, the TCJA was enacted. The TCJA includes significant changes to the IRC, including amendments which significantly changed the taxation of business entities and includes specific provisions related to regulated public utilities. The more significant changes that impact the Company included in the TCJA are reductions in the corporate federal income tax rate from 35% to 21% , elimination of the corporate alternative minimum tax provision, additional limitations on deductions of executive compensation, and limitations on the utilization of NOLs arising after December 31, 2017, to 80% of taxable income with no carryback but with an indefinite carryforward. The specific provisions related to regulated public utilities in the TCJA generally provide for the continued deductibility of interest expense, the elimination of bonus depreciation for property acquired and placed into service after September 27, 2017, and the continuance of rate normalization requirements for accelerated depreciation benefits and changes to deferred tax balances as a result of the change in the corporate federal income tax rate.

The results for the twelve months ended December 31, 2017 contain provisional estimates of the impact of the TCJA. These amounts are considered provisional because they use estimates for which tax returns have not yet been filed and because estimated amounts may be impacted by future regulatory and accounting guidance if and when issued. The Company will adjust these provisional amounts as further information becomes available and as we refine our calculations. As permitted by recent guidance issued by the Securities and Exchange Commission, these adjustments will occur during a reasonable “measurement period” not to exceed twelve months from the date of enactment.

Provisional reductions in accumulated deferred federal income taxes ("ADFIT") due to the reduction in the corporate income tax rate to 21% under the provisions of the TCJA will result in amounts previously collected from utility customers for these deferred taxes to be refundable to such customers, generally through reductions in future rates. The TCJA includes provisions that stipulate how these excess deferred taxes are to be returned to customers for certain accelerated tax depreciation benefits. Potential refunds of other deferred taxes will be determined by the Company’s regulators. The December 31, 2017 balance sheet reflects the impact of the TCJA which reduced ADFIT by $298.9 million , reduced regulatory assets by $23.6 million and increased regulatory liabilities by $275.3 million . The changes in deferred taxes were recorded at the amount of the reduced future cash flow expected to be included in rates, as required in ASC 740. These adjustments had no impact on the Company’s cash flows for the year ended December 31, 2017.

In February 2018, the FASB issued ASU 2018-02, as a result of concerns raised by stakeholders due to the TCJA. ASU 2018-02 addresses concerns that the tax reduction due to the change in the corporate tax rate from 35% to 21% would be “stranded” in AOCI. ASU 2018-02 allows companies to reclassify stranded taxes from AOCI to retained earnings. The Company is currently in the process of evaluating the impact of ASU 2018-02 and its impact on regulated utilities. At December 31, 2017, the Company has $7.2 million in stranded taxes in AOCI.

The provisional tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2017 and 2016 are presented below (in thousands):

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS



	December 31,
	2017			2016
Deferred tax assets:
Benefit of tax loss carryforwards	$	24,035		$	60,749
Alternative minimum tax credit carryforward	16,620			16,620
Pensions and benefits	32,606			57,756
Asset retirement obligation	19,530			26,929
Regulatory liabilities related to income taxes	63,794			—
Deferred fuel	1,405			—
Total gross deferred tax assets	157,990			162,054
Deferred tax liabilities:
Plant, principally due to depreciation and basis differences	(426,077		)	(668,303		)
Decommissioning	(34,520		)	(43,463		)
Deferred fuel	—			(3,962		)
Other	(2,416		)	(1,392		)
Total gross deferred tax liabilities	(463,013		)	(717,120		)
Net accumulated deferred income taxes	$	(305,023	)	$	(555,066	)

Based on the average annual earnings before taxes for the prior three years , and excluding the effects of unusual or infrequent items, the Company believes that the deferred tax assets will be fully realized.

The Company recognized income tax expense for 2017 , 2016 and 2015 as follows (in thousands):



	Years Ended December 31,
	2017			2016			2015
Income tax expense:
Federal:
Current	$	2,507		$	2,642		$	2,319
Deferred	46,089			47,909			32,819
Total federal income tax	48,596			50,551			35,138
State:
Current	(897		)	766			1,730
Deferred	1,816			3,285			(1,650		)
Total state income tax	919			4,051			80
Generation (amortization) of accumulated investment tax credits	1,489			(684		)	(323		)
Total income tax expense	$	51,004		$	53,918		$	34,895

As of December 31, 2017 , the Company had $16.6 million of AMT credit carryforwards. Based on the TCJA provisions, the Company may claim a refund of 50% of the remaining AMT credits (to the extent the credits exceed the Company's regular tax liability for the year) in 2018, 2019, and 2020. Any AMT credits remaining after 2020 will be refunded in 2021. As of December 31, 2017 , the Company had $23.0 million of federal and $1.4 million of state tax loss carryforwards. Under the TCJA, NOLs arising in tax years ending after 2017 cannot be carried back but can be carried forward indefinitely. The use of NOLs generated after 2017 to offset taxable income is limited to 80% of taxable income. Federal NOLs generated prior to 2018 are able to offset 100% of future taxable income to the extent available but have lives of only 20 years .

Income tax provisions differ from amounts computed by applying the statutory federal income tax rate of 35% to book income before federal income tax as follows (in thousands):

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS



	Years Ended December 31,
	2017			2016			2015
Federal income tax expense computed on income at statutory rate	$	52,243		$	52,740		$	40,885
Difference due to:
State taxes, net of federal benefit	597			2,633			52
AEFUDC	450			(475		)	(2,345		)
Permanent tax differences	(2,562		)	(2,369		)	(2,898		)
Other	276			1,389			(799		)
Total income tax expense	$	51,004		$	53,918		$	34,895
Effective income tax rate	34.2		%	35.8		%	29.9		%

The Company files income tax returns in the United States federal jurisdiction and in the states of Texas, New Mexico and Arizona. The Company is no longer subject to tax examination by the taxing authorities in the federal, Arizona and New Mexico jurisdictions for years prior to 2013. In August 2017, the Company reached an agreement with the Texas Comptroller of Public Accounts and settled audits in Texas for tax years 2007 through 2011 .

In the third quarter of 2016, the Company changed its accounting for state income taxes from the flow-through method to the normalization method in accordance with the 2016 PUCT Final Order and the NMPRC Final Order. Under the flow-through method, the Company previously recorded deferred state income taxes and regulatory liabilities and assets offsetting such deferred state income taxes at the expected cash flow to be reflected in future rates. Upon implementation of normalization, the Company began amortizing the net regulatory asset for deferred state income taxes to deferred income tax expense over a 15 year period as allowed by the regulators. In the third quarter of 2016, the Company began recording deferred state income tax expense as required by normalization, retroactive to January 2016 as provided in the final orders. The impact of the change was additional income tax expense of $1.9 million and $5.1 million for the years ended December 31, 2017 and 2016, respectively.

The FASB guidance prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The Company recorded a decrease of $1.2 million (net of an increase of $0.5 million ), a decrease of $0.4 million (net of an increase of $ 0.3 million ), and an unrecognized tax position of $0.8 million , in 2017 , 2016 , and 2015 respectively, related to transmission and distribution costs and other amounts deducted in current and prior year Texas franchise tax returns. The Company recorded an unrecognized tax position of $0.1 million in 2017 and a decrease of $0.3 million in 2016 related to tax credits taken and apportionment factors used in prior year Arizona income tax returns, which have been settled through audit. A reconciliation of the December 31, 2017 , 2016 and 2015 amounts of unrecognized tax benefits are as follows (in thousands):



	2017			2016			2015
Balance at January 1	$	5,300		$	6,000		$	5,200
Additions for tax positions related to the current year	200			400			500
Reductions for tax positions related to the current year	—			—			—
Additions for tax positions of prior years	400			100			300
Reductions for tax positions of prior years	(1,700		)	(1,200		)	—
Balance at December 31	$	4,200		$	5,300		$	6,000

If recognized, $1.1 million of the unrecognized tax position at December 31, 2017 , would reduce the effective tax rate. The Company recognized an income tax benefit for the decrease in unrecognized tax positions of $1.1 million for the year ended December 31, 2017 .

The Company recognizes in tax expense interest and penalties related to tax benefits that have not been recognized. For the year ended December 31, 2017 , the Company recognized a benefit of $0.2 million . For the years ended December 31, 2016 , and 2015 the Company recognized interest expense of $0.1 million , and $0.2 million , respectively. The Company had approximately $0.7 million and $0.8 million accrued for the payment of interest and penalties at December 31, 2017 and 2016 , respectively.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

K. Commitments, Contingencies and Uncertainties

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 that 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. The Company has entered into the following significant agreements with various counterparties for the purchase and sale of electricity:



						Commercial
						Operation
Type of Contract	Counterparty	Quantity			Term	Date
Power Purchase and Sale Agreement	Freeport		25	MW	December 2008 through December 2018	N/A
Power Purchase and Sale Agreement	Freeport		100	MW	June 2006 through December 2021	N/A
Power Purchase Agreement	Hatch Solar Energy Center I, LLC		5	MW	July 2011 through July 2036	July 2011
Power Purchase Agreement	NRG		20	MW	August 2011 through August 2031	August 2011
Power Purchase Agreement	SunE EPE1, LLC		10	MW	June 2012 through June 2037	June 2012
Power Purchase Agreement	SunE EPE2, LLC		12	MW	May 2012 through May 2037	May 2012
Power Purchase Agreement	Macho Springs Solar, LLC		50	MW	May 2014 through May 2034	May 2014
Power Purchase Agreement	Newman Solar LLC		10	MW	December 2014 through December 2044	December 2014

The Company has a firm Power Purchase and Sale Agreement with Freeport-McMoran Copper & Gold Energy Services LLC ("Freeport") that provides for Freeport to deliver energy to the Company from the Luna Energy Facility (a natural gas-fired combined cycle generation facility located in Luna County, New Mexico) and for the Company to deliver a like amount of energy at Greenlee, Arizona. The Company may purchase the quantities noted in the table above at a specified price at times when energy is not exchanged under the Power Purchase and Sale Agreement. The agreement was approved by the FERC and will continue through an initial term ending December 31, 2021 , with subsequent rollovers until terminated. Upon mutual agreement, the Power Purchase and Sale Agreement allows the parties to increase the amount of energy that is purchased and sold under the agreement. The parties have agreed to increase the amount up to 125 MW through December 2018.

The Company has entered into several power purchase agreements to help meet its renewable portfolio requirements. Namely, the Company has a 25 -year purchase power agreement with Hatch Solar Energy Center I, LLC to purchase all of the output from a solar photovoltaic plant located in southern New Mexico which began commercial operation in July 2011 . In June 2015, the Company entered into a consent agreement with Hatch Solar Energy Center 1, LLC to provide for additional or replacement photovoltaic modules. The Company also entered into a 20 -year contract with NRG Solar Roadrunner LLC ("NRG") to purchase all of the output of a solar photovoltaic plant built in southern New Mexico which began commercial operation in August 2011 . In addition, the Company has 25 -year purchase power agreements to purchase all of the output of two additional solar photovoltaic plants located in southern New Mexico, SunE EPE1, LLC and SunE EPE2, LLC which began commercial operation in June 2012 and May 2012 , respectively. In September 2017, Longroad Solar Portfolio Holdings, LLC purchased SunE EPE1, LLC and in October 2017, Silicon Ranch Corporation purchased SunE EPE2, LLC with the Company's consent per the terms of both purchase power agreements.

Furthermore, the Company has a 20 -year purchase power agreement with Macho Springs Solar, LLC to purchase the entire generation output delivered from the 50 MW Macho Springs solar photovoltaic plant located in Luna County, New Mexico which began commercial operation in May 2014 . Finally, the Company has a 30 -year purchase power agreement with Newman Solar LLC to purchase the total output of approximately 10 MW from a solar photovoltaic plant on land subleased from the Company in proximity to its Newman Power Station ("Newman"). This solar photovoltaic plant began commercial operation in December 2014 .

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

Environmental Matters

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

Environmental Litigation and Investigations . Since July 2011, the U.S. Department of Justice (the "DOJ"), on behalf of the EPA, and APS have been engaged in substantive settlement negotiations in an effort to resolve certain of the pending matters. The allegations being addressed through settlement negotiations are that APS failed to obtain the necessary permits and install the controls necessary under the CAA to reduce sulfur dioxide ("SO2"), nitrogen oxides ("NOx"), and particulate matter ("PM") , and that defendants failed to obtain an operating permit under Title V of the CAA that reflects applicable requirements imposed by law. On June 24, 2015, the parties filed with the U.S. District Court for New Mexico a settlement agreement ("CAA Settlement Agreement") resolving this matter. On August 17, 2015, the U.S. District Court for New Mexico entered the CAA Settlement Agreement. The agreement imposes a total civil penalty payable by the co-owners of Four Corners collectively in the amount of $1.5 million , and it requires the co-owners to pay $6.7 million for environmental mitigation projects. At December 31, 2017, the Company has accrued its remaining unpaid share of approximately $0.2 million related to this matter.

Lease Agreements

The Company leases land in El Paso, Texas, adjacent to Newman under a lease which expires in June 2033 with a renewal option of 25 years . The Company also has several other leases for office, parking facilities and equipment which expire within the next 5 years . The Company has transmission and distribution lines which are operated under various land rights agreements, including easements, leases, permits and franchises. The majority of these agreements include renewal options which the Company routinely exercises. These agreements generally do not impose any restrictions relating to issuance of additional debt, payment of dividends or entering into other lease arrangements. The Company has no significant capital lease agreements.

The Company's total annual rental expense related to operating leases was $2.4 million , $1.7 million , and $1.9 million for 2017 , 2016 and 2015 , respectively. As of December 31, 2017 , the Company’s minimum future rental payments for the next five years are as follows (in thousands):



2018	$	951
2019	893
2020	820
2021	675
2022	595

Union Matters

The Company has approximately 1,100 employees, about 38% of whom are covered by a collective bargaining agreement.

The International Brotherhood of Electrical Workers Local 960 ("Local 960") represents the Company’s employees working primarily in the power plants, substations, line crews, meter reading and collection, facilities services, and customer service. The Company entered into a new collective bargaining agreement effective September 3, 2016, with Local 960 for a three-year term ending September 3, 2019. The agreement provides for pay increases of 3% on September 3, 2016, September 3, 2017 and on September 3, 2018, respectively.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

L. Litigation

See

Part II, Item 8, Financial Statements and Supplementary Data, Note C and Note K for discussion of the effects of government legislation and regulation on the Company as well as certain pending legal proceedings.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

M. Employee Benefits

Retirement Plans

The Company’s Retirement Income Plan (the "Retirement Plan") is a qualified noncontributory defined benefit plan. Upon retirement or death of a vested plan participant, assets of the Retirement Plan are used to pay benefit obligations under the Retirement Plan. Contributions from the Company are based on various factors, such as the minimum funding amounts required by the Internal Revenue Service ("IRS"), state and federal regulatory requirements, amounts requested from customers in the Company's Texas and New Mexico jurisdictions, and the annual net periodic benefit cost of the Retirement Plan, as actuarially calculated. The assets of the Retirement Plan are primarily invested in common collective trusts which hold equity securities, debt securities and cash equivalents and are managed by a professional investment manager appointed by the Company.

The Company has two non-qualified retirement plans that are non-funded defined benefit plans. The Company's Supplemental Retirement Plan covers certain former employees and directors of the Company. The Excess Benefit Plan was adopted in 2004 and covers certain active and former employees of the Company. The net periodic benefit cost for the non-qualified retirement plans are based on substantially the same actuarial methods and economic assumptions as those used for the Retirement Plan.

The Retirement Plan was amended effective April 1, 2014 to offer a cash balance pension benefit as an alternative to its existing final average pay pension benefit for employees hired prior to January 1, 2014 . Employees hired after January 1, 2014 are automatically enrolled in the cash balance pension benefit.

Prior to December 31, 2013 , employees who completed one year of service with the Company and worked at least a minimum number of hours each year were covered by the final average pay formula of the plan. For participants that continue to be covered by the final average pay formula, retirement benefits are based on the employee’s final average pay and years of service. The cash balance pension benefit covers employees beginning on their employment commencement date or re-employment commencement date. Retirement benefits under the cash balance pension benefit are based on the employee’s cash balance account, consisting of pay credits and interest credits.

The obligations and funded status of the plans are presented below (in thousands):



	December 31,
	2017						2016
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Change in projected benefit obligation:
Benefit obligation at end of prior year	$	337,768		$	27,462		$	325,706		$	26,958
Service cost	8,156			362			7,705			296
Interest cost	12,196			863			12,161			878
Actuarial loss	20,829			2,217			7,988			1,267
Benefits paid	(16,960		)	(2,512		)	(15,792		)	(1,937		)
Benefit obligation at end of year	361,989			28,392			337,768			27,462
Change in plan assets:
Fair value of plan assets at end of prior year	269,766			—			260,035			—
Actual return on plan assets	44,283			—			18,223			—
Employer contribution	7,300			2,512			7,300			1,937
Benefits paid	(16,960		)	(2,512		)	(15,792		)	(1,937		)
Fair value of plan assets at end of year	304,389			—			269,766			—
Funded status at end of year	$	(57,600	)	$	(28,392	)	$	(68,002	)	$	(27,462	)

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

Amounts recognized in the Company's balance sheets consist of the following (in thousands):



	December 31,
	2017						2016
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Current liabilities	$	—		$	(2,154	)	$	—		$	(2,696	)
Noncurrent liabilities	(57,600		)	(26,238		)	(68,002		)	(24,766		)
Total	$	(57,600	)	$	(28,392	)	$	(68,002	)	$	(27,462	)

The accumulated benefit obligation in excess of plan assets is as follows (in thousands):



	December 31,
	2017						2016
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Projected benefit obligation	$	(361,989	)	$	(28,392	)	$	(337,768	)	$	(27,462	)
Accumulated benefit obligation	(329,279		)	(25,370		)	(314,071		)	(25,550		)
Fair value of plan assets	304,389			—			269,766			—

Pre-tax amounts recognized in accumulated other comprehensive income consist of the following (in thousands):



	Years Ended December 31,
	2017						2016
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Net loss	$	109,215		$	11,408		$	121,052		$	10,073
Prior service benefit	(20,410		)	(146		)	(23,877		)	(185		)
Total	$	88,805		$	11,262		$	97,175		$	9,888

The following are the weighted-average actuarial assumptions used to determine the benefit obligations:



	December 31,
	2017						2016
			Non-Qualified						Non-Qualified
	Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan		Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan
Discount rate	3.77	%	3.40	%	3.81	%	4.29	%	3.76	%	4.34	%
Rate of compensation increase	4.5	%	N/A		4.5	%	4.5	%	N/A		4.5	%

The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed and updated at each measurement date. The discount rate used to measure the fiscal year end obligation is based on a segmented spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. A 1% increase in the discount rate would decrease the December 31, 2017 retirement plans' projected benefit obligation by 12.4% . A 1% decrease in the discount rate would increase the December 31, 2017 retirement plans' projected benefit obligation by 15.6% .

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The components of net periodic benefit cost are presented below (in thousands):



	Years Ended December 31,
	2017						2016						2015
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Service cost	$	8,156		$	362		$	7,705		$	296		$	8,530		$	262
Interest cost	12,196			863			12,161			878			13,477			1,018
Expected return on plan assets	(19,189		)	—			(18,879		)	—			(19,795		)	—
Amortization of:
Net loss	7,572			882			6,554			785			9,710			937
Prior service benefit	(3,467		)	(39		)	(3,467		)	(39		)	(3,467		)	(39		)
Net periodic benefit cost	$	5,268		$	2,068		$	4,074		$	1,920		$	8,455		$	2,178

In 2016, the Company changed the method used to estimate the service and interest components of net periodic benefit cost for pension benefits . This change, compared to the previous method, resulted in a decrease of approximately $2.9 million in the service cost and interest cost components in 2016. Historically, the Company estimated service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. In 2016, the Company elected to utilize a full yield curve approach to estimate these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows. The Company believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plan’s liability cash flows to the corresponding spot rates on the yield curve. The Company accounted for this change as a change in accounting estimate and accordingly, accounted for this prospectively.

The changes in benefit obligations recognized in other comprehensive income are presented below (in thousands):



	Years Ended December 31,
	2017						2016						2015
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Net (gain) loss	$	(4,265	)	$	2,217		$	8,644		$	1,266		$	4,266		$	(811	)
Amortization of:
Net loss	(7,572		)	(882		)	(6,554		)	(785		)	(9,710		)	(937		)
Prior service benefit	3,467			39			3,467			39			3,467			39
Total recognized in other comprehensive income	$	(8,370	)	$	1,374		$	5,557		$	520		$	(1,977	)	$	(1,709	)

The total amount recognized in net periodic benefit costs and other comprehensive income are presented below (in thousands):



	Years Ended December 31,
	2017					2016				2015
	Retirement Income Plan			Non-Qualified Retirement Plans		Retirement Income Plan		Non-Qualified Retirement Plans		Retirement Income Plan		Non-Qualified Retirement Plans
Total recognized in net periodic benefit cost and other comprehensive income	$	(3,102	)	$	3,442	$	9,631	$	2,440	$	6,478	$	469

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The following are amounts in accumulated other comprehensive income that are expected to be recognized as components of net periodic benefit cost during 2018 (in thousands):



	Retirement Income Plan			Non-Qualified Retirement Plans
Net loss	$	7,450		$	960
Prior service benefit	(3,470		)	(40		)

The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost for the twelve months ended December 31 :



	2017						2016						2015
			Non-Qualified						Non-Qualified						Non-Qualified
	Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan		Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan		Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan
Discount rate
Benefit obligation	4.30	%	3.76	%	4.35	%	4.57	%	3.99	%	4.63	%	4.0	%	3.4	%	4.1	%
Service cost	4.51	%	N/A		4.52	%	4.83	%	N/A		4.87	%	4.0	%	N/A		4.1	%
Interest cost	3.70	%	2.94	%	3.78	%	3.86	%	3.04	%	3.9	%	4.0	%	3.4	%	4.1	%
Expected long-term return on plan assets	7.0	%	N/A		N/A		7.0	%	N/A		N/A		7.5	%	N/A		N/A
Rate of compensation increase	4.5	%	N/A		4.5	%	4.5	%	N/A		4.5	%	4.5	%	N/A		4.5	%

The Company’s overall expected long-term rate of return on assets is 7.5% effective January 1, 2018, which is both a pre-tax and after-tax rate as pension funds are generally not subject to income tax. The expected long-term rate of return is based on the weighted average of the expected returns on investments based upon the target asset allocation of the pension fund. The Company’s target allocations for the plan’s assets are presented below:



	December 31, 2017
Equity securities	50	%
Fixed income	40	%
Alternative investments	10	%
Total	100	%

As of January 1, 2018, the long-term rate of return assumption was updated to be gross of administrative expenses paid to the trust. Net of administrative expenses, the reported long-term rate of return would have been 7.0% .

The Retirement Plan invests the majority of its plan assets in common collective trusts which includes a diversified portfolio of domestic and international equity securities and fixed income securities. Alternative investments of the Retirement Plan are comprised of a real estate limited partnership and equity securities of real estate companies, primarily in real estate investment trusts, and other property trusts. The expected rate of returns for the funds are assessed annually and are based on long-term relationships among major asset classes and the level of incremental returns that can be earned by the successful implementation of different active investment management strategies. Equity and real estate equity returns are based on estimates of long-term inflation rate, real rate of return, 10-year Treasury bond premium over cash, an expected equity risk premium, as well as other economic factors. Fixed income returns are based on maturity, long-term inflation, real rate of return and credit spreads. These assumptions also capture the expected correlation of returns between these asset classes over the long term.

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The FASB guidance on disclosure for pension plans requires disclosure of fair value measurements of plan assets. To increase consistency and comparability in fair value measurements, the FASB guidance on fair value measurements established 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. Prices of securities held in the mutual funds and underlying portfolios of the Retirement Plan are primarily obtained from independent pricing services. These prices are based on observable market data. The Common Collective Trusts are valued using the Net Asset Value ("NAV") provided by the administrator of the fund. The NAV price is quoted on a restrictive market although the underlying investments are traded on active markets. The NAV used for determining the fair value of the investments in the Common Collective Trusts have readily determinable fair values. Accordingly, such fund values are categorized as Level 1.


•	Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. The fair value of these investments are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences.


•	Level 3 – Unobservable inputs using data that is not corroborated by market data.

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The fair value of the Company’s Retirement Plan assets at December 31, 2017 and 2016 , and the level within the three levels of the fair value hierarchy defined by the FASB guidance on fair value measurements are presented in the table below (in thousands):



Description of Securities	Fair Value as of December 31, 2017		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Cash and Cash Equivalents	$	1,582	$	1,582	$	—	$	—
Common Collective Trusts (a)
Equity funds	158,684		158,684		—		—
Fixed income funds	124,491		124,491		—		—
Real estate funds	15,779		15,779		—		—
Total Common Collective Trusts	298,954		298,954		—		—
Limited Partnership Interest in Real Estate (b)(c)	3,853
Total Plan Investments	$	304,389	$	300,536	$	—	$	—



Description of Securities	Fair Value as of December 31, 2016		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Cash and Cash Equivalents	$	932	$	932	$	—	$	—
Common Collective Trusts (a)
Equity funds	144,081		144,081		—		—
Fixed income funds	109,356		109,356		—		—
Real estate funds	8,406		8,406		—		—
Total Common Collective Trusts	261,843		261,843		—		—
Limited Partnership Interest in Real Estate (b)(c)	6,991
Total Plan Investments	$	269,766	$	262,775	$	—	$	—

_____________________


(a)	The Common Collective Trusts are invested in equity and fixed income securities, or a combination thereof. The investment objective of each fund is to produce returns in excess of, or commensurate with, its predefined index.

(b)

This investment is a commercial real estate partnership that purchases land, develops limited infrastructure, and sells it for commercial development. The Company was restricted from selling its partnership interest during the life of the partnership, which spanned 7 years. Return on investment is realized as land is sold. The fair value of the limited partnership interest in real estate is based on the NAV of the partnership which reflects the appraised value of the land. The partnership term expired on June 30, 2016 . Upon expiration, dissolution of the partnership commenced and, as a result, the general partner of the partnership is attempting to sell the remaining inventory as soon as possible at the highest pricing possible.

(c)

In the first quarter of 2016, the Company implemented ASU 2015-07, Fair Value Measurement (Topic 820) which eliminates the requirement to categorize investments in the fair value hierarchy if the fair value is measured at NAV per share (or its equivalent) using the practical expedient in the FASB’s fair value measurement gui dance . 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.

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The table below reflects the changes in the fair value of investments in the real estate limited partnership during the period (in thousands):



	Fair Value of Investments in Real Estate
Balances at December 31, 2015	$	8,588
Sale of land	(775		)
Unrealized loss in fair value	(822		)
Balances at December 31, 2016	6,991
Sale of land	(2,687		)
Unrealized loss in fair value	(451		)
Balances at December 31, 2017	$	3,853

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 twelve month periods ending December 31, 2017 and 2016 . There were no purchases, issuances, and settlements related to the assets in the Level 3 fair value measurement category during the twelve month periods ending December 31, 2017 and 2016 .

The Company and the fiduciaries responsible for the Retirement Plan adhere to the traditional capital market pricing theory which maintains that over the long term, the risk of owning equities should be rewarded with a greater return than available from fixed income investments. The Company and the fiduciaries responsible for the Retirement Plan seek to minimize the risk of owning equity securities by investing in funds that pursue risk minimization strategies and by diversifying its investments to limit its risks during falling markets. The investment manager has full discretionary authority to direct the investment of plan assets held in trust within the guidelines prescribed by the Company and the fiduciaries responsible for the Retirement Plan through the plan’s investment policy statement including the ability to hold cash equivalents. The investment guidelines of the investment policy statement are in accordance with the Employee Retirement Income Security Act of 1974 ("ERISA") and Department of Labor ("DOL") regulations.

The Company contributes at least the minimum funding amounts required by the IRS for the Retirement Plan, as actuarially calculated.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):



	Retirement Income Plan		Non-Qualified Retirement Plans
2018	$	17,166	$	2,154
2019	17,656		2,032
2020	17,938		1,975
2021	18,612		1,926
2022	19,247		1,876
2023-2027	105,915		8,754

401(k) Defined Contribution Plans

The Company sponsors 401(k) defined contribution plans covering substantially all employees. The Company provides a 50 percent matching contribution up to 6 percent of the employee’s compensation for employees who are enrolled in the final average pay pension benefit of the Retirement Plan and a 100 percent matching contribution up to 6 percent of the employee's compensation for employees who are enrolled in the cash balance pension benefit of the Retirement Plan, subject to certain other limits and exclusions. Annual matching contributions made to the savings plans for the years 2017 , 2016 and 2015 were $4.4 million , $4.1 million , and $3.9 million , respectively.



	2017		2016 (a)				2015
Discount rate:			January 1 - September 30		October 1 - December 31
Benefit obligation	4.37	%	4.59	%	3.75	%	4.1	%
Service cost	4.59	%	4.91	%	4.03	%	4.1	%
Interest cost	3.76	%	3.86	%	3.15	%	4.1	%
Expected long-term return on plan assets	4.875	%	4.875%				5.2	%
Health care cost trend rates:
Initial
Pre-65 medical	6.5	%	7.0%				7.25	%
Post-65 medical	4.5	%	7.0%				7.25	%
Pre-65 drug	7.5	%	7.0%				7.25	%
Post-65 drug	10.5	%	7.0%				7.25	%
Ultimate	4.5	%	4.5%				4.5	%
Year ultimate reached (b)	2026		2026				2026


(a)	The institutional funds are invested in equity or fixed income securities, or a combination thereof. The investment objective of each fund is to produce returns in excess of, or commensurate with, its predefined index.



	Fair Value of Investments in Real Estate
Balance at December 31, 2015	$	1,610
Sale of land	(145		)
Unrealized loss in fair value	(154		)
Balance at December 31, 2016	1,311
Sale of land	(504		)
Unrealized loss in fair value	(85		)
Balance at December 31, 2017	$	722



2018	$	2,260
2019	2,404
2020	2,607
2021	2,771
2022	2,937
2023-2027	16,440


(1)	In September 2017, the $33.3 million 2012 Series A 1.875% Pollution Control Bonds which were subject to mandatory tender for purchase were redeemed and retired utilizing funds borrowed under the RCF.



	December 31, 2017
	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	$	4,700	$	(46	)	$	10,099	$	(165	)	$	14,799	$	(211	)
U.S. Government Bonds	28,866		(416		)	18,186		(969		)	47,052		(1,385		)
Municipal Debt Obligations	4,290		(73		)	9,736		(742		)	14,026		(815		)
Corporate Debt Obligations	10,685		(107		)	4,475		(331		)	15,160		(438		)
Total Debt Securities	48,541		(642		)	42,496		(2,207		)	91,037		(2,849		)
Common Stock	962		(210		)	—		—			962		(210		)
Total Temporarily Impaired Securities	$	49,503	$	(852	)	$	42,496	$	(2,207	)	$	91,999	$	(3,059	)



	Total		2018		2019 through 2022		2023 through 2027		2028 and Beyond
Federal Agency Mortgage Backed Securities	$	20,732	$	—	$	18	$	280	$	20,434
U.S. Government Bonds	58,181		5,251		27,181		11,663		14,086
Municipal Debt Obligations	16,584		511		7,690		7,064		1,319
Corporate Debt Obligations	34,674		215		16,946		7,601		9,912


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


•	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.


(a)	The Company sold its interest in Four Corners in July 2016. The sales proceeds were reduced by the settlement of other obligations between the Company and APS and its affiliate, 4C Acquisition, LLC. See Part II, Item 8, Financial Statements and Supplementary Data, Note E.



	2017 Quarters									2016 Quarters
	4th (2)		3rd		2nd		1st			4th		3rd (3)		2nd		1st
					(In thousands except for share data)
Operating revenues (1)	$	196,149	$	297,470	$	251,843	$	171,335		$	188,037	$	323,225	$	217,865	$	157,809
Operating income (loss)	20,299		105,737		65,939		6,279			20,470		129,857		44,697		(163		)
Net income (loss)	6,500		59,684		36,066		(3,989		)	5,656		74,636		22,284		(5,808		)
Basic earnings per share:
Net income (loss)	0.16		1.47		0.89		(0.10		)	0.14		1.84		0.55		(0.14		)
Diluted earnings per share:
Net income (loss)	0.16		1.47		0.89		(0.10		)	0.14		1.84		0.55		(0.14		)
Dividends declared per share of common stock	0.335		0.335		0.335		0.310			0.310		0.310		0.310		0.295


(1)	Operating revenues are seasonal in nature, with the peak sales periods generally occurring during the summer months. Comparisons among quarters of a year may not represent overall trends and changes in operations.


Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure


Item 10.	Directors, Executive Officers of the Registrant and Corporate Governance



Name	Age	Current Position and Business Experience
Mary E. Kipp	50	President and Chief Executive Officer since May 2017; Chief Executive Officer from December 2015 to May 2017; President from September 2014 to December 2015; Senior Vice President, General Counsel and Chief Compliance Officer from June 2010 to September 2014.
Nathan T. Hirschi	54	Senior Vice President and Chief Financial Officer since October 2013; Vice President and Controller from March 2010 to October 2013.
Steven T. Buraczyk	50	Senior Vice President of Operations since October 2013; Vice President of Regulatory Affairs from April 2013 to October 2013; Vice President of Power Marketing and Fuels and Resource and Delivery Planning from August 2012 to April 2013; Vice President of System Operations and Planning from January 2011 to August 2012; Vice President of Power Marketing and Fuels from July 2008 to January 2011.
Rocky R. Miracle	65	Senior Vice President of Corporate Development and Chief Compliance Officer since May 2017; Senior Vice President Corporate Services and Chief Compliance Officer from December 2015 to May 2017; Senior Vice President of Corporate Planning & Development and Chief Compliance Officer from September 2014 to December 2015; Senior Vice President of Corporate Planning and Development from August 2009 to September 2014.
William A. Stiller	66	Senior Vice President of Public & Customer Affairs and Chief Human Resources Officer since December 2015; Senior Vice President of Human Resources and Customer Care from October 2013 to December 2015; Vice President and Chief Human Resources Officer from January 2013 to October 2013; Independent Human Resources consultant from 2005 to 2013.
Adrian J. Rodriguez	39	Senior Vice President, General Counsel and Assistant Secretary since September 2017; Vice President, General Counsel and Assistant Secretary from May 2017 to September 2017; Principal Attorney from July 2016 to May 2017; Senior Attorney from November 2014 to July 2016; Staff Attorney from April 2013 to November 2014.
Russell G. Gibson	65	Vice President and Controller since September 2014; Chief Financial Officer and Vice President for ReadyOne Industries, Inc. from June 2006 to September 2014.


Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters



Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans
approved by security holders	—	$	—	1,342,428
Equity compensation plans
not approved by security holders	—	—		—
Total	—	$	—	1,342,428


Item 13.	Certain Relationships and Related Transactions, and Director Independence



		Page
1.	Financial Statements:

	See Index to Financial Statements	51

2.	Financial Statement Schedules:

	All schedules are omitted as the required information is not applicable or is included in the financial statements or related notes thereto.

3.	Exhibits



Exhibit Number			Title
Exhibit 3 –		Articles of Incorporation and Bylaws:
	3.01	–	Restated Articles of Incorporation of the Company, dated February 7, 1996 and effective February 12, 1996. (Exhibit 3.1 to the Company’s Registration Statement on Form S-3, filed on September 26, 2017)
	3.02	–	Amended and Restated Bylaws of the Company, dated July 27, 2017. (Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on July 27, 2017)
Exhibit 4 –		Instruments Defining the Rights of Security Holders, including Indentures:
	4.01	–	General Mortgage Indenture and Deed of Trust, dated as of February 1, 1996. (Exhibit 4.1 to the Company’s Registration Statement on Form S-3, filed on September 26, 2017)
4.01-01		–	First Supplemental Indenture, dated February 1, 1996, to Exhibit 4.01. (included in Exhibit 4.01)
4.01-02		–	Second Supplemental Indenture, dated as of August 19, 1997, to Exhibit 4.01. (included in Exhibit 4.01)
4.01-03		–	Third Supplemental Indenture, dated as of January 29, 1999, to Exhibit 4.01. (included in Exhibit 4.01)
4.01-04		–	Fourth Supplemental Indenture, dated as of January 25, 2002, to Exhibit 4.01. (included in Exhibit 4.01)
4.01-05		–	Fifth Supplemental Indenture, dated as of December 17, 2004, to Exhibit 4.01. (included in Exhibit 4.01)
4.01-06		–	Sixth Supplemental Indenture to Exhibit 4.01, dated as of May 5, 2005 to General Mortgage Indenture and Deed of Trust dated as of February 1, 1996 between the Company and U.S. Bank National Association as trustee. (included in Exhibit 4.01)
4.01-07		–	Seventh Supplemental Indenture to Exhibit 4.01, dated as of April 11, 2006 to General Mortgage Indenture and Deed of Trust dated as of February 1, 1996 between the Company and U.S. Bank National Association as trustee. (included in Exhibit 4.01)
4.01-08		–	Eighth Supplemental Indenture to Exhibit 4.01, dated as of July 7, 2015 to General Mortgage Indenture and Deed of Trust dated as of February 1, 1996 between the Company and U.S. Bank National Association as trustee. (included in Exhibit 4.01)
4.02		–	Indenture of Trust between Maricopa County, Arizona Pollution Control Corporation and Union Bank of California, N.A. as Trustee dated as of August 1, 2012 relating to $59,235,000 Maricopa County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds 2012 Series A (El Paso Electric Company Palo Verde Project). (Exhibit 4.05 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
4.03		–	Loan Agreement dated August 1, 2012 between Maricopa County, Arizona Pollution Control Corporation and El Paso Electric Company relating to the Pollution Control Bonds referred to in Exhibit 4.02. (Exhibit 4.06 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
4.04		–	Indenture of Trust between Maricopa County, Arizona Pollution Control Corporation and Union Bank, N.A. as Trustee dated as of March 1, 2009 relating to $63,500,000 Maricopa County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds 2009 Series A (El Paso Electric Company Palo Verde Project). (Exhibit 4.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
4.05		–	Loan Agreement dated March 1, 2009 between Maricopa County, Arizona Pollution Control Corporation and El Paso Electric Company relating to the Pollution Control Bonds referred to in Exhibit 4.04. (Exhibit 4.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
4.06		–	Indenture of Trust between Maricopa County, Arizona Pollution Control Corporation and Union Bank, N.A. as Trustee dated as of March 1, 2009 relating to $37,100,000 Maricopa County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds 2009 Series B (El Paso Electric Company Palo Verde Project). (Exhibit 4.03 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
4.07		–	Loan Agreement dated March 1, 2009 between Maricopa County, Arizona Pollution Control Corporation and El Paso Electric Company relating to the Pollution Control Bonds referred to in Exhibit 4.06. (Exhibit 4.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
4.08		–	Amended and Restated Installment Sale Agreement, dated August 1, 2012, between El Paso Electric Company and the City of Farmington, New Mexico, relating to the Pollution Control Bonds referred to in Exhibit 4.09. (Exhibit 4.04 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
	4.09	–	Debt Securities Indenture, dated as of May 1, 2005. (Exhibit 4.2 to the Company's Registration Statement on Form S-3, filed on September 26, 2017)

Since 1999
(a)

Authorized
Shares

Shares repurchased (b)

Cost, including commission (in thousands)

Total remaining shares available for repurchase at December 31, 2017



Exhibit Number			Title
	4.10	–	First Supplemental Indenture, dated as of May 19, 2008. (Exhibit 4.4 to the Company's Registration Statement on Form S-3, filed on September 26, 2017)
	4.11	–	Securities Resolution No. 1, dated May 11, 2005, relating to the Company's 6.00% Senior Notes due 2035. (Exhibit 4.2 to the Company's Current Report on Form 8-K filed on May 19, 2005)
	4.12	–	Securities Resolution No. 2, dated May 29, 2008, relating to the Company's 7.50% Senior Notes due 2038. (Exhibit 4.1 to the Company's Current Report on Form 8-K filed on June 9, 2008)
	4.13	–	Securities Resolution No. 3, dated December 3, 2012, relating to the Company's 3.30% Senior Notes due 2022. (Exhibit 4.1 to the Company's Current Report on Form 8-K filed on December 6, 2012)
	4.14	–	Securities Resolution No. 4, dated December 1, 2014, relating to the Company's 5.000% Senior Notes due 2044. (Exhibit 4.1 to the Company's Current Report on Form 8-K filed on December 2, 2014)
	4.15	–	Securities Resolution No. 5, dated March 24, 2016, relating to the Company's 5.000% Senior Notes due 2044. (Exhibit 4.1 to the Company's Current Report on Form 8-K filed on March 24, 2016)
Exhibit 10 –		Material Contracts:
*10.01		–	Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, between Arizona Public Service Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Tucson Gas & Electric Company and the Company, describing the respective participation ownerships of the various utilities having undivided interests in the Arizona Nuclear Power Project and in general terms defining the respective ownerships, rights, obligations, major construction and operating arrangements of the Parties. (Exhibit 10.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
*10.01-01		–	Amendment No. 1, dated January 1, 1974, to Exhibit 10.01 (Exhibit 10.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
*10.01-02		–	Amendment No. 2, dated August 28, 1975, to Exhibit 10.01 (Exhibit 10.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
*10.01-03		–	Amendment No. 3, dated July 22, 1976, to Exhibit 10.01 (Exhibit 10.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
*10.01-04		–	Amendment No. 4, dated December 15, 1977, to Exhibit 10.01 (Exhibit 10.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
*10.01-05		–	Amendment No. 5, dated December 5, 1979, to Exhibit 10.01 (Exhibit 10.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
*10.01-06		–	Amendment No. 6, dated October 16, 1981, to Exhibit 10.01 (Exhibit 10.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
*10.01-07		–	Amendment No. 7, dated April 1, 1982, to Exhibit 10.01 (Exhibit 10.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
*10.01-08		–	Amendment No. 8, dated September 12, 1983, to Exhibit 10.01 (Exhibit 10.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
*10.01-09		–	Amendment No. 9, dated June 12, 1984, to Exhibit 10.01 (Exhibit 10.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
*10.01-10		–	Amendment No. 10, dated November 21, 1985, to Exhibit 10.01 (Exhibit 10.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
*10.01-11		–	Amendment No. 11, dated January 10, 1987, to Exhibit 10.01 (Exhibit 10.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
*10.01-12		–	Amendment No. 12, dated August 5, 1988, to Exhibit 10.01 (Exhibit 10.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
*10.01-13		–	Amendment No. 13, dated June 15, 1991, to Exhibit 10.01 (Exhibit 10.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.01-14		–	Amendment No. 14, dated June 20, 2000, to Exhibit 10.01. (Exhibit 10.05-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002)
10.01-15		–	Amendment No. 15, dated January 13, 2011, to Exhibit 10.01. (Exhibit 10.07 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
10.01-16		–	Amendment No. 16, dated April 28, 2014, to Exhibit 10.01. (Exhibit 10.06 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014)



Exhibit Number		Title
*10.02	–	ANPP Valley Transmission System Participation Agreement, dated August 20, 1981, and Amendments No. 1 and 2 thereto. APS Contract No. 2253-419.00. (Exhibit 10.06 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
*10.03	–	Arizona Nuclear Power Project High Voltage Switchyard Participation Agreement, dated August 20, 1981. APS Contract No. 2252-419.00. (Exhibit 20.14 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1981)
*10.03-01	–	Amendment No. 1, dated November 20, 1986, to Exhibit 10.03. (Exhibit 10.11-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1986)
*10.04	–	Firm Palo Verde Nuclear Generating Station Transmission Service Agreement, between Salt River Project Agricultural Improvement and Power District and the Company, dated October 18, 1983. (Exhibit 19.12 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1983)
*10.05	–	Interconnection Agreement, as amended, dated December 8, 1981, between the Company and Southwestern Public Service Company, and Service Schedules A-C and F thereto. (Exhibit 10.13 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
*10.06	–	Amrad to Artesia 345 KV Transmission System and DC Terminal Participation Agreement, dated December 8, 1981, between the Company and Texas-New Mexico Power Company, and the First through Third Supplemental Agreements thereto. (Exhibit 10.14 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
#10.07	–	El Paso Electric Company Excess Benefit Plan, dated as of April 1, 2014 (Exhibit 10.07 to the Company's Annual Report on Form 10-K for the year ended December 31, 2016)
*10.08	–	Interconnection Agreement and Amendment No. 1, dated July 19, 1966, between the Company and Public Service Company of New Mexico. (Exhibit 19.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1982)
*10.09	–	Southwest New Mexico Transmission Project Participation Agreement, dated April 11, 1977, between Public Service Company of New Mexico, Community Public Service Company and the Company, and Amendments 1 through 5 thereto. (Exhibit 10.16 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
*10.09-01	–	Amendment No. 6, dated as of June 17, 1999, to Exhibit 10.09. (Exhibit 10.09 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999)
*10.10	–	Tucson-El Paso Power Exchange and Transmission Agreement, dated April 19, 1982, between Tucson Electric Power Company and the Company. (Exhibit 19.26 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1982)
10.10-01	–	Settlement Agreement between TEP and the Company, dated April 26, 2011, to Exhibit 10.10. (Exhibit 10.14-01 to the Company's Annual Report on Form 10-K for the year ended December 31, 2011)
10.11	–	Southwest Reserve Sharing Group Participation Agreement, dated January 1, 1998, between the Company, Arizona Electric Power Cooperative, Arizona Public Service Company, City of Farmington, Los Alamos County, Nevada Power Company, Plains Electric G&T Cooperative, Inc., Public Service Company of New Mexico, Tucson Electric Power and Western Area Power Administration. (Exhibit 10.18 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997)
*10.12	–	Arizona Nuclear Power Project Transmission Project Westwing Switchyard Amended Interconnection Agreement, dated August 14, 1986, between The United States of America; Arizona Public Service Company; Department of Water and Power of the City of Los Angeles; Nevada Power Company; Public Service Company of New Mexico; Salt River Project Agricultural Improvement and Power District; Tucson Electric Power Company; and the Company. (Exhibit 10.72 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1986)
#10.13	–	Form of Indemnity Agreement, between the Company and its directors and officers. (Exhibit 10.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 2012)
*10.14	–	Interchange Agreement, executed April 14, 1982, between Comisión Federal de Electricidad and the Company. (Exhibit 19.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1991)
*10.15	–	Trust Agreement, dated as of February 12, 1996, between the Company and Texas Commerce Bank National Association, as Trustee of the Rio Grande Resources Trust II. (Exhibit 10.34 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.16	–	Note Purchase Agreement, dated as of August 17, 2010, between El Paso Electric Company, Rio Grande Resources Trust II and the purchasers named therein. (Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed on August 18, 2010)



Exhibit Number		Title
10.17	–	Decommissioning Trust Agreement, dated as of April 1, 2006, between the Company and Wells Fargo Bank, N.A., as decommissioning trustee for Palo Verde Unit 1. (Exhibit 10.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006)
10.18	–	Decommissioning Trust Agreement, dated as of April 1, 2006, between the Company and Wells Fargo Bank, N.A., as decommissioning trustee for Palo Verde Unit 2. (Exhibit 10.03 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006)
10.19	–	Decommissioning Trust Agreement, dated as of April 1, 2006, between the Company and Wells Fargo Bank, N.A., as decommissioning trustee for Palo Verde Unit 3. (Exhibit 10.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006)
10.20	–	Second Amended and Restated Credit Agreement dated as of January 14, 2014, among the Company, The Bank of New York Mellon Trust Company, N.A., not in its individual capacity, but solely in its capacity as trustee of the Rio Grande Resources Trust II, the lenders party thereto, JPMorgan Chase Bank, N.A., as administrative agent and issuing bank and Union Bank of California, N.A., as syndication agent. (Exhibit 10.25-03 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2013)
10.20-01	–	Extension and Increase Confirmation to Exhibit 10.20. (Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 10, 2017)
#†10.21	–	Change in Control Agreement between the Company and certain key officers of the Company. (Exhibit 10.26 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014)
10.22	–	Purchase and Sale Agreement between the Company and Arizona Public Service Company, dated February 17, 2015. (Exhibit 10.1 to the Company's Current Report on Form 8-K filed on February 19, 2015)
10.22-01	–	Amendment No. 1, dated April 13, 2015, to Exhibit 10.22. (Exhibit 10.03 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015)
10.22-02	–	Amendment Agreement, dated July 6, 2016, to Exhibit 10.22. (Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on July 7, 2016)
#10.23	–	Form of Directors’ Restricted Stock Award Agreement between the Company and certain directors of the Company. (Exhibit 10.07 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999)
10.24	–	Franchise Agreement, dated July 12, 2005, between the Company and the City of El Paso. (Exhibit 10.05 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015)
10.24-01	–	Amendment No. 1, dated November 16, 2010, to Exhibit 10.24. (Exhibit 10.06 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015)
10.25	–	Settlement Agreement, dated as of February 24, 2000, with the City of Las Cruces. (Exhibit 10.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000)
10.26	–	Franchise Agreement, dated April 3, 2000, between the Company and the City of Las Cruces. (Exhibit 10.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000)
10.27	–	Interconnection Agreement dated as of May 23, 2002, between the Company and the Public Service Company of New Mexico. (Exhibit 10.09 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002)
10.27-01	–	First Amended and Restated Interconnection Agreement, dated October 9, 2003, to Exhibit 10.27. (Exhibit 10.52-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003)
10.28	–	Power Purchase and Sale Agreement, dated as of December 16, 2005, between the Company and Phelps Dodge Energy Services, LLC. (Exhibit 10.42 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005)
10.28-01	–	Letter Agreement, dated October 24, 2016, to Exhibit 10.28. (Exhibit 10.28-08 to the Company's Annual Report on Form 10-K for the year ended December 31, 2016)
10.29	–	Settlement Agreement between the State of Texas and the Company, dated October 17, 2006. (Exhibit 10.08 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006)
#10.30	–	El Paso Electric Company 2007 Long-Term Incentive Plan. (Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed on May 2, 2007)
#10.30-01	–	Amended and Restated 2007 Long-Term Incentive Plan to Exhibit 10.30. (Exhibit 99.1 to the Company's Registration Statement (No. 333-196628) on Form S-8, filed on June 6, 2014)
#10.30-02	–	First Amendment to the Amended and Restated 2007 Long-Term Incentive Plan. (Exhibit 10.1 to the Company's Current Report on Form 8-K filed on February 5, 2018)
#10.31	–	Employment Agreement between the Company and Mary E. Kipp, dated December 15, 2015. (Exhibit 10.50 to the Company's Annual Report on Form 10-K for the year ended December 31, 2015)



Exhibit Number		Title
#10.32	–	Change in Control Agreement between the Company and Mary E. Kipp. (Exhibit 10.01 to the Company’s Current Report on Form 8-K filed on May 26, 2017)
#10.33	–	Long-Term Incentive Award Agreement (For Non-Employee Directors). (Exhibit 10.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017)
#10.34	–	Long-Term Incentive Award Agreement (For Employees). (Exhibit 10.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017)
#10.35	–	Form of Performance Share Award Agreement for outstanding awards between the Company and certain officers of the Company. (Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on February 5, 2018)
#10.36	–	Form of Performance Share Award Agreement between the Company and certain officers of the Company. (Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on February 5, 2018)
#10.37	–	Form of Restricted Stock Award Agreement between the Company and certain officers of the Company. (Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on February 5, 2018)
#10.38	–	Form of Restricted Stock Award Agreement between the Company and non-employee directors of the Company. (Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on February 5, 2018)

Exhibit 12 –	Computation of Ratios:
*12.01	–	Computation of Ratios of Earnings to Fixed Charges
Exhibit 23 –	Consent of Experts:
*23.01	–	Consent of KPMG LLP (set forth on page 124 of this report)
Exhibit 24 –	Power of Attorney:
*24.01	–	Power of Attorney (set forth on page 122 of this report)
*24.02	–	Certified copy of resolution authorizing signatures pursuant to Power of Attorney
Exhibit 31 and 32 –	Certifications:
*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
Exhibit 99 –	Additional Exhibits:
*99.01	–	Agreed Order, entered August 30, 1995, by the Public Utility Commission of Texas. (Exhibit 99.31 to the Company's Registration Statement No. 33-99744 on Form S-1)
99.02	–	Final Order, entered September 24, 1998, by the New Mexico Public Utility Commission. (Exhibit 99.31 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1998)
99.03	–	Final Order, entered June 8, 1999, by the Public Utility Commission of Texas. (Exhibit 99.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999)
99.04	–	Final Order, entered January 8, 2002, by the New Mexico Public Utility Commission. (Exhibit 99.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2001)
Exhibit 101 –	XBRL – Related Documents:
*101.INS	–	XBRL Instance Linkbase 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



	*		Filed herewith.
	#		Management contracts or compensatory plans or arrangements required to be identified by Item 15(a)(3) of Form 10-K.
	†		Agreements substantially identical in all material respects to this exhibit have been entered into between the Company and its Section 16 officers, except for the president and chief executive officer, which agreement is separately filed herewith.
	††		Confidential treatment has been requested and received for the redacted portions of these Exhibits. The copies filed omit the information subject to the confidentiality request. Omissions are designated as "****." A complete version of these Exhibits has been filed separately with the Securities and Exchange Commission.



EL PASO ELECTRIC COMPANY

By:	/s/ MARY E. KIPP
	Mary E. Kipp
	President and Chief Executive Officer (Principal Executive Officer)



Signature	Title	Date

/s/ MARY E. KIPP	President and Chief Executive Officer and Director (Principal Executive Officer)	February 28, 2018
(Mary E. Kipp)

/s/ NATHAN T. HIRSCHI	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	February 28, 2018
(Nathan T. Hirschi)

/s/ RUSSELL G. GIBSON	Vice President and Controller (Principal Accounting Officer)	February 28, 2018
(Russell G. Gibson)

/s/ CATHERINE A. ALLEN	Director	February 28, 2018
(Catherine A. Allen)

/s/ PAUL M. BARBAS	Director	February 28, 2018
(Paul M. Barbas)

/s/ JAMES W. CICCONI	Director	February 28, 2018
(James W. Cicconi)

/s/ EDWARD ESCUDERO	Director	February 28, 2018
(Edward Escudero)

/s/ JAMES W. HARRIS	Director	February 28, 2018
(James W. Harris)

/s/ WOODLEY L. HUNT	Director	February 28, 2018
(Woodley L. Hunt)

/s/ RAYMOND PALACIOS JR	Director	February 28, 2018
(Raymond Palacios Jr.)

/s/ ERIC B. SIEGEL	Director	February 28, 2018
(Eric B. Siegel)

/s/ STEPHEN N. WERTHEIMER	Director	February 28, 2018
(Stephen N. Wertheimer)

/s/ CHARLES A. YAMARONE	Director	February 28, 2018
(Charles A. Yamarone)