10-K

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, 2016

OR

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 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, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting 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

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, 2016, the aggregate market value of the voting stock held by non-affiliates of the registrant was $1,883,999,218 (based on the closing price as quoted on the New York Stock Exchange on that date).

As of January 31, 2017, there were 40,557,679 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 2017 annual meeting of its shareholders are incorporated by reference into Part III of this report.

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
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
MW	Megawatt(s)
MWh	Megawatt-hour(s)
NMPRC	New Mexico Public Regulation Commission
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
NRC	Nuclear Regulatory Commission
Palo Verde	Palo Verde Nuclear 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
TEP	Tucson Electric Power Company
White Sands	White Sands Missile Range

( i)

TABLE OF CONTENTS

Item	Description	Page
	PART I
1	Business	1
1A	Risk Factors	17
1B	Unresolved Staff Comments	23
2	Properties	23
3	Legal Proceedings	23
4	Mine Safety Disclosures	23
	PART II
5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	24
6	Selected Financial Data	26
7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
7A	Quantitative and Qualitative Disclosures About Market Risk	48
8	Financial Statements and Supplementary Data	50
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	109
9A	Controls and Procedures	109
9B	Other Information	109
	PART III
10	Directors, Executive Officers and Corporate Governance	110
11	Executive Compensation	111
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	111
13	Certain Relationships and Related Transactions, and Director Independence	111
14	Principal Accounting Fees and Services	111
	PART IV
15	Exhibits and Financial Statement Schedules	112

( ii)

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,

• possible corporate restructurings, acquisitions and dispositions,

• compliance with debt and other restrictive covenants,

• interest rates and dividends,

• environmental matters,

• nuclear operations, and

• the overall economy of our service area.

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

• actions of 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 Nuclear Generating Station ("Palo Verde"), including costs to comply with any new or expanded regulatory or environmental requirements,

• reductions in output at generation plants operated by 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,

• 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,

( iii)

• 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,

• electric utility deregulation or re-regulation,

• regulated and competitive markets,

• ongoing municipal, state and federal activities,

• cuts in military spending or shutdowns of the federal government that reduce demand for 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 and capital market conditions,

• changes in accounting requirements and other accounting matters,

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

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

• the impact of lawsuits filed against the Company,

• the impact of changes in interest rates,

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

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

• possible income tax and interest payments as a result of audit adjustments proposed by the Internal Revenue Service ("IRS") or state taxing authorities,

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

• 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 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.

( iv)

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 capability of approximately 2,080 MW. For the year ended December 31, 2016, the Company’s energy sources consisted of approximately 49% nuclear fuel, 34% natural gas, 2% coal, 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, 2016, the Company had power purchase agreements for 107 MW from solar photovoltaic generation facilities. (See "Energy Sources – Purchased Power").

The Company serves approximately 411,100 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, 2016). 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, 2017, 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, 2016, the Company’s net dependable generating capability of approximately 2,080 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	1	100	%	Culberson/El Paso Counties, Texas; Dona Ana County, New Mexico
Total		2,080

1

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 threePalo 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 2013, the Palo Verde Participants approved the 2013 Palo Verde decommissioning study (the "2013 Study"), which estimated that the Company must fund approximately $380.7 million (stated in 2013 dollars) to cover its share of decommissioning costs. At December 31, 2016, the Company's decommissioning trust fund had a balance of $255.7 million. Although the 2013 Study was based on the latest available information, there can be no assurance that decommissioning cost estimates attributable to the Company will not increase in the future or that regulatory requirements will not change. A 2016 Palo Verde decommissioning study is underway and is expected to be finalized in the second quarter of 2017 at which time the Company will record its effects.

• Spent Fuel Storage. 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 and payment of $57.4 millionby the DOE to the Palo Verde Participants for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. On October 8, 2014, the Company received approximately$9.1 million, representing its share of the award, of which $7.9 million was refunded to customers through the applicable fuel adjustment clauses. On October 31, 2014, APS, acting on behalf of itself and the Palo Verde Participants, submitted to the government an additional request for reimbursement of spent nuclear fuel storage costs for the period July 1, 2011 through June 30, 2014. The accepted claim amount was$42.0 million. On June 1, 2015, the Company received approximately$6.6 million, representing its share of the award, of which $5.8 million was credited to customers through the applicable fuel adjustment clauses in March 2015. After June 2015, APS will file annual claims for the period July 1 of the then-previous year to June 30 of the then-current year. On November 2, 2015, APS filed a $12.0 million claim for the period July 1, 2014 through June 30, 2015. In February 2016, the DOE notified APS of the approval of the claim. Funds related to this claim were received in the first quarter of 2016. The Company's share of this claim is approximately$1.9 million, of which $1.6 million was credited to customers through the applicable fuel adjustment clauses in March 2016. On October 31, 2016 APS filed an $11.3 million claim for the period July 1, 2015 through June 30, 2016. The Company's share of this claim is approximately$1.8 million. On February 1, 2017, the DOE notified APS of the approval of the claim. Any reimbursement is anticipated to be received in the second quarter of 2017, and the majority of the award received by the Company will be credited to customers through 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, and the proceeding has not been conclusively decided by the NRC or the courts. 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 construction authorization

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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. 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. The continued storage rule 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 12, 2014, APS was notified by the DOE that, effective May 16, 2014, the one-mill fee would be suspended. Electricity generated at Palo Verde and sold prior to May 16, 2014 remained subject 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 $125.0 million (the Company's share is $19.7 million) on capital enhancements related to these requirements as of December 31, 2016.

• 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 February 17, 2015, the Company and APS entered into an asset purchase agreement (the "Purchase and Sale Agreement") providing for the sale of the Company’s interests in Four Corners to APS. Four Corners continued to provide energy to serve the Company's native load up to the closing date of the sale onJuly 6, 2016. Also on July 6, 2016, prior to the

4

closing of the transaction, the Company and APS entered into an amendment to the Purchase and Sale Agreement pursuant to which APS assigned its right, title and interest in the Purchase and Sale Agreement to its affiliate 4C Acquisition, LLC ("APS's affiliate"), and Pinnacle West Capital Corporation, the parent company of APS and APS's affiliate ("Pinnacle West"), guaranteed APS's affiliate's obligations under the Purchase and Sale Agreement. The sales price was$32.0 million, which was based on the net book value as defined in the Purchase and Sale Agreement. The sales price was adjusted downward by$7.0 millionand$19.5 million, respectively, to reflect the assumption by APS's affiliate of the Company's obligation to pay for future plant decommissioning and mine reclamation expenses. The sales price was also adjusted downward by approximately$1.3 millionfor estimated closing adjustments and other assets and liabilities assumed by APS's affiliate. At the closing, the Company received approximately$4.2 millionin cash, subject to post-closing adjustments. No significant gain or loss was recorded after the closing date. 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.

Wind and Solar Photovoltaic Facilities

The Company’s Hueco Mountain Wind Ranch consisted of two wind turbines with a total capacity of 1.32 MW. The two wind turbines were decommissioned in June 2016. The Company also owns six 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 sources at Palo Verde and, prior to July 6, 2016, Four Corners, 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.

5

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.

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.

Cross State Air Pollution Rule. The U.S. Environmental Protection Agency (the "EPA") promulgated the Cross-State Air Pollution Rule ("CSAPR") in August 2011, which involves requirements to limit emissions of NOx and SO2 from certain of the Company's power plants in Texas and/or purchase allowances representing other parties' emissions reductions. CSAPR was intended to replace the EPA's 2005 Clean Air Interstate Rule ("CAIR"). The U.S. Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") vacated CSAPR in August 2012 and allowed CAIR to stand until the EPA issued a proper replacement. On April 29, 2014, the U.S. Supreme Court reversed and upheld CSAPR, remanding certain portions of CSAPR to the D.C. Circuit for further consideration. On July 28, 2015, the D.C. Circuit ruled that the EPA's emissions budgets for 13 states, including Texas, are invalid but left the rule in place on remand. On October 26, 2016, the EPA published its final CSAPR Update Rule with an effective date of December 27, 2016. While we are unable to determine the full impact of this rule at this time, the Company believes it is currently positioned to comply with CSAPR.

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 NAAQS for fine PM. On October 1, 2015, following on its November 2014 proposal, EPA released a final rule tightening the primary and secondary NAAQS for ground-level ozone from its 2008 standard levels of 75 parts per billion ("ppb") to 70 ppb. Ozone is the main component of smog. While not directly emitted into the air, it forms from precursors, including NOx and volatile organic compounds, in combination with sunlight. The EPA is scheduled to make attainment/nonattainment designations for the revised ozone standards by October 1, 2017. While it is currently unknown how the areas in which we operate will be designated, for nonattainment areas classified as "Moderate" and above, states, and any tribes that choose to do so, are expected to be required to complete development of implementation plans in the 2020-2021 timeframe. Most nonattainment areas are expected to have until 2020 or 2023 to meet the primary (health) standard, with the exact attainment date varying based on the ozone level in the area. The Company continues to evaluate what impact these final and proposed NAAQS could have on its operations. If the Company is required to install additional equipment to control emissions at its facilities, the NAAQS, individually or in the aggregate, could have a material impact on its operations and financial results.

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. As the Company no longer owns any coal-fired generation as a result of the sale, it believes it is not responsible for a significant portion of the compliance or ongoing operational costs associated with the Mercury and Air Toxics Standards ("MATS"), the Coal Combustion Residue ("CCR") Rule, or the revised Wastewater Effluent Limitation Guidelines ("ELG"), which had been identified in previous filings that the Company has made with the SEC. 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. Similar to other former owners of real property, the Company may be subject to certain future claims under environmental laws and regulations as former owner of Four Corners. The extent of such claims, if any, cannot be predicted with certainty.

Climate Change. In recent years, there has been increasing public debate regarding the potential impact on global climate change. There has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of GHG and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Most recently, in April 2016

6

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.

The U.S. federal government has either considered, proposed and/or finalized legislation or regulations limiting GHG emissions, including carbon dioxide. In particular, the U.S. Congress has considered legislation to restrict or regulate GHG emissions. In the past few years, the EPA began using the CAA to regulate carbon dioxide and other GHG emissions, such as the 2009 GHG Reporting Rule and the EPA’s sulfur hexafluoride ("SF6") reporting rule, both of which apply to the Company, as well as the EPA’s 2010 actions to impose permitting requirements on new and modified sources of GHG emissions. In October 2015, the EPA published a final rule establishing new source performance standards ("NSPS") limiting CO2 emissions from new, modified and reconstructed electric generating units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate CO2 emissions from existing power plants, as well as a proposed "federal plan" to address CO2 emissions from affected units in those states that do not submit an approvable compliance plan. The standards for existing plants are known as the Clean Power Plan ("CPP"), under which rule interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates by 2030. Legal challenges to the CPP have been filed by groups of states and industry members. On February 9, 2016, the U.S. Supreme Court issued a decision to stay the rule until legal issues are resolved. On September 27, 2016, the case against the CPP was heard in the United States Court of Appeals for the District of Columbia Circuit. We cannot at this time determine the impact of the CPP and related rules and legal challenges may have on our financial position, results of operations or cash flows.

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, some studies suggest that 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 millionfor environmental mitigation projects. At December 31, 2016, the Company has accrued its remaining unpaid share of approximately$0.2 millionrelated to this matter.

Construction Program

Utility construction expenditures reflected in the following table consist primarily of local generation, expanding and updating the transmission and distribution systems, and the cost of capital improvements and replacements at Palo Verde. 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.

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The Company’s estimated cash construction costs for 2017 through 2021 are approximately $1.1 billion. Actual costs may vary from the construction program estimates shown. Such estimates are reviewed and updated periodically to reflect changed conditions.

By Year (1)(2) (estimates in millions)			By Function (estimates in millions)
2017	$	215	Production (1)(2)	$	492
2018	185		Transmission	131
2019	203		Distribution	349
2020	240		General	113
2021	242
Total	$	1,085	Total	$	1,085

__________________________

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

(2) Estimated production costs consist of:

a. $273 million for new generating capacity, including:

i. $253 million of construction costs from 2018 through 2021 for a 320 MW generating resource scheduled for completion in 2023.

ii. $20 million for two utility-scale solar energy generating facilities which would have a combined maximum capacity of up to 8 MW.

b. $219 million of other generation costs, including $191 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,
	2016		2015		2014
Power Source	(percentage of total kWh energy mix)
Nuclear	49	%	47	%	47	%
Natural gas	34	%	34	%	35	%
Coal	2	%	6	%	5	%
Purchased power	15	%	13	%	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 and conversion services through 2018 and 45% of its requirements in 2019-2025. The participants have also contracted for 100% of Palo Verde's enrichment services through 2020, 20% of its enrichment services for 2021-2026 and all of Palo Verde's 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. RGRT has $95 million aggregate principal amount borrowed in the form of senior notes, of which $50 million will mature in August 2017. The Company expects to repay the $50 million of senior notes upon maturity with borrowings under the Company’s revolving credit facility (the "RCF") or refinance them. The 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 2016, 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 2017. 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 2017.

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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.

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 2016 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,
	2016		2015			2014
Operating revenues (in thousands):
Non-fuel base revenues:
Retail:
Residential	$	278,774	$	246,265		$	234,371
Commercial and industrial, small	194,942		187,436			185,388
Commercial and industrial, large	39,070		40,411			39,239
Sales to public authorities	96,881		91,244			92,066
Total retail base revenues	609,667		565,356			551,064
Wholesale:
Sales for resale	2,407		2,455			2,277
Total non-fuel base revenues	612,074		567,811			553,341
Fuel revenues:
Recovered from customers during the period	148,397		127,765			161,052
Under (over) collection of fuel	14,893		(13,342		)	3,110
New Mexico fuel in base rates	33,279		72,129			71,614
Total fuel revenues	196,569		186,552			235,776
Off-system sales:
Fuel cost	38,933		52,406			74,716
Shared margins	5,632		11,048			21,117
Retained margins	1,137		1,362			2,147
Total off-system sales	45,702		64,816			97,980
Other	32,591		30,690			30,428
Total operating revenues	$	886,936	$	849,869		$	917,525
Number of customers (end of year) (1):
Residential	363,987		358,819			353,885
Commercial and industrial, small	41,741		40,367			40,038
Commercial and industrial, large	49		49			49
Other	5,285		5,261			5,017
Total	411,062		404,496			398,989
Average annual kWh use per residential customer	7,748		7,763			7,496
Energy supplied, net, kWh (in thousands):
Generated	8,820,006		9,585,089			9,477,129
Purchased and interchanged	1,552,251		1,390,946			1,390,490
Total	10,372,257		10,976,035			10,867,619
Energy sales, kWh (in thousands):
Retail:
Residential	2,805,789		2,771,138			2,640,535
Commercial and industrial, small	2,403,447		2,384,514			2,357,846
Commercial and industrial, large	1,030,745		1,062,662			1,064,475
Sales to public authorities	1,572,510		1,585,568			1,562,784
Total retail	7,812,491		7,803,882			7,625,640
Wholesale:
Sales for resale	62,086		63,347			61,729
Off-system sales	1,927,508		2,500,947			2,609,769
Total wholesale	1,989,594		2,564,294			2,671,498
Total energy sales	9,802,085		10,368,176			10,297,138
Losses and Company use	570,172		607,859			570,481
Total	10,372,257		10,976,035			10,867,619
Native system:
Peak load, kW	1,892,000		1,794,000			1,766,000
Net dependable generating capability for peak, kW	2,080,000		2,055,000			1,879,000
Total system:
Peak load, kW (2)	2,027,000		1,992,000			1,953,000
Net dependable generating capability for peak, kW	2,080,000		2,055,000			1,879,000

___________________________

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

(2) Includes spot sales and net losses of 135,000 kW, 198,000 kW and 187,000 kW for 2016, 2015 and 2014, 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 (the "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 "Unopposed Settlement"). On August 25, 2016, the PUCT approved the Unopposed Settlement and issued its final order in Docket No. 44941 (the "PUCT Final Order"), as proposed. The 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 millionrelated to Four Cornerscosts, which will be collected through a surcharge terminating on July 12, 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 millionin rate case expenses through a separate surcharge and (v) allowing the Company to recover revenues associated with the relate back of rates to consumption on and after January 12, 2016 through March 31, 2016 through a separate surcharge.

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

For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2015 Texas Retail Rate Case until it received the PUCT Final Order on August 25, 2016. Accordingly, it reported in the third quarter of 2016 the cumulative effect of the PUCT Final Order which related back to January 12, 2016. The effects of the PUCT Final Order on operating results for the year ended December 31, 2016 increased operating revenues by $42.4 million, decreased depreciation expense by $10.3 million and decreased other expenses, net by approximately $2.7 million for an aggregate increase in income before income taxes of $50.0 million and an increase in net income of $27.3 million.

2017 Texas Retail Rate Case Filing. On February 13, 2017, the Company filed with the City of El Paso, other municipalities incorporated in the Company's Texas service territory and the PUCT in Docket No.46831, a request for an increase in non-fuel base revenues of approximately$42.5 million. The Company invoked its statutory right to have its new rates relate back for consumption on and after July 18, 2017, which is the 155th day after the filing. The difference in rates that would have been billed will be surcharged or refunded to customers after the PUCT's final order in Docket No. 46831. The PUCT has the authority to require the Company to surcharge or refund such difference over a period not to exceed 18 months. The Company cannot predict the outcome or the timing of this rate case at this time.

Energy Efficiency Cost Recovery Factor. On May 1, 2015, the Company filed its annual application to establish its energy efficiency cost recovery factor for 2016. In addition to projected energy efficiency costs for 2016 and a true-up to prior year actual costs, the Company requested approval of a $1.0 millionbonus for the 2014 energy efficiency program results in accordance with PUCT rules. This case was assigned PUCT Docket No. 44677. A stipulation and settlement agreement was filed September 24, 2015 and the PUCT approved the settlement on November 5, 2015. The settlement approved by the PUCT included a performance bonus of $1.0 million. The Company recorded the performance bonus in operating revenues in the fourth quarter of 2015.

On April 29, 2016, the Company filed its annual application to establish its energy efficiency cost recovery factor for 2017. In addition to projected energy efficiency costs for 2017 and true-up to prior year actual costs, the Company requested approval of a$0.7 millionbonus for the 2015 energy efficiency program results in accordance with PUCT rules. This case was assigned PUCT Docket No. 45885. Parties in the proceeding, including PUCT staff and the City of El Paso, filed a settlement in the case that approved the Company's proposal with a reduction to the 2015 program bonus of $0.2 million. The PUCT approved the settlement on October 28, 2016. The settlement approved by the PUCT included a performance bonus of$0.5 millionwhich was recorded in operating revenues in the third quarter of 2016.

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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 exceed4%of the previous twelve months' fuel costs. All such fuel revenue and expense activities are subject to periodic final review by the PUCT in fuel reconciliation proceedings.

On April 15, 2015, the Company filed a request, which was assigned PUCT Docket No. 44633, to reduce its fixed fuel factor by approximately 24% to reflect reduced fuel expenses primarily related to a reduction in the price of natural gas used to generate power. The over-recovered balance was below the PUCT's materiality threshold. The reduction in the fixed fuel factor was effective on an interim basis May 1, 2015 and approved by the PUCT on May 20, 2015.

On November 30, 2016, the Company filed a request, which was assigned PUCT Docket No. 46610, to increase its fixed fuel factor by approximately28.8%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 December 31, 2016, the Company had under-recovered fuel costs in the amount of$11.1 millionfor the Texas jurisdiction.

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 millionof Texas fuel and purchased power expenses incurred during the period of April 1, 2013 through March 31, 2016. A procedural schedule has been adopted with hearings in April 2017. As of December 31, 2016, Texas jurisdictional fuel and purchased power costs subject to a future Texas fuel reconciliation are approximately$114.4 million. The Company cannot predict the outcome or the timing of this matter.

Montana Power Station Approvals. The Company received Certificate of Convenience and Necessity ("CCN") approval from the PUCT to constructfournatural gas fired generating units atMPSin El Paso County, Texas. The Company also obtained air permits from the Texas Commission on Environmental Quality (the "TCEQ") and theEPA. MPS Units 1 and 2 and associated transmission lines and common facilities were completed and placed into service inMarch 2015. MPS Units 3 and 4 were completed and placed into service onMay 3, 2016andSeptember 15, 2016, respectively.

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 a3 MWsolar photovoltaic system located at MPS. Participation will be on a voluntary basis, and customers will contract for a set capacity (kW) amount and receive all energy produced. This case was assigned PUCT Docket No. 44800. The Company filed a settlement agreement among all parties on July 1, 2016 approving the program, and the PUCT approved the settlement agreement and program on September 1, 2016. The Company expects completion of the solar facility and commencement of the program in the second quarter of 2017.

Four Corners. On February 17, 2015, the Company and APSentered intothePurchase and Sale Agreementproviding for the sale of the Company's interest in Four Corners to APS.The sale of the Company's interest in Four Corners closed onJuly 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.

On June 10, 2015, the Company filed an application in Texas requesting reasonableness and public interest findings and certain rate and accounting findings related to the Purchase and Sale Agreement. This case was assigned PUCT Docket No. 44805. Subsequent to the filing of the application, the case has been subject to numerous procedural matters, including a March 23, 2016 order in which the PUCT determined not to dismiss the reasonableness and public interest issues in this docket but to consider the requested rate and accounting findings, including mine reclamation costs, in 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, and the parties are engaged in settlement discussions.

At December 31, 2016, the regulatory asset associated with the Four Corners mine reclamation costs for the Company's Texas jurisdiction was approximately$7.3 million. The Company currently continues to recover its mine reclamation costs in Texas under previous orders and decisions of the PUCT. If any future determinations made by the Company's regulators result in changes to how existing regulatory assets or previously incurred costs for Four Corners are recovered in rates, any such changes would be recognized only when it becomes probable future cash flows will change as a result of such regulatory actions.

13

Other Required Approvals. The Company has obtained other required approvals for tariffs and approvals required by the Public Utility Regulatory Act (the "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 millionin other service fees and a decrease in the Company's allowed return on equity to9.48%. 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.

2017 New Mexico Rate Case Filing. NMPRC Case No. 15-00109-UT requires 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.

Fuel and Purchased Power Costs. On January 8, 2014, the NMPRC approved the continuation of the Fuel and Purchased Power Cost Adjustment Clause (the "FPPCAC") without modification in NMPRC Case No. 13-00380-UT. Historically, fuel and purchased power costs were recovered through base rates and a FPPCAC that accounts for changes in the costs of fuel relative to the amount included in base rates. Effective July 1, 2016, with the implementation of the final order in Case No. 15-00127-UT, fuel and purchased power costs are no longer recovered through base rates 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. The Company recovers costs related to Palo Verde Unit 3 capacity and energy in New Mexico through the FPPCAC as purchased power using a proxy market price approved in Case No. 13-00380-UT. 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, 2016 that total approximately$114.6 million. At December 31, 2016, the Company had a net fuel over-recovery balance of$0.2 millionin New Mexico.

Montana Power Station Approvals.The Company received CCNs from the NMPRC to constructfourunits at MPS and the associated transmission lines. The Company also obtained all necessary air permits from the TCEQ and the EPA. A final order in NMPRC Case No. 13-00297-UT approving the CCN for MPS Units 3 and 4 was issued on June 11, 2014. MPS Units 1 and 2 and associated transmission lines and common facilities were completed and placed into service inMarch 2015. MPS Units 3 and 4 were completed and placed into service onMay 3, 2016andSeptember 15, 2016, respectively.

Four Corners. On June 15, 2016, in NMPRC Case No. 15-00109-UT, the NMPRC issued its final order approving the Company's sale and abandonment of its ownership interest in Four Corners to APS pursuant to a February 17, 2015 Purchase and Sale Agreement between the Company and APS.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.

5 MW HAFB Facility CCN.On October 7, 2015, in NMPRC Case No. 15-00185-UT, the NMPRC issued a final order approving a CCN for a5 MWsolar power generation facility located on HAFB in the Company's service territory in New Mexico. The Company and HAFB negotiated a special retail contract, which includes 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 second quarter of 2017.

Issuance of Long-Term Debt and Guarantee of Debt. On October 7, 2015 the Company received approval in NMPRC Case No. 15-00280-UT to issue up to$310.0 millionof new long-term debt and to guarantee the issuance of up to $65.0 millionof new debt by RGRTto finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. This approval supersedes prior approvals. Under this authorization, onMarch 24, 2016, the Company issued$150.0 millionaggregate principal amount of5.00%Senior Notes dueDecember 1, 2044. The net proceeds from the issuance of these senior notes, after deducting the underwriters' commission, were$158.1 million. These proceeds include accrued interest of$2.4 millionand a$7.1 millionpremium before expenses. These senior notes constitute an additional issuance of the Company's5.00%Senior Notes due2044, of which$150.0 millionwas previously issued onDecember 1, 2014, for a total principal amount outstanding of$300.0 million.

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

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Federal Regulatory Matters

Four Corners. On June 26, 2015, APS filed an application requesting authorization from FERC to purchase100%of the Company’s ownership interest in Units 4 and 5 of Four Corners and the associated transmission interconnection facilities and rights. On December 22, 2015, FERC issued an order approving the proposed transaction. The sale of the Company's interest in Four Corners closed onJuly 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.

Revolving Credit Facility; Issuance of Long-Term Debt and Guarantee of Debt. On October 19, 2015, the FERC issued an order in Docket No. ES15-66-000 approving the Company’s filing to issue short-term debt under theRCFup to$400.0 million outstanding at any time, to issue up to$310.0 million in long-term debt, and to guarantee the issuance of up to $65.0 millionof new long-term debt by RGRT to finance future nuclear fuel purchases. The authorization is effective from November 15, 2015 through November 15, 2017. This approval supersedes prior approvals.

Under this authorization, on March 24, 2016, the Company issued$150.0 millionaggregate principal amount of5.00%Senior Notes dueDecember 1, 2044. Additionally under this authorization, on January 9, 2017, the Company exercised its option to extend the maturity of the RCF by one year toJanuary 14, 2020and to increase the size of the facility by$50.0 millionto$350.0 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$50.0 million(up to a total of$400.0 million) upon the satisfaction of certain conditions, more fully set forth in the agreement, including obtaining commitments from lenders or third party financial institutions. Additionally, the Company agreed to reduce the letters of credit commitment to$50.0 millionfrom a total commitment, under the RCF, of$350.0 million.

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

United States Department of Energy. The DOE regulates the Company's exports of power to the Comisión Federal de Electricidad in Mexico pursuant to a license andtwopresidential permits issued by the DOE.

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

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.

Power Sales Contracts

The Company has entered into several short-term (three months or less) off-system sales contracts throughout 2016.

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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 to4.00%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 at3.25%of gross revenues, but the 2010 amendment added an incremental fee equal to0.75%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 onJuly 31, 2030.

The Company does not have a written franchise agreement with the City of Las Cruces, the second largest city in its service territory. The Company provides electric distribution service to the City of Las Cruces under an implied franchise by satisfying all obligations under the franchise agreement that expired onApril 30, 2009. The Company pays the City of Las Cruces a franchise fee of2.00%of gross revenues the Company receives from services within the City of Las Cruces.

Military Installations

The Company serves HAFB,White Sandsand Fort Bliss. These military installations represent approximately2.8% 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 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 PUCT Final Order established our current retail base rates in Texas, effective January 12, 2016. 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.

On February 13, 2017, we filed a general base rate case with the PUCT, Docket No. 46831 (the “2017 Texas rate case”), respectively, to establish new rates and to request recovery of new plant placed into service since April 2015 of approximately $444 million and to recover other cost of service increases. We anticipate that third parties will intervene in the 2017 Texas rate case and we expect them to challenge the reasonableness and necessity of certain of our costs. While we cannot predict the outcome or the timing of the 2017 Texas rate case at this time, we invoked our statutory right to have new rates relate back for consumption on and after July 18, 2017, which is the 155th day after the filing. The difference in rates that would have been billed will be surcharged or refunded to customers after the PUCT's final order in the 2017 Texas rate case. The PUCT has the authority to require us to surcharge or refund such differences over a period not to exceed 18 months. If the PUCT does not increase our rates adequately, our future operations, cash flow and financial condition could be materially and adversely affected. For a full discussion of these rate cases see Part II, Item 8, "Financial Statements and Supplementary Data, Note C of Notes to Financial Statements."

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. We are exposed to the risk of failing to recover all costs associated with the construction of MPS Units 3 and 4 and other new units and transmission assets.

In 2014 and 2016, we issued $150.0 million in aggregate principal amount of 5.00% Senior Notes, due December 1, 2044 for a total principal amount outstanding of $300.0 million. The net proceeds from the 5.00% Senior Notes along with borrowings under our RCF were used to fund the construction of MPS and other capital additions. The costs of financing and constructing these assets are subject to review by the PUCT and NMPRC. To the extent that the PUCT or the NMPRC determines that the costs of construction are not reasonable because of cost overruns, delays or other reasons, we may not be allowed to recover these costs from customers in base rates.

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.

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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

In recent years, the global credit and equity markets and the overall economy have been extremely volatile. These and future events could have a number of 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 shutdown. 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, 2016. 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 93.2% and 94.3% in the twelve months ended December 31, 2016 and 2015, 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.

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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 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. This could materially increase our costs and 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 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.

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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 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. Under EPA regulations finalized in May 2010, formerly known as the "Tailoring Rule", the EPA can impose GHG best achievable control technology requirements for sources, including power plants already required to implement prevention of significant deterioration under the CAA for certain other pollutants.

In addition, in October 2015, the EPA published a final rule establishing NSPS limiting CO2 emissions from new, modified and reconstructed electric generating units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate CO2 emissions from existing power plants, as well as a proposed "federal plan" to address CO2 emissions from affected units in those states that do not submit an approvable compliance plan. The standards for existing plants are known as the Clean Power Plan ("CPP"), under which rule interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates by 2030. Legal challenges to the CPP have been filed by groups of states and industry members. On February 9, 2016, the U.S. Supreme Court issued a decision to stay the rule until legal issues are resolved. Further, on September 3, 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. 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 $1,213,503 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).

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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 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 and distributed generation including solar rooftop projects. Customers’ increased use of energy efficiency measures and distributed generation could result in lower demand. Reduced demand due to energy efficiency measures 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 91% of revenues are directly related to the retail sales of electric power to approximately 400,000 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.

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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 control 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. 

Both the new administration and the Republicans in the House of Representatives have made public statements in support of comprehensive tax reform, including significant changes to the United States corporate income tax laws. These proposed changes include, among other things, a reduction in the corporate income tax rate, the immediate deductibility of 100% of capital expenditures, and the elimination of the interest expense deduction. We are currently unable to predict whether these reform discussions will result in any significant changes to existing tax laws, or if any such changes would have a cumulative positive or negative impact on us. However, it is possible that changes in the United States federal income tax laws could have a material adverse effect on our results of operations, financial condition, and cash flows.

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.

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 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-ways, 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"), which opened in early 2015, 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 four 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," 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)
2015
First Quarter	$	41.32	$	35.43	$	38.64	$	0.280
Second Quarter	39.26		33.77		34.66		0.295
Third Quarter	38.32		33.90		36.82		0.295
Fourth Quarter	40.35		35.32		38.50		0.295
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

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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, 2011 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.

	12/31/2011	12/31/2012	12/31/2013	12/31/2014	12/31/2015	12/31/2016
EE	100	96	109	128	127	158
EEI Index	100	102	115	149	143	168
NYSE Composite	100	113	139	145	136	148

As of January 31, 2017, there were 2,313 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 $49.6 million in cash dividends during the twelve months ended December 31, 2016. On January 26, 2017, the Board of Directors declared a quarterly cash dividend of $0.31 per share payable on March 31, 2017 to shareholders of record at the close of business on March 17, 2017. 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, 2016 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, 2016	—	$	—	—	393,816
November 1 to November 30, 2016	—	—		—	393,816
December 1 to December 31, 2016	5,579	46.50		—	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."

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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,
	2016		2015		2014		2013		2012
Operating revenue	$	886,936	$	849,869	$	917,525	$	890,362	$	852,881
Operating income	194,861		$	146,191	$	151,163	$	165,635	$	168,658
Net income	$	96,768	$	81,918	$	91,428	$	88,583	$	90,846
Basic earnings per share:
Net income	$	2.39	$	2.03	$	2.27	$	2.20	$	2.27
Weighted average number of shares outstanding	40,350,688		40,274,986		40,190,991		40,114,594		39,974,022
Diluted earnings per share:
Net income	$	2.39	$	2.03	$	2.27	$	2.20	$	2.26
Weighted average number of shares and dilutive
potential shares outstanding	40,408,033		40,308,562		40,211,717		40,126,647		40,055,581
Dividends declared per share of common stock	$	1.225	$	1.165	$	1.105	$	1.045	$	0.97
Cash additions to utility property, plant and equipment	$	225,361	$	281,458	$	277,078	$	237,411	$	202,387
Total assets (a)	$	3,376,278	$	3,200,607	$	3,033,400	$	2,748,139	$	2,637,183
Long-term debt, net of current portion (a)	$	1,195,513	$	1,122,660	$	1,122,235	$	988,436	$	987,960
Common stock equity	$	1,074,396	$	1,016,538	$	984,254	$	943,833	$	824,999

________________

(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, 2016, we had recorded regulatory assets currently subject to recovery in future rates of approximately $118.9 million and regulatory liabilities of approximately $18.4 million as discussed in greater detail in Part II, Item 8, Financial Statements and Supplementary Data, Note D of the Notes to Financial Statements. Regulatory tax assets of approximately $66.7 million, primarily related to the regulatory treatment of the equity portion of allowance for funds used during construction ("AFUDC") and excess deferred income taxes, are included in regulatory assets.

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 Fuel and Purchased Power Cost Adjustment Clause (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. As of December 31, 2016, Texas jurisdictional fuel and purchased power costs subject to a future Texas fuel reconciliation are approximately $114.4 million. The NMPRC approved the continuation of its use of the FPPCAC without modification and the Company’s application requesting reconciliation of fuel and purchased power costs through December 2012 in Case No. 13-00380-UT. 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, 2016 that total approximately $114.6 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

27

in February following the prior calendar year. As of December 31, 2016, the RGEC fuel costs subject to 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 $79.6 million and represents approximately 97% of our total ARO balance of $81.8 million as of December 31, 2016. A 10% increase in the estimates of future Palo Verde decommissioning costs at current price levels would have increased the ARO liability by approximately $7.8 million at December 31, 2016. 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 Nuclear Regulatory Commission, 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 $119.9 million as of December 31, 2016. A hypothetical 10% increase in interest rates would have reduced the fair values of these funds by $1.4 million at December 31, 2016. Our decommissioning trust funds also include marketable equity securities of approximately $129.8 million at December 31, 2016. A hypothetical 20% decrease in equity prices would have reduced the fair values of these funds by $26.0 million at December 31, 2016. 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, 2016 totaled $129.9 million and are recorded as liabilities on our balance sheet. The net periodic benefit costs for these plans totaled $3.8 million for the twelve months ended December 31, 2016.

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 2016, 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, 2016, the corresponding weighted-average discount rates range from 3.76% to 4.36% depending upon the benefit plan.

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Our overall expected long-term rate of return on assets for the pension trust fund is 7.0% effective January 1, 2017, which is both a pre-tax and after-tax rate as pension funds are generally not subject to income tax. Our overall expected long-term rate of return on assets for the other post-retirement benefits trust, on an after-tax basis, is 4.875% effective January 1, 2017. Both expected long-term rates of return are based on the after-tax weighted average of the expected returns on investments. The expected returns on investments in the pension trust and the other post-retirement benefits trust are based upon the target asset allocations for the two trusts.

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 6.5%, 7.5%, 4.5% and 10.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2017 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 forpension and other post-retirementbenefits. This change, compared to the previous method, resulted in a decrease in the service cost and interest cost components in 2016, and is expected to result in a decrease in the service cost and interest cost components in future periods. 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 change in estimate decreased the service and interest components of net periodic benefit cost for pension and other post-retirementbenefitsin 2016 by approximately$2.9 million and $0.8 million, respectively.

The following table reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2016 reported pension liability and our 2016 reported pension expense (in thousands):

	Increase (Decrease)
Actuarial Assumption	Impact on Pension Liability			Impact on Pension Expense
Discount rate:
Increase 1%	$	(41,843	)	$	(3,601	)
Decrease 1%	51,463			4,343
Expected long-term rate of return on plan assets:
Increase 1%	N/A			(2,698		)
Decrease 1%	N/A			2,698
Compensation rate:
Increase 1%	6,615			1,241
Decrease 1%	(6,002		)	(1,106		)

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The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2016 other post-retirement benefit obligations and our 2016 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%	$	(9,631	)	$	(1,329	)	$	(276	)
Decrease 1%	12,246			1,595			350
Healthcare cost trend rate:
Increase 1%	11,222			2,342			1,252
Decrease 1%	(8,951		)	(1,919		)	(973		)
Expected long-term rate of return on plan assets:
Increase 1%	N/A			(376		)	N/A
Decrease 1%	N/A			376			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.

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, 2016.

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 $2.6 million as of December 31, 2016.

Overview

The following is an overview of our results of operations for the years ended December 31, 2016, 2015 and 2014. Net income and basic earnings per share for the years ended December 31, 2016, 2015 and 2014 are shown below:

	Years Ended December 31,
	2016		2015		2014
Net income (in thousands)	$	96,768	$	81,918	$	91,428
Basic earnings per share	2.39		2.03		2.27

Financial Effect of the PUCT Final Order

On August 25, 2016, the PUCT approved the Unopposed Settlement and issued its final order in Docket No.44941 (the "PUCT Final Order"), as proposed. See Part II, Item 8, "Financial Statements and Supplementary Data, Note C of Notes to Financial Statements."

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

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

		Three Months Ended												Twelve Months Ended
Category		March 31, 2016			June 30, 2016			September 30, 2016			December 31, 2016			December 31, 2016
Retail non-fuel base rate increase:
Relate back		$	4,782		$	—		$	—		$	—		$	4,782
Interim rates		457			10,417			15,138			—			26,012
Additional non-fuel base rate increase for Four Corners		708			867			1,328			853			3,756
Base rate increase		—			—			—			6,321			6,321
Retail non-fuel base rate increase, total		$	5,947		$	11,284		$	16,466		$	7,174		$	40,871
Miscellaneous service revenues		353			400			390			379			1,522
Revenue taxes		(19		)	(436		)	(643		)	(238		)	(1,336		)
Depreciation		2,491			2,510			2,412			2,849			10,262
Rate case expense		—			—			(600		)	(395		)	(995		)
AFUDC		(106		)	(87		)	(72		)	(52		)	(317		)
Pre-tax increase		$	8,666		$	13,671		$	17,953		$	9,717		$	50,007
Income tax expense (a)		4,104			5,677			7,221			5,714			22,716
After-tax increase		$	4,562		$	7,994		$	10,732		$	4,003		$	27,291
(a)	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 PUCT Final Order and the NMPRC Final Order. The impact of the change was additional income tax expense of $5.1 million for the twelve months ended December 31, 2016.

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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 2016 and 2015, 2015 and 2014, and 2014 and 2013 (in thousands):

	2016				2015				2014
Prior year December 31 net income	$	81,918			$	91,428			$	88,583
Changes (net of tax):
Increased (decreased) retail non-fuel base revenues	28,802			(a)	9,290			(b)	(3,533		)	(c)
Decreased (increased) depreciation and amortization	3,580			(d)	(4,214		)	(e)	(2,415		)	(f)
Increased (decreased) non-base revenue, net of energy expense	804				(5,370		)	(g)	3,779			(h)
Changes in the effective tax rate	(5,343		)	(i)	1,540			(j)	15
(Decreased) increased allowance for funds used during construction	(4,887		)	(k)	(4,953		)	(l)	6,157			(m)
Increased interest on long-term debt (net of capitalized interest)	(3,700		)	(n)	(4,516		)	(o)	(390		)
(Decreased) increased investment and interest income	(2,784		)	(p)	3,084			(q)	5,309			(r)
Increased taxes other than income taxes	(1,168		)	(s)	(641		)		(3,252		)	(t)
Other	(454		)		(3,730		)		(2,825		)
Current year December 31 net income	$	96,768			$	81,918			$	91,428

______________________ 

Footnotes reflect pre-tax amounts

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

(b) Retail non-fuel base revenues increased, primarily due to (i) increased revenues of $11.9 million from our residential customers due to hotter weather in the third quarter of 2015 contributing to a 4.9% increase in kWh sales; (ii) increased revenues of $2.0 million from small commercial and industrial customers due to a 1.1% increase in kWh sales resulting from hotter weather and a 1.6% increase in the average number of customers and (iii) a $1.2 million increase from large commercial and industrial customers. These increases were partially offset by an $0.8 million decrease from sales to public authorities due to a military installation moving a portion of their load to an interruptible rate.

(c) Retail non-fuel base revenues decreased, primarily due to (i) a $3.0 million reduction in revenues from sales to public authorities reflecting increased use of an interruptible rate at a military installation in our service territory as well as other energy saving programs at military installations; (ii) a $2.3 million decrease in sales to residential customers primarily due to milder weather; and (iii) a $1.0 million decrease in sales to large commercial and industrial customers.

(d) Depreciation and amortization decreased primarily due to (i) a reduction of approximately $10.9 million resulting from changes in depreciation rates approved in the PUCT Final Order and the NMPRC Final Order and (ii) the sale of the Company's interest in Four Corners. 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.

(e) 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.

(f) Depreciation and amortization increased due to increased depreciable plant balances including Rio Grande Unit 9, which began commercial operation in the second quarter of 2013.

(g) 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.

(h) Non-base revenues, net of energy expenses increased due to: (i) recognition of $2.2 million in Palo Verde performance rewards associated with the 2009 to 2012 performance periods, net of disallowed fuel and purchased power costs related to the resolution of the Texas fuel reconciliation proceeding designated as PUCT Docket No. 41852; (ii) a $2.0 million Texas Energy Efficiency bonus awarded in the fourth quarter of 2014 and (iii) an increase of $3.6 million in deregulated Palo Verde Unit 3 revenues. The increase was partially offset by a decrease of $3.3 million in transmission wheeling revenues.

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

32

(j) 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 AEFUDC and the loss of the domestic production activities deduction in 2015.

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

(l) AFUDC decreased primarily due to lower balances of construction work in process 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) AFUDC increased, primarily due to higher balances of CWIP subject to AFUDC, reflecting construction work in progress on MPS and the EOC.

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

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

(p) Investment and interest income decreased primarily due to lower realized gains on securities sold from the Company’s Palo Verde decommissioning trust in 2016 compared to 2015. The net gains reported in 2016 and 2015 are primarily the result of the Company's efforts to re-balance and further diversify its Palo Verde decommissioning trust fund investments.

(q) Investment and interest income increased, primarily due to further diversification and re-balancing our Palo Verde decommissioning trust fund equity portfolio.

(r) Investment and interest income increased, primarily due to increased gains on the sales of equity investments in our Palo Verde decommissioning trust funds.

(s) 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.

(t) Taxes other than income taxes increased, primarily due to higher property tax values and assessment rates. Additionally, in the first quarter of 2014, the Arizona tax district in which Palo Verde operates adjusted its 2013 property tax rate, resulting in an additional charge of $1.3 million.

33

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 2016, 2015 and 2014.

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,
	2016		2015		2014
Residential	46	%	44	%	42	%
Commercial and industrial, small	32		33		34
Commercial and industrial, large	6		7		7
Sales to public authorities	16		16		17
Total retail non-fuel base revenues	100	%	100	%	100	%

No retail customer accounted for more than 4% of our non-fuel base revenues during such periods. As shown in the table above, residential and small commercial customers comprise 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 from 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,
	2016		2015		2014
January 1 to March 31	17	%	18	%	19	%
April 1 to June 30	25		26		27
July 1 to September 30	38		35		33
October 1 to December 31	20		21		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 2016, 2015 and 2014.

	2016	2015	2014	10-year Average
Cooling degree days	2,811	2,839	2,671	2,732
Heating degree days	1,851	2,095	1,900	2,157

34

Customer growth is a key driver in the growth of retail sales. The average number of retail customers grew 1.5% and 1.4% in 2016 and 2015, respectively. See the tables presented on pages 37 and 38 which provide detail on the average number of retail customers and the related revenues and kWh sales.

Retail non-fuel base revenues. Retail non-fuel base revenues increased primarily due to the recognition of $40.9 million related to the PUCT Final Order. Excluding the $40.9 million PUCT Final Order impact, for the twelve months ended December 31, 2016, retail non-fuel base revenues increased $3.4 million, pre-tax, 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.

Retail non-fuel base revenues increased $14.3 million, or 2.6%, for the twelve months ended December 31, 2015 when compared to the twelve months ended December 31, 2014. This increase includes an $11.9 million increase in revenues from residential customers and a $2.0 million increase in revenues from small commercial and industrial customers reflecting hotter summer weather and increases of 1.3% and 1.6%, respectively, in the average number of residential customers and small commercial and industrial customers. KWh sales to public authorities increased 1.5% while revenue declined by $0.8 million, primarily due to a military installation moving a portion of their load to an interruptible rate. Retail non-fuel revenues from large commercial and industrial customers increased $1.2 million due to a surcharge billed to a large customer. Cooling degree days increased 6.3% in 2015, when compared to the same period in the prior year, and were 5.3% over the 10-year average. Heating degree days increased 10.3% for 2015, compared to 2014, and were 3.6% 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 Texas, fuel costs are recovered through a fixed fuel factor. We can seek to revise our fixed fuel factor based upon an approved formula at least four months after our last revision, except in the month of December. In addition, if we materially over-recover fuel costs, we must seek to refund the over-recovery, and if we materially under-recover fuel costs, we may seek a surcharge to recover those costs. Fuel over and under recoveries are defined as material when they exceed 4% of the previous twelve months' fuel costs. On April 15, 2015, we filed a request, which was assigned PUCT Docket No. 44633, to reduce our fixed fuel factor by approximately 24% to reflect an expected reduction in fuel expense. The over-recovered balance was below the materiality threshold. The reduction in the fixed fuel factor was effective on an interim basis May 1, 2015 and was approved by the PUCT on May 20, 2015. On November 30, 2016, we filed a request, which was assigned PUCT Docket No. 46610, to increase our 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 3, 2017 and approved by the PUCT on January 10, 2017. On September 27, 2016, we 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.

In New Mexico, effective July 1, 2016, with the implementation of the NMPRC Final Order, fuel and purchased power costs will no longer be recovered through base rates, as it was historically, but will be completely recovered through the Fuel and Purchased Power Cost Adjustment Clause (the "FPPCAC"). Fuel and purchased power costs are reconciled to actual costs on a monthly basis and recovered or refunded to customers the second succeeding month. The Company's request to reconcile its fuel and purchased power costs for the period January 1, 2013 through December 31, 2014 was approved in the NMPRC Final Order.

In March 2015 and March 2016, $5.8 million and $1.6 million, respectively, were credited to customers through the applicable fuel adjustment clauses as the result of a reimbursement from the DOE related to spent nuclear fuel storage.

We under-recovered fuel costs by $14.9 million in the twelve months ended December 31, 2016. We over-recovered fuel costs by $13.3 million and under-recovered $3.1 million in the twelve months ended December 31, 2015 and 2014, respectively. At December 31, 2016, we had a net fuel under-recovery balance of $10.9 million, including an under-recovery of $11.1 million in Texas offset by an over-recovery of $0.2 million in New Mexico.

35

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.

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, 2016, 2015 and 2014 (in thousands, except for MWhs).

	Years Ended December 31,
	2016		2015		2014
MWh sales	1,927,508		2,500,947		2,609,769
Sales revenue	$	45,702	$	64,816	$	97,980
Fuel cost	$	38,933	$	52,406	$	74,716
Total margins	$	6,769	$	12,410	$	23,264
Retained margins	$	1,137	$	1,362	$	2,147

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. Off-system sales revenues decreased $33.2 million, or 33.8%, and the related retained margins decreased $0.8 million, or 36.6%, for the twelve months ended December 31, 2015 when compared to 2014 as a result of lower average market prices for power and a 4.2% decrease in MWh sales.

36

Comparisons of kWh sales and operating revenues are shown below:

						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	33,279		72,129			(38,850		)	(53.9	)
Total fuel revenues (3)	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 (4) (5)	32,591		30,690			1,901			6.2
Total operating revenues	$	886,936	$	849,869		$	37,067		4.4
Average number of retail customers (6):
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 PUCT Final Order in 2016.

(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) 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.

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

(5) Represents revenues with no related kWh sales and includes $1.5 million increase resulting from the PUCT Final Order in 2016.

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

37

						Increase (Decrease)
Years Ended December 31:	2015			2014		Amount			Percent
kWh sales (in thousands):
Retail:
Residential	2,771,138			2,640,535		130,603			4.9	%
Commercial and industrial, small	2,384,514			2,357,846		26,668			1.1
Commercial and industrial, large	1,062,662			1,064,475		(1,813		)	(0.2	)
Sales to public authorities	1,585,568			1,562,784		22,784			1.5
Total retail sales	7,803,882			7,625,640		178,242			2.3
Wholesale:
Sales for resale	63,347			61,729		1,618			2.6
Off-system sales	2,500,947			2,609,769		(108,822		)	(4.2	)
Total wholesale sales	2,564,294			2,671,498		(107,204		)	(4.0	)
Total kWh sales	10,368,176			10,297,138		71,038			0.7
Operating revenues (in thousands):
Non-fuel base revenues:
Retail:
Residential	$	246,265		$	234,371	$	11,894		5.1	%
Commercial and industrial, small	187,436			185,388		2,048			1.1
Commercial and industrial, large	40,411			39,239		1,172			3.0
Sales to public authorities	91,244			92,066		(822		)	(0.9	)
Total retail non-fuel base revenues	565,356			551,064		14,292			2.6
Wholesale:
Sales for resale	2,455			2,277		178			7.8
Total non-fuel base revenues	567,811			553,341		14,470			2.6
Fuel revenues:
Recovered from customers during the period	127,765			161,052		(33,287		)	(20.7	)
Under (over) collection of fuel (1)	(13,342		)	3,110		(16,452		)	-
New Mexico fuel in base rates	72,129			71,614		515			0.7
Total fuel revenues (2)	186,552			235,776		(49,224		)	(20.9	)
Off-system sales:
Fuel cost	52,406			74,716		(22,310		)	(29.9	)
Shared margins	11,048			21,117		(10,069		)	(47.7	)
Retained margins	1,362			2,147		(785		)	(36.6	)
Total off-system sales	64,816			97,980		(33,164		)	(33.8	)
Other (3) (4)	30,690			30,428		262			0.9
Total operating revenues	$	849,869		$	917,525	$	(67,656	)	(7.4	)
Average number of retail customers (5):
Residential	356,969			352,277		4,692			1.3	%
Commercial and industrial, small	40,250			39,600		650			1.6
Commercial and industrial, large	49			49		—			-
Sales to public authorities	5,250			5,088		162			3.2
Total	402,518			397,014		5,504			1.4

 _______________________

(1) Includes the portion of DOE refund related to spent fuel storage of $5.8 million and $7.9 million in 2015 and 2014, respectively, that were credited to customers through the applicable fuel adjustment clauses. 2014 includes $2.2 million related to Palo Verde performance rewards, net.

(2) Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $9.7 million and $15.0 million in 2015 and 2014, respectively.

(3) Includes an Energy Efficiency Bonus of $1.3 million and $2.0 million in 2015 and 2014, respectively. 

(4) Represents revenues with no related kWh sales.

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

38

Energy expenses

Our sources of energy include electricity generated from our nuclear, natural gas and coal generating plants and purchased power. After adding the new natural gas generating units (MPS Units 1 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 available net generating capacity and approximately 58% of our Company-generated energy for the twelve months ended December 31, 2016. 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 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 a 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.

Energy expenses decreased $73.9 million, or 23.4%, for the twelve months ended December 31, 2015 compared to 2014, primarily due to (i) decreased natural gas costs of $62.5 million due to a 32.0% decrease in the average price of natural gas, (ii) decreased total purchased power of $11.3 million due to a 18.7% decrease in the average price of total purchased power and (iii) decreased nuclear fuel expense of $1.2 million due to a 7.2% decrease in the cost of nuclear fuel consumed. The decrease in energy expense was partially offset by (i) a $2.1 million reduction in the 2015 DOE refund compared to 2014 and (ii) an increase in coal costs of $1.0 million due to a 10.3% increase in the MWhs generated with coal.

The table below details the sources and costs of energy for 2016, 2015 and 2014.

	2016						2015
Fuel Type	Cost			MWh	Cost per MWh		Cost			MWh	Cost per MWh
	(in thousands)						(in thousands)
Natural Gas	$	123,806		3,550,904	$	34.87	$	134,361		3,790,659	$	35.45
Coal	6,154		(a)	175,258	35.11		13,913			657,744	21.15
Nuclear	43,778		(b)	5,093,844	8.94		40,126		(b)	5,136,686	9.06
Total	173,738			8,820,006	19.90		188,400			9,585,089	20.32
Purchase Power:
Photovoltaic	23,413			289,800	80.79		22,495			277,241	81.14
Other	36,314			1,262,451	28.76		31,050			1,113,705	27.88
Total purchased power	59,727			1,552,251	38.48		53,545			1,390,946	38.50
Total energy	$	233,465		10,372,257	22.68		$	241,945		10,976,035	22.63
	2014
Fuel Type	Cost			MWh	Cost per MWh
	(in thousands)
Natural Gas	$	196,833		3,774,209	$	52.15
Coal	12,883			596,252	21.61
Nuclear	41,289		(b)	5,106,668	9.76
Total	251,005			9,477,129	27.39
Purchase Power:
Photovoltaic	19,575			227,979	85.86
Other	45,229			1,162,511	39.80
Total purchased power	64,804			1,390,490	47.35
Total energy	$	315,809		10,867,619	29.94

 _____________________

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

(b) Costs includes a DOE refund related to spent fuel storage of $1.8 million, $6.4 million, and $8.5 million recorded in 2016, 2015, and 2014, respectively. Cost per MWh excludes this settlement.

39

Other operations expense

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 offset by increased operating expenses at the MPS, and (iii) decreased other administrative and general expenses of $0.5 million. These decreases were partially offset by (i) a $2.3 million increase in regulatory expenses, primarily related to the 2015 New Mexico and Texas rate cases being expensed, and (ii) increased transmission and distribution expenses of $0.8 million.

Other operations expense increased $4.1 million, or 1.7%, in 2015 compared to 2014 primarily due to (i) a $4.0 million increase in other operations payroll costs including a $1.5 million increase in employee incentive compensation; (ii) increased pension and benefits costs due to changes in actuarial assumptions used to calculate expenses for the post-retirement benefit plan; (iii) a $1.7 million increase in operations expenses at our fossil-fuel generating plants primarily due to expenses at our MPS with no comparable expenses during 2014 and (iv) a $1.5 million increase in transmission and distribution expenses related to wheeling expense and system support and improvements. These increases were partially offset by (i) a $1.9 million decrease in outside services expenses and (ii) a $1.4 million decrease in operations expense at Palo Verde.

Maintenance expense

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. Maintenance expense decreased $0.4 million, or 0.6%, in 2015 compared to 2014, primarily due to a decrease in the level of maintenance at our Rio Grande and Four Corners generating plants, which was partially offset by maintenance at our MPS with no comparable expenses during 2014.

Depreciation and amortization expense

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 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 May 2016 and September 2016, respectively.

Depreciation and amortization expense increased $6.5 million, or 7.8%, in 2015 compared to 2014, primarily due to the increases in depreciable plant balances, including MPS Units 1 and 2 and the EOC, which were placed in service during the first quarter of 2015, partially offset by an increase in the estimated useful lives of certain large intangible software systems effective July 2015 in the amount of $1.8 million.

Taxes other than income taxes

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. Taxes other than income taxes increased $1.0 million, or 1.6%, in 2015 compared to 2014, primarily due to (i) higher property tax values and assessment rates and (ii) additional payroll taxes.

Other income (deductions)

Other income (deductions) decreased $7.2 million, or 27.8%, in 2016 compared to 2015, primarily due to (i) decreased allowance for equity funds used during construction ("AEFUDC") resulting from lower average balances of construction work in progress ("CWIP") and a reduction in the AEFUDC rate, and (ii) decreased investment and interest income due to lower realized gains from our Palo Verde decommissioning trust fund equity portfolio.

Other income (deductions) decreased $2.3 million, or 8.1%, in 2015 compared to 2014, primarily due to (i) decreased AEFUDC resulting from lower average balances of CWIP and a reduction in the AEFUDC rate and (ii) higher gains recognized on the sales of land in 2014 compared to 2015. This decrease was partially offset by increased investment and interest income due to further diversification and re-balancing of our Palo Verde decommissioning trust fund equity portfolio.

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Interest charges (credits)

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 allowance for borrowed funds used during construction ("ABFUDC") as a result of lower average balances of CWIP and a reduction in the ABFUDC rate.

Interest charges (credits) increased by $8.4 million, or 18.0%, in 2015 compared to 2014 primarily due to interest expense on the $150.0 million aggregate principal amount of 5.00% Senior Notes due 2044 issued in December 2014 and decreased ABFUDC as a result of lower balances of CWIP and a reduction in the ABFUDC rate.

Income tax expense

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 and (ii) an increase in state income taxes due to normalization as discussed in Note J of the Notes to Financial Statements and decreases in decommissioning trust income, which is taxed at a lower rate. Income tax expense decreased by $6.2 million, or 15.1%, in 2015 compared to 2014, primarily due to (i) a decrease in the pre-tax income and (ii) a decrease in state income taxes.

New accounting standards

In May 2014, the FASB issuedASU2014-09, 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. Early adoption of ASU 2014-09 is permitted after December 15, 2016, however, we plan to adopt the new standard for reporting periods beginning after December 15, 2017.

Under the new standard, companies may use either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We have not concluded which transition method we will elect but we currently anticipate using the modified retrospective approach.

We are currently in the process of evaluating the impact of the new standard on our various revenue and cash flow streams, including the evaluation of the impact, if any, on changes to business processes, systems and controls to support recognition and disclosure 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 not completed our final evaluation of tariff sales under the new guidance but currently we do not anticipate that ASU 2014-09 will have a material impact on our revenue recognition for such sales. We are still considering the impacts of the guidance on several industry-related accounting issues, including the accounting for contributions in aid of construction ("CIAC"), assessing the collectability criterion and the presentation of revenues associated with alternative revenue programs. Our initial assessment may change as we execute our implementation plan and new guidance is provided by the American Institute of Certified Public Accountants Power and Utilities Industry Task Force.

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 public companies for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Upon adoption of the new standard, we expect to record the cumulative effects as of January 1, 2018 which will result in an adjustment to accumulated other comprehensive income (losses) and retained earnings for unrealized gains (losses) related to equity securities owned by us. Had we been required to adopt the new standard at January 1, 2016, accumulated other comprehensive income would decrease by$28.8 millionand retained earnings would increase by a corresponding amount. Furthermore, we would report for the year ended

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December 31, 2016 an increase in investment income of$1.2 million, an increase in income tax expense of$0.2 millionand a decrease in other comprehensive income of$1.0 million. We continue to assess the future impact of this ASU.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and requiring qualitative and quantitative disclosures on leasing agreements. ASU 2016-02 maintains a distinction between finance leases and operating leases similar to the distinction under previous leases guidance for capital leases and operating leases. The impact of leases reported in 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 for public companies will be required for annual reporting periods beginning after December 15, 2018 and interim periods within that reporting period. Early adoption of ASU 2016-02 is permitted for all entities, however, we plan to adopt the new standard 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, including the evaluation of 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 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 will adopt the new standard effective January 1, 2017 and do not expect the effect of the adoption to be material to our financial condition, results of operations or cash flows. The cumulative effect of the adoption of the new standard will be to increase net operating loss carryforward deferred tax assets and retained earnings by approximately$0.2 millionon January 1, 2017. We also expect to continue to account for our outstanding stock awards based on the equity method and therefore do not anticipate any changes in reporting related compensation expense.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326) ("ASU 2016-13"). 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. For public business entities, the provisions of ASU 2016-13 are effective for fiscal years and interim periods within that reporting period beginning after December 15, 2019. Early implementation is permitted as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. ASU 2016-13 will be applied in a modified-retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is implemented. We are currently assessing the future impact of 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 new guidance addresses the following classification issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon bonds; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. For public business entities, the provisions of ASU 2016-15 are effective for fiscal years and interim periods within that reporting period beginning after December 15, 2017. Early adoption is permitted, including adoption in an interim period. If an entity elects early adoption of ASU 2016-15 in an interim period, adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. 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 December 2016, the FASB issued ASU 2016-19, Technical Corrections and Improvements, which amends a number of Topics in the FASB ASC. This ASU is part of an ongoing FASB project to facilitate Codification updates for non-substantive technical corrections, clarifications, and improvements that are not expected to have a significant effect on accounting practice or create a significant administrative cost to most entities. Most of the amendments are effective upon issuance of ASU 2016-19 while certain amendments that require transition guidance are effective for us beginning January 1, 2017. We believe we are in

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compliance with those amendments that are effective immediately and that are applicable to us. We have not completed our evaluation of the new standard for amendments that require transition guidance.

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

In March 2016, we issued $150.0 million aggregate principal amount of 5.00% Senior Notes due December 1, 2044 to repay outstanding short-term borrowings under our RCF used for working capital and general corporate purposes, which may include funding capital expenditures. Despite such issuances of senior notes, 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, 2016, our capital structure, including common stock, long-term debt, current maturities of long-term debt, and short-term borrowings under the RCF, consisted of 44.1% common stock equity and 55.9% debt. As of December 31, 2016, we had a balance of $8.4 million of cash and cash equivalents. Based on current projections, we believe that we will have adequate liquidity through our current cash balances, cash from operations and available borrowings under our RCF to meet all of our anticipated cash requirements for the next twelve months, including the upcoming maturities of long term debt.

Our principal liquidity requirements in the near-term are expected to consist of capital expenditures to expand and support electric service obligations, expenditures for nuclear fuel inventory, interest payments on our indebtedness, cash dividend payments, operating expenses including fuel costs, maintenance costs and taxes, payment of our $50.0 million Series B 4.47% Senior Notes which mature in August 2017 and payment or remarketing of $33.3 million 2012 Series A 1.875% Pollution Control Bonds which are subject to mandatory tender for purchase in September 2017.

Capital Requirements. During the twelve months ended December 31, 2016, our capital requirements primarily consisted of expenditures for the construction and purchase of electric utility plant, cash dividend payments, and purchases of nuclear fuel. Projected utility construction expenditures are to add new generation, expand and update our transmission and distribution systems, and make capital improvements and replacements at Palo Verde and other generating facilities. On May 3, 2016 and September 15, 2016, we placed into commercial operation MPS Units 3 and 4, respectively, and the related common facilities and transmission systems at a combined cost of approximately $160.5 million, including AFUDC, for the two units. Estimated cash construction expenditures for all capital projects for 2017 are expected to be approximately $215 million. See Part I, Item 1, "Business – Construction Program." Cash capital expenditures for new electric plant were $225.4 million in the twelve months ended December 31, 2016 compared to $281.5 million in the twelve months ended December 31, 2015. Capital requirements for purchases of nuclear fuel were $42.4 million for the twelve months ended December 31, 2016, as compared to $42.0 million for the twelve months ended December 31, 2015.

On December 30, 2016, we paid a quarterly cash dividend of $0.31 per share, or $12.6 million, to shareholders of record as of the close of business on December 14, 2016. We paid a total of $49.6 million in cash dividends during the twelve months ended December 31, 2016. On January 26, 2017, our Board of Directors declared a quarterly cash dividend of $0.31 per share payable on March 31, 2017 to shareholders of record at the close of business on March 17, 2017 which will require cash of $12.5 million. 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 2017, we may repurchase shares of our common stock in the future. Under our repurchase program, purchases can be made at open market prices or in private transactions, and repurchased shares are available for issuance under employee benefit and stock incentive plans, or may be retired. No shares of common stock were repurchased during the twelve months ended December 31, 2016. As of December 31, 2016, 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. Due to net operating loss carryfowards resulting from accelerated depreciation deductions, income tax payments are expected to be minimal in 2017.

We continually evaluate our funding requirements related to our retirement plans, other post-retirement benefit plans, and decommissioning trust funds. We contributed $9.2 million and $10.9 million to our retirement plans during both the twelve months

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ended December 31, 2016 and 2015, respectively. We contributed $1.7 million and $0.5 million to our other post-retirement benefit plans during the twelve months ended December 31, 2016 and 2015, respectively. We contributed $4.5 million to our decommissioning trust funds in both 2016 and 2015. 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 RGRT, a Texas grantor trust through which we finance our portion of fuel for Palo Verde, entered into a note purchase agreement with various institutional purchasers. Under the terms of the agreement, RGRT sold to the purchasers $110.0 million aggregate principal amount of senior notes. In August 2015, $15.0 million of these senior notes matured and were paid with borrowings under the RCF. In August 2016, $50.0 million of these senior notes were reclassified to current maturities of long-term debt on our Balance Sheet, as they will mature in August 2017.

Capital Resources. Cash provided by operations, $231.2 million for the twelve months ended December 31, 2016 and $246.7 million for the twelve months ended December 31, 2015, is a significant source for funding capital requirements. The primary factors affecting the change in cash flows from operations were increases in net under-collection of fuel revenues and accounts receivable. Offsetting the decreases in cash flows from operations were increased revenues due to the PUCT Final Order and the NMPRC Final Order and increases in deferred income taxes. 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 November 30, 2016, we filed a request to increase our Texas fixed fuel factor by approximately 28.8% to reflect increasing natural gas costs. This increase was effective with January 2017 billings. During the twelve months ended December 31, 2016, we had under-recoveries of fuel costs of $14.9 million compared to over-recoveries of fuel costs of $13.3 million during the twelve months ended December 31, 2015. At December 31, 2016, we had a net fuel under-recovery balance of $10.9 million, including an under-recovery of $11.1 million in the Texas jurisdiction offset by an over-recovery of $0.2 million 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. Additionally, we agreed to reduce the letters of credit commitment under the RCF to $50.0 million from a total commitment of $350.0 million. The total amount borrowed for nuclear fuel by RGRT, excluding debt issuance costs, was $132.6 million at December 31, 2016, of which $37.6 million had been borrowed under the RCF, and $95.0 million was borrowed through senior notes. At December 31, 2015, the total amounts borrowed for nuclear fuel by RGRT, excluding debt issuance costs, were $128.7 million of which $33.7 million had been borrowed under the RCF and $95.0 million was borrowed through senior notes. Interest costs on borrowings to finance nuclear fuel are accumulated by RGRT and charged to us as fuel is consumed and recovered from customers through fuel recovery charges. The outstanding balance for working capital and general corporate purposes was $44.0 million at December 31, 2016 and $108.0 million at December 31, 2015. Total aggregate borrowings under the RCF as of December 31, 2016 were $81.6 million, with available borrowing capacity of $267.9 million thereunder, after giving consideration to the $50.0 million increase on January 9, 2017.

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

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short-term borrowings under the RCF. These senior notes constitute an additional issuance of our 5.00% Senior Notes due 2044, of which $150.0 million aggregate principal amount was previously issued on December 1, 2014, for a total principal amount currently outstanding of $300.0 million.

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Contractual Obligations. Our contractual obligations as of December 31, 2016 are as follows (in thousands):

	Payments due by period
	Total		2017		2018 and 2019		2020 and 2021		2022 and Beyond
Long-term debt (including interest):
Senior notes (1)	$	2,135,575	$	55,200	$	110,400	$	110,400	$	1,859,575
Pollution control bonds (2)	434,253		43,675		19,918		19,918		350,742
RGRT senior notes (3)	106,307		54,503		4,536		47,268		—
Financing obligations (including interest):
Revolving credit facility (4)	83,075		83,075		—		—		—
Purchase obligations:
Power contracts	12,726		12,726		—		—		—
Fuel contracts:
Gas (5)	335,992		50,278		58,538		61,261		165,915
Nuclear fuel (6)	84,960		21,521		22,558		15,454		25,427
Retirement plans and other post-retirement benefits (7)	11,498		11,498		—		—		—
Nuclear Decommissioning Trust Funds (8)	4,500		4,500		—		—		—
Operating leases (9)	9,940		808		1,328		1,226		6,578
Total	$	3,218,826	$	337,784	$	217,278	$	255,527	$	2,408,237

 _____________________

(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 four series of pollution control bonds that are scheduled for remarketing and/or mandatory tender, one in 2017, two in 2040, and one in 2042.

(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, due 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 $300.0 million RCF. At December 31, 2016, $44.0 million was borrowed for working capital and general corporate purposes and $37.6 million was borrowed by RGRT for nuclear fuel. This balance includes interest based on actual interest rates at the end of 2016 and assumes this amount will be outstanding for the entire year of 2017.

(5) Amount is based on the minimum volumes per the contract and market and/or contract price at the end of 2016. 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 2016.

(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 2017. We have no minimum cash contractual funding requirement related to our retirement income plan or other post-retirement benefits for 2017. However, we are subject to minimum funding requirements of ERISA. We also may decide to fund at higher levels and expect to contribute $11.5 million to our retirement plans in 2017, as disclosed in Part II, Item 8, Financial Statements and Supplementary Data, Note M. Minimum funding requirements for 2018 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 our anticipated contributions in 2017. We have no minimum funding obligation in either the Texas or New Mexico jurisdiction effective February 1, 2016 with PUCT Docket No. 44941 and July 1, 2016 with NMPRC Case No. 15-00127-UT, respectively. However, we continued to fund at the same funding levels of $0.4 million

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per month in 2016. We expect our funding requirements to change in the future based on amounts requested in our upcoming rate filings in both jurisdictions.

(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 four 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.

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 $119.9 million and $113.3 million as of December 31, 2016 and 2015, respectively. A hypothetical 10% increase in interest rates would reduce the fair values of these funds by $1.4 million and $1.2 million at December 31, 2016 and 2015, respectively.

Equity Price Risk

Our decommissioning trust funds include marketable equity securities of approximately $129.8 million and $117.5 million at December 31, 2016 and 2015, respectively. A hypothetical 20% decrease in equity prices would have reduced the fair values of these funds by $26.0 million and $23.5 million based on their fair values at December 31, 2016 and 2015, 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, 2017, 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.

48

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, 2016. 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, 2016, 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 51 of this report.

49

Item 8.Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	51
Balance Sheets as of December 31, 2016 and 2015	52
Statements of Operations for the years ended December 31, 2016, 2015, 2014	54
Statements of Comprehensive Operations for the years ended December  31, 2016, 2015, and 2014	55
Statements of Changes in Common Stock Equity for the years ended December  31, 2016, 2015, 2014	56
Statements of Cash Flows for the years ended December 31, 2016, 2015, 2014	57
Notes to Financial Statements	58

50

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

El Paso Electric Company:

We have audited the accompanying balance sheets of El Paso Electric Company (the Company) as of December 31, 2016 and 2015, 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, 2016. We also have audited El Paso Electric Company’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). El Paso Electric 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 these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. 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.

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.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of El Paso Electric Company as of December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles. Also in our opinion, El Paso Electric Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

/s/ KPMG LLP

Houston, Texas

February 24, 2017

51

EL PASO ELECTRIC COMPANY

BALANCE SHEETS

ASSETS (In thousands)	December 31,
	2016			2015
Utility plant:
Electric plant in service	$	3,791,566		$	3,616,301
Less accumulated depreciation and amortization	(1,244,332		)	(1,329,843		)
Net plant in service	2,547,234			2,286,458
Construction work in progress	154,738			293,796
Nuclear fuel; includes fuel in process of $57,315 and $51,854, respectively	194,842			190,282
Less accumulated amortization	(75,602		)	(75,031		)
Net nuclear fuel	119,240			115,251
Net utility plant	2,821,212			2,695,505
Current assets:
Cash and cash equivalents	8,420			8,149
Accounts receivable, principally trade, net of allowance for doubtful accounts of $2,156 and $2,046, respectively	88,452			66,326
Inventories, at cost	47,216			48,697
Under-collection of fuel revenues	11,123			—
Prepayments and other	8,988			9,872
Total current assets	164,199			133,044
Deferred charges and other assets:
Decommissioning trust funds	255,708			239,035
Regulatory assets	118,861			115,127
Other	16,298			17,896
Total deferred charges and other assets	390,867			372,058
Total assets	$	3,376,278		$	3,200,607

See accompanying notes to financial statements.

52

EL PASO ELECTRIC COMPANY

BALANCE SHEETS (Continued)

CAPITALIZATION AND LIABILITIES (In thousands except for share data)	December 31,
	2016			2015
Capitalization:
Common stock, stated value $1 per share, 100,000,000 shares authorized, 65,685,615 and 65,709,819 shares issued, and 137,017 and 118,834 restricted shares, respectively	$	65,823		$	65,829
Capital in excess of stated value	322,643			320,073
Retained earnings	1,114,561			1,067,396
Accumulated other comprehensive loss, net of tax	(7,116		)	(13,914		)
	1,495,911			1,439,384
Treasury stock, 25,304,914 and 25,384,834 shares, respectively, at cost	(421,515		)	(422,846		)
Common stock equity	1,074,396			1,016,538
Long-term debt, net of current portion	1,195,513			1,122,660
Total capitalization	2,269,909			2,139,198
Current liabilities:
Current maturities of long-term debt	83,143			—
Short-term borrowings under the revolving credit facility	81,574			141,738
Accounts payable, principally trade	62,953			59,978
Taxes accrued	32,488			30,351
Interest accrued	13,287			12,649
Over-collection of fuel revenues	255			4,023
Other	29,709			28,325
Total current liabilities	303,409			277,064
Deferred credits and other liabilities:
Accumulated deferred income taxes	555,066			495,237
Accrued pension liability	92,768			90,527
Accrued post-retirement benefit liability	34,400			54,553
Asset retirement obligation	81,800			81,621
Regulatory liabilities	18,435			24,303
Other	20,491			38,104
Total deferred credits and other liabilities	802,960			784,345
Commitments and contingencies
Total capitalization and liabilities	$	3,376,278		$	3,200,607

See accompanying notes to financial statements.

53

EL PASO ELECTRIC COMPANY

STATEMENTS OF OPERATIONS

(In thousands except for share data)

	Years Ended December 31,
	2016			2015			2014
Operating revenues	$	886,936		$	849,869		$	917,525
Energy expenses:
Fuel	173,738			188,400			251,005
Purchased and interchanged power	59,727			53,545			64,804
	233,465			241,945			315,809
Operating revenues net of energy expenses	653,471			607,924			601,716
Other operating expenses:
Other operations	242,014			242,950			238,832
Maintenance	66,746			65,223			65,629
Depreciation and amortization	84,317			89,824			83,342
Taxes other than income taxes	65,533			63,736			62,750
	458,610			461,733			450,553
Operating income	194,861			146,191			151,163
Other income (deductions):
Allowance for equity funds used during construction	7,023			10,639			14,662
Investment and interest income, net	14,083			17,508			13,633
Miscellaneous non-operating income	1,292			2,062			4,075
Miscellaneous non-operating deductions	(3,699		)	(4,328		)	(4,199		)
	18,699			25,881			28,171
Interest charges (credits):
Interest on long-term debt and revolving credit facility	71,544			65,851			59,028
Other interest	1,303			1,313			1,250
Capitalized interest	(4,990		)	(4,968		)	(5,092		)
Allowance for borrowed funds used during construction	(4,983		)	(6,937		)	(8,368		)
	62,874			55,259			46,818
Income before income taxes	150,686			116,813			132,516
Income tax expense	53,918			34,895			41,088
Net income	$	96,768		$	81,918		$	91,428
Basic earnings per share	$	2.39		$	2.03		$	2.27
Diluted earnings per share	$	2.39		$	2.03		$	2.27
Dividends declared per share of common stock	$	1.225		$	1.165		$	1.105
Weighted average number of shares outstanding	40,350,688			40,274,986			40,190,991
Weighted average number of shares and dilutive potential shares outstanding	40,408,033			40,308,562			40,211,717

See accompanying notes to financial statements.

54

EL PASO ELECTRIC COMPANY

STATEMENTS OF COMPREHENSIVE OPERATIONS

(In thousands)

	Years Ended December 31,
	2016			2015			2014
Net income	$	96,768		$	81,918		$	91,428
Other comprehensive income (loss):
Unrecognized pension and post-retirement benefit costs:
Net gain (loss) arising during period	(20,053		)	5,429			(54,328		)
Prior service benefit	32,697			824			34,200
Reclassification adjustments included in net income for amortization of:
Prior service benefit	(7,407		)	(6,574		)	(7,659		)
Net loss	4,965			8,622			6,182
Net unrealized gains/losses on marketable securities:
Net holding gains (losses) arising during period	8,444			(2,906		)	10,827
Reclassification adjustments for net gains included in net income	(7,640		)	(11,114		)	(7,350		)
Net losses on cash flow hedges:
Reclassification adjustment for interest expense included in net income	498			467			438
Total other comprehensive income (loss) before income taxes	11,504			(5,252		)	(17,690		)
Income tax benefit (expense) related to items of other comprehensive income (loss):
Unrecognized pension and post-retirement benefit costs	(4,261		)	(3,286		)	8,051
Net unrealized (gains) losses on marketable securities	(106		)	2,828			(760		)
Losses on cash flow hedges	(339		)	(203		)	(214		)
Total income tax benefit (expense)	(4,706		)	(661		)	7,077
Other comprehensive income (loss), net of tax	6,798			(5,913		)	(10,613		)
Comprehensive income	$	103,566		$	76,005		$	80,815

See accompanying notes to financial statements.

55

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, 2013	65,759,625		$	65,760		$	314,443		$	985,665		$	2,612		25,492,919		$	(424,647	)	$	943,833
Restricted common stock grants and deferred compensation	103,672		104			4,175														4,279
Stock awards withheld for taxes	(4,696	)	(5		)	(183		)												(188		)
Forfeited restricted common stock	(19,162	)	(19		)															(19		)
Deferred taxes on stock incentive plan						(302		)												(302		)
Compensation paid in shares	10,104		10			382														392
Net income									91,428											91,428
Other comprehensive income (loss)												(10,613		)						(10,613		)
Dividends declared									(44,556		)									(44,556		)
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

See accompanying notes to financial statements.

56

EL PASO ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(In thousands)

	Years Ended December 31,
	2016			2015			2014
Cash Flows From Operating Activities:
Net income	$	96,768		$	81,918		$	91,428
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service	84,317			89,824			83,342
Amortization of nuclear fuel	43,748			43,099			43,864
Deferred income taxes, net	50,510			30,846			39,129
Allowance for equity funds used during construction	(7,023		)	(10,639		)	(14,662		)
Other amortization and accretion	17,295			17,707			18,380
Gain on sale of property, plant and equipment	(545		)	(658		)	(2,092		)
Net gains on sale of decommissioning trust funds	(7,640		)	(11,114		)	(7,350		)
Other operating activities	1,279			517			(93		)
Change in:
Accounts receivable	(17,511		)	4,839			(5,815		)
Inventories	265			(2,859		)	(786		)
Net over-collection (under-collection) of fuel revenues	(14,891		)	13,344			(3,121		)
Prepayments and other	(1,184		)	(3,984		)	(2,750		)
Accounts payable	(2,140		)	(11,235		)	9,684
Taxes accrued	1,945			4,512			(2,209		)
Other current liabilities	2,022			3,719			1,198
Deferred charges and credits	(16,065		)	(3,165		)	(4,807		)
Net cash provided by operating activities	231,150			246,671			243,340
Cash Flows From Investing Activities:
Cash additions to utility property, plant and equipment	(225,361		)	(281,458		)	(277,078		)
Cash additions to nuclear fuel	(42,383		)	(41,966		)	(37,877		)
Capitalized interest and AFUDC:
Utility property, plant and equipment	(12,006		)	(17,576		)	(23,030		)
Nuclear fuel	(4,990		)	(4,968		)	(5,092		)
Allowance for equity funds used during construction	7,023			10,639			14,662
Decommissioning trust funds:
Purchases, including funding of $4.5 million	(99,497		)	(110,223		)	(117,675		)
Sales and maturities	91,268			102,567			108,311
Proceeds from sale of property, plant and equipment	4,841			721			2,395
Other investing activities	5,373			(470		)	4,192
Net cash used for investing activities	(275,732		)	(342,734		)	(331,192		)
Cash Flows From Financing Activities:
Dividends paid	(49,603		)	(47,059		)	(44,556		)
Borrowings under the revolving credit facility:
Proceeds	355,607			344,398			231,399
Payments	(415,771		)	(217,192		)	(231,219		)
Payment on maturing RGRT senior notes	—			(15,000		)	—
Proceeds from issuance of senior notes	157,052			—			149,468
Other financing activities	(2,432		)	(1,439		)	(2,328		)
Net cash provided by financing activities	44,853			63,708			102,764
Net increase (decrease) in cash and cash equivalents	271			(32,355		)	14,912
Cash and cash equivalents at beginning of period	8,149			40,504			25,592
Cash and cash equivalents at end of period	$	8,420		$	8,149		$	40,504

See accompanying notes to financial statements.

57

INDEX TO NOTES TO FINANCIAL STATEMENTS

	Page
Note A. Summary of Significant Accounting Policies	59
Note B. New Accounting Standards	62
Note C. Regulation	63
Note D. Regulatory Assets and Liabilities	68
Note E. Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant	69
Note F. Accounting for Asset Retirement Obligations	72
Note G. Common Stock	73
Note H. Accumulated Other Comprehensive Income (Loss)	78
Note I. Long-Term Debt and Financing Obligations	80
Note J. Income Taxes	82
Note K. Commitments, Contingencies and Uncertainties	85
Note L. Litigation	87
Note M. Employee Benefits	88
Note N. Franchises and Significant Customers	101
Note O. Financial Instruments and Investments	102
Note P. Supplemental Statements of Cash Flow Disclosures	107
Note Q. Selected Quarterly Financial Data (Unaudited)	108

58

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 generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company evaluates its estimates on an on-going basis, including those related to depreciation, unbilled revenue, income taxes, fuel costs, pension and other post-retirement obligations and asset retirement obligations ("ARO"). Actual results could differ from those estimates.

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 2016, 2015 and 2014 was 2.28%, 2.64%, and 2.60%, 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 in the most recent final orders from the Public Utility Commission of Texas ("PUCT") and the New Mexico Public Regulation Commission ("NMPRC") and changes in the estimated life of certain intangible software assets. See Part II, Item 8, Financial Statements and Supplementary Data, Note C and Note E.

Previously, the Company recorded gains and losses on the disposition of vehicles in earnings when realized. However, beginning in 2016, the Company began crediting the proceeds (salvage) on the disposition of vehicles to accumulated depreciation.

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 Nuclear 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.

59

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

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. AFUDC is compounded on a semi-annual basis. The average AFUDC rates used in 2016, 2015 and 2014 were 6.43%, 7.18% and 8.15%, 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. All temporary cash investments with an original maturity of three months or less are considered cash equivalents.

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 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 $21.0 million and $21.7 million as of December 31, 2016 and 2015, 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

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existing collections environment. Additions, deductions and balances for allowance for doubtful accounts for 2016, 2015 and 2014 are as follows (in thousands):

	2016		2015		2014
Balance at beginning of year	$	2,046	$	2,253	$	2,261
Additions:
Charged to costs and expense	2,427		2,057		2,755
Recovery of previous write-offs	1,395		1,613		1,516
Uncollectible receivables written off	3,712		3,877		4,279
Balance at end of year	$	2,156	$	2,046	$	2,253

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. Historically, 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. 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.

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 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.

Reclassification. Certain amounts in the Company's financial statements for 2015 have been reclassified to conform to the 2016 presentation. The Company implemented Accounting Standards Update ("ASU") 2015-03 and ASU 2015-17 in the first quarter of 2016, retrospectively to all periods presented in the Company's financial statements. See Part II, Item 8, Financial Statements and Supplementary Data, Note I and Note O for impact of ASU 2015-03, and Note J for impact of ASU 2015-17.

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B.New Accounting Standards

In May 2014, the FASB issuedASU2014-09, 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. Early adoption of ASU 2014-09 is permitted after December 15, 2016, however, the Company plans to adopt the new standard for reporting periods beginning after December 15, 2017.

Under the new standard, companies may use either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). The Company has not concluded which transition method it will elect but it currently anticipates using the modified retrospective approach.

The Company is currently in the process of evaluating the impact of the new standard on its various revenue and cash flow streams, including the evaluation of the impact, if any, on changes to business processes, systems and controls to support recognition and disclosure 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 not completed its final evaluation of tariff sales under the new guidance but currently does not anticipate that ASU 2014-09 will have a material impact on the Company's revenue recognition for such sales. The Company is still considering the impacts of the guidance on several industry-related accounting issues, including the accounting for contributions in aid of construction ("CIAC"), assessing the collectability criterion and the presentation of revenues associated with alternative revenue programs. The Company's initial assessment may change as we execute our implementation plan and new guidance is provided by the American Institute of Certified Public Accountants Power and Utilities Industry Task Force.

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 public companies for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Upon adoption of the new standard, the Company expects to record the cumulative effects as of January 1, 2018 which will result in an adjustment to accumulated other comprehensive income (losses) and retained earnings for unrealized gains (losses) related to equity securities owned by the Company. Had the Company been required to adopt the new standard at January 1, 2016, accumulated other comprehensive income would decrease by$28.8 millionand retained earnings would increase by a corresponding amount. Furthermore, the Company would report for the year ended December 31, 2016 an increase in investment income of$1.2 million, an increase in income tax expense of$0.2 millionand a decrease in other comprehensive income of$1.0 million. The Company is continuing to assess the future impact of this ASU.

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

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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, including the evaluation of 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 is unable to determine the impact this standard will have on the financial statements and related disclosures.

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. The Company will adopt the new standard effective January 1, 2017 and does not expect the effect of the adoption to be material to the Company's financial condition, results of operations or cash flows. The cumulative effect of the adoption of the new standard will be to increase net operating loss carryforward deferred tax assets and retained earnings by approximately$0.2 millionon January 1, 2017. The Company also expects to continue to account for its outstanding stock awards based on the equity method and therefore does not anticipate any changes in reporting related compensation expense.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326) ("ASU 2016-13"). 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. For public business entities, the provisions of ASU 2016-13 are effective for fiscal years and interim periods within that reporting period beginning after December 15, 2019. Early implementation is permitted as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. ASU 2016-13 will be applied in a modified-retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is implemented. The Company is currently assessing the future impact of 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 new guidance addresses the following classification issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon bonds; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. For public business entities, the provisions of ASU 2016-15 are effective for fiscal years and interim periods within that reporting period beginning after December 15, 2017. Early adoption is permitted, including adoption in an interim period. If an entity elects early adoption of ASU 2016-15 in an interim period, adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. 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 December 2016, the FASB issued ASU 2016-19, Technical Corrections and Improvements, which amends a number of Topics in the FASB ASC. This ASU is part of an ongoing FASB project to facilitate Codification updates for non-substantive technical corrections, clarifications, and improvements that are not expected to have a significant effect on accounting practice or create a significant administrative cost to most entities. Most of the amendments are effective upon issuance of ASU 2016-19 while certain amendments that require transition guidance are effective for the Company beginning January 1, 2017. The Company believes it is in compliance with those amendments that are effective immediately and that are applicable to the Company. The Company has not completed its evaluation of the new standard for amendments that require transition guidance.

C.    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,

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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 (the "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 "Unopposed Settlement"). On August 25, 2016, the PUCT approved the Unopposed Settlement and issued its final order in Docket No. 44941 (the "PUCT Final Order"), as proposed. The 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 millionrelated to Four Corners Generating Station ("Four Corners") costs, which will be collected through a surcharge terminating on July 12, 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 millionin rate case expenses through a separate surcharge and (v) allowing the Company to recover revenues associated with the relate back of rates to consumption on and after January 12, 2016 through March 31, 2016 through a separate surcharge.

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

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

2017 Texas Retail Rate Case Filing.On February 13, 2017, the Company filed with the City of El Paso, other municipalities incorporated in the Company's Texas service territory and the PUCT in Docket No.46831, a request for an increase in non-fuel base revenues of approximately$42.5 million. The Company invoked its statutory right to have its new rates relate back for consumption on and after July 18, 2017, which is the 155th day after the filing. The difference in rates that would have been billed will be surcharged or refunded to customers after the PUCT's final order in Docket No. 46831. The PUCT has the authority to require the Company to surcharge or refund such difference over a period not to exceed 18 months. The Company cannot predict the outcome or the timing of this rate case at this time.

Energy Efficiency Cost Recovery Factor. On May 1, 2015, the Company filed its annual application to establish its energy efficiency cost recovery factor for 2016. In addition to projected energy efficiency costs for 2016 and a true-up to prior year actual costs, the Company requested approval of a $1.0 millionbonus for the 2014 energy efficiency program results in accordance with PUCT rules. This case was assigned PUCT Docket No. 44677. A stipulation and settlement agreement was filed September 24, 2015 and the PUCT approved the settlement on November 5, 2015. The settlement approved by the PUCT included a performance bonus of $1.0 million. The Company recorded the performance bonus in operating revenues in the fourth quarter of 2015.

On April 29, 2016, the Company filed its annual application to establish its energy efficiency cost recovery factor for 2017. In addition to projected energy efficiency costs for 2017 and true-up to prior year actual costs, the Company requested approval of a$0.7 millionbonus for the 2015 energy efficiency program results in accordance with PUCT rules. This case was assigned PUCT Docket No. 45885. Parties in the proceeding, including PUCT staff and the City of El Paso, filed a settlement in the case that approved the Company's proposal with a reduction to the 2015 program bonus of $0.2 million. The PUCT approved the settlement on October 28, 2016. The settlement approved by the PUCT included a performance bonus of$0.5 millionwhich was recorded in operating revenues in the third quarter of 2016.

Fuel and Purchased Power Costs.The Company's actual fuel costs, including purchased power energy costs, are recovered from customers through a fixed fuel factor. The PUCT has adopted a fuel cost recovery rule (the "Texas Fuel Rule") that allows the Company to seek periodic adjustments to its fixed fuel factor. The Company can seek to revise its fixed fuel factor based upon the approved formula at least four months after its last revision except in the month of December. The Texas Fuel Rule requires the Company to request to refund fuel costs in any month when the over-recovery balance exceeds a threshold material amount and it expects fuel costs to continue to be materially over-recovered. The Texas Fuel Rule also permits the Company to seek to

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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 exceed4%of the previous twelve months' fuel costs. All such fuel revenue and expense activities are subject to periodic final review by the PUCT in fuel reconciliation proceedings.

On April 15, 2015, the Company filed a request, which was assigned PUCT Docket No. 44633, to reduce its fixed fuel factor by approximately 24% to reflect reduced fuel expenses primarily related to a reduction in the price of natural gas used to generate power. The over-recovered balance was below the PUCT's materiality threshold. The reduction in the fixed fuel factor was effective on an interim basis May 1, 2015 and approved by the PUCT on May 20, 2015.

On November 30, 2016, the Company filed a request, which was assigned PUCT Docket No. 46610, to increase its fixed fuel factor by approximately28.8%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 December 31, 2016, the Company had under-recovered fuel costs in the amount of$11.1 millionfor the Texas jurisdiction.

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 millionof Texas fuel and purchased power expenses incurred during the period of April 1, 2013 through March 31, 2016. A procedural schedule has been adopted with hearings in April 2017. As of December 31, 2016, Texas jurisdictional fuel and purchased power costs subject to a future Texas fuel reconciliation are approximately$114.4 million. The Company cannot predict the outcome or the timing of this matter.

Montana Power Station Approvals.The Company received Certificate of Convenience and Necessity ("CCN") approval from the PUCT to constructfournatural gas fired generating units at Montana Power Station ("MPS") in El Paso County, Texas. The Company also obtained air permits from the Texas Commission on Environmental Quality (the "TCEQ") and the U.S. Environmental Protection Agency (the "EPA"). MPS Units 1 and 2 and associated transmission lines and common facilities were completed and placed into service inMarch 2015. MPS Units 3 and 4 were completed and placed into service onMay 3, 2016andSeptember 15, 2016, respectively.

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 a3 MWsolar photovoltaic system located at MPS. Participation will be on a voluntary basis, and customers will contract for a set capacity (kW) amount and receive all energy produced. This case was assigned PUCT Docket No. 44800. The Company filed a settlement agreement among all parties on July 1, 2016 approving the program, and the PUCT approved the settlement agreement and program on September 1, 2016. The Company expects completion of the solar facility and commencement of the program in the second quarter of 2017.

Four Corners. On February 17, 2015, the Company and Arizona Public Service Company ("APS") entered into an asset purchase agreement (the "Purchase and Sale Agreement") providing for the sale of the Company's interest in Four Corners to APS.The sale of the Company's interest in Four Corners closed onJuly 6, 2016. See Part II, Item 8,Financial Statements and Supplementary Data, Note Efor further details on the sale of Four Corners.

On June 10, 2015, the Company filed an application in Texas requesting reasonableness and public interest findings and certain rate and accounting findings related to the Purchase and Sale Agreement. This case was assigned PUCT Docket No. 44805. Subsequent to the filing of the application, the case has been subject to numerous procedural matters, including a March 23, 2016 order in which the PUCT determined not to dismiss the reasonableness and public interest issues in this docket but to consider the requested rate and accounting findings, including mine reclamation costs, in 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, and the parties are engaged in settlement discussions.

At December 31, 2016, the regulatory asset associated with the Four Corners mine reclamation costs for the Company's Texas jurisdiction was approximately$7.3 million. The Company currently continues to recover its mine reclamation costs in Texas under previous orders and decisions of the PUCT. If any future determinations made by the Company's regulators result in changes to how existing regulatory assets or previously incurred costs for Four Corners are recovered in rates, any such changes would be recognized only when it becomes probable future cash flows will change as a result of such regulatory actions.

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

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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 millionin other service fees and a decrease in the Company's allowed return on equity to9.48%. 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.

Fuel and Purchased Power Costs. On January 8, 2014, the NMPRC approved the continuation of the Fuel and Purchased Power Cost Adjustment Clause (the "FPPCAC") without modification in NMPRC Case No. 13-00380-UT. Historically, fuel and purchased power costs were recovered through base rates and a FPPCAC that accounts for changes in the costs of fuel relative to the amount included in base rates. Effective July 1, 2016, with the implementation of the final order in Case No. 15-00127-UT, fuel and purchased power costs are no longer recovered through base rates 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. The Company recovers costs related to Palo Verde Unit 3 capacity and energy in New Mexico through the FPPCAC as purchased power using a proxy market price approved in Case No. 13-00380-UT. 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, 2016 that total approximately$114.6 million. At December 31, 2016, the Company had a net fuel over-recovery balance of$0.2 millionin New Mexico.

Montana Power Station Approvals.The Company received CCNs from the NMPRC to constructfourunits at MPS and the associated transmission lines. The Company also obtained all necessary air permits from the TCEQ and the EPA. A final order in NMPRC Case No. 13-00297-UT approving the CCN for MPS Units 3 and 4 was issued on June 11, 2014. MPS Units 1 and 2 and associated transmission lines and common facilities were completed and placed into service inMarch 2015. MPS Units 3 and 4 were completed and placed into service onMay 3, 2016andSeptember 15, 2016, respectively.

Four Corners.On June 15, 2016, in NMPRC Case No. 15-00109-UT, the NMPRC issued its final order approving the Company's sale and abandonment of its ownership interest in Four Corners to APS pursuant to a February 17, 2015 Purchase and Sale Agreement between the Company and APS.See Part II, Item 8,Financial Statements and Supplementary Data, Note Efor further details on the sale of Four Corners.

5 MW Holloman Air Force Base ("HAFB") Facility CCN.On October 7, 2015, in NMPRC Case No. 15-00185-UT, the NMPRC issued a final order approving a CCN for a5 MWsolar power generation facility located on HAFB in the Company's service territory in New Mexico. The Company and HAFB negotiated a special retail contract, which includes 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 second quarter of 2017.

Issuance of Long-Term Debt and Guarantee of Debt. On October 7, 2015 the Company received approval in NMPRC Case No. 15-00280-UT to issue up to$310.0 millionof new long-term debt and to guarantee the issuance of up to $65.0 millionof new debt by Rio Grande Resources Trust ("RGRT") to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. This approval supersedes prior approvals. Under this authorization, onMarch 24, 2016, the Company issued$150.0 millionaggregate principal amount of5.00%Senior Notes dueDecember 1, 2044. The net proceeds from the issuance of these senior notes, after deducting the underwriters' commission, were$158.1 million. These proceeds include accrued interest of$2.4 millionand a$7.1 millionpremium before expenses. These senior notes constitute an additional issuance of the Company's5.00%Senior Notes due2044, of which$150.0 millionwas previously issued onDecember 1, 2014, for a total principal amount outstanding of$300.0 million.

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

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Federal Regulatory Matters

Four Corners.On June 26, 2015, APS filed an application requesting authorization from FERC to purchase100%of the Company’s ownership interest in Units 4 and 5 of Four Corners and the associated transmission interconnection facilities and rights. On December 22, 2015, FERC issued an order approving the proposed transaction. The sale of the Company's interest in Four Corners closed onJuly 6, 2016. See Part II, Item 8,Financial Statements and Supplementary Data, Note Efor further details on the sale of Four Corners.

Revolving Credit Facility; Issuance of Long-Term Debt and Guarantee of Debt. On October 19, 2015, the FERC issued an order in Docket No. ES15-66-000 approving the Company’s filing to issue short-term debt under the revolving credit facility ("RCF") up to$400.0 million outstanding at any time, to issue up to$310.0 million in long-term debt, and to guarantee the issuance of up to $65.0 millionof new long-term debt by RGRT to finance future nuclear fuel purchases. The authorization is effective from November 15, 2015 through November 15, 2017. This approval supersedes prior approvals.

Under this authorization, on March 24, 2016, the Company issued$150.0 millionaggregate principal amount of5.00%Senior Notes dueDecember 1, 2044. Additionally under this authorization, on January 9, 2017, the Company exercised its option to extend the maturity of the RCF by one year toJanuary 14, 2020and to increase the size of the facility by$50.0 millionto$350.0 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$50.0 million(up to a total of$400.0 million) upon the satisfaction of certain conditions, more fully set forth in the agreement, including obtaining commitments from lenders or third party financial institutions. Additionally, the Company agreed to reduce the letters of credit commitment to$50.0 millionfrom a total commitment, under the RCF, of$350.0 million.

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

United States Department of Energy ("DOE"). The DOE regulates the Company's exports of power to the Comisión Federal de Electricidad in Mexico pursuant to a license andtwopresidential permits issued by the DOE.

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

Sales for Resale

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.

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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, 2016		December 31, 2015
Regulatory assets
Regulatory tax assets (a)	(b)	$	66,670	$	69,359
Loss on reacquired debt (c)	May 2035	15,780		16,632
Final coal reclamation (d)	(e)	9,581		9,520
Nuclear fuel postload daily financing charge	(e)	3,831		4,195
Unrecovered issuance costs due to reissuance of PCBs (c)	August 2042	794		827
Texas energy efficiency	(f)	—		25
Texas 2015 rate case costs	September 2018	2,670		1,882
Texas 2017 rate case costs	(g)	246		—
Texas relate back surcharge	(h)	6,455		—
New Mexico renewable energy credits and related costs (i)	June 2022	6,937		6,397
New Mexico 2010 FPPCAC audit	June 2019	398		434
New Mexico Palo Verde deferred depreciation	(b)	4,415		4,568
New Mexico 2015 rate case costs	June 2019	1,074		1,288
New Mexico 2017 rate case costs	(g)	10		—
Total regulatory assets		$	118,861	$	115,127
Regulatory liabilities
Regulatory tax liabilities (a)	(b)	$	10,648	$	17,266
Accumulated deferred investment tax credit (j)	(b)	3,328		4,011
Texas energy efficiency	(f)	1,288		—
New Mexico energy efficiency	(f)	2,159		2,238
Texas military base discount and recovery factor	(k)	184		788
New Mexico gain on sale of assets (l)	June 2019	828		—
Total regulatory liabilities		$	18,435	$	24,303

______________________________

(a) We do not earn a return on these items since the related accumulated deferred income tax assets and liabilities offset.

(b) The amortization periods for these assets and liabilities are based upon the life of the associated assets or liabilities.

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

(d) This item relates to coal reclamation costs associated with Four Corners. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.

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

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

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

(h) This item relates to the recovery of revenues through a separate surcharge beginning October 1, 2016 and ending September 30, 2017. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.

(i) This item relates to renewable energy credits and procurement plan costs, components approved for recovery in the New Mexico 2015 rate case.

(j) This item is excluded from rate base.

(k) 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.

(l) 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, 2016 (in thousands):

	Gross Plant		Accumulated Depreciation			Net Plant
Nuclear production	$	948,382	$	(320,000	)	$	628,382
Steam and other	926,419		(186,539		)	739,880
Total production	1,874,801		(506,539		)	1,368,262
Transmission	498,660		(259,488		)	239,172
Distribution	1,127,897		(365,601		)	762,296
General	205,866		(57,240		)	148,626
Intangible	84,342		(55,464		)	28,878
Total	$	3,791,566	$	(1,244,332	)	$	2,547,234

During 2016, depreciation decreased due to changes in rates approved in the PUCT Final Order and the NMPRC Final Order. The change, effective in January 2016 for Texas and July 2016 for New Mexico, reduced depreciation expense in 2016 by $10.9 million.

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). Effective July 2015, the Company changed the estimated useful life of certain large intangible software systems which decreased depreciation during 2015 by $1.8 million. 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):

2014	$	8,051
2015	6,482
2016	5,302
2017 (estimated)	5,148
2018 (estimated)	4,631
2019 (estimated)	4,242
2020 (estimated)	3,808
2021 (estimated)	3,227

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, 2016 and 2015 is as follows (in thousands):

	December 31, 2016						December 31, 2015
	Palo Verde			Other (a)			Palo Verde			Other (a)
Electric plant in service	$	948,382		$	67,621		$	917,483		$	229,627
Accumulated depreciation	(320,000		)	(44,377		)	(304,060		)	(181,886		)
Construction work in progress	50,598			1,895			48,938			9,528
Total	$	678,980		$	25,139		$	662,361		$	57,269

_______________

(a) 2015 other jointly-owned utility plant includes a 7% interest in Units 4 and 5 at Four Corners and certain other transmission facilities which the Company sold on July 6, 2016.

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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 threePalo 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, 2016, the Company’s decommissioning trust fund had a balance of $255.7 million, which is above its minimum funding level. The Company monitors the status of its decommissioning funds and adjusts its deposits, if necessary.

Decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers retained by APS. In December 2013, the Palo Verde Participants approved the 2013 Palo Verde decommissioning study (the "2013 Study"). The 2013 Study estimated that the Company must fund approximately $380.7 million (stated in 2013 dollars) to cover its share of decommissioning costs which was an increase in decommissioning costs of $23.3 million (stated in 2013 dollars) from the 2010 Palo Verde decommissioning study. However, because the cash flows from the 2013 Study were less than the inflated amounts from the 2010 Study, the effect of this change lowered the ARO by $1.9 million which lowered annual expenses starting in January 2014. Although the 2013 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. A 2016 Palo Verde decommissioning study (the "2016 Study") is underway and is expected to be finalized in the second quarter of 2017 at which time the Company will record its effects. If the expected cash flows as identified in the 2016 Study exceed the expected cash flows identified in the 2013 Study (stated in 2016 dollars), the ARO will increase with a corresponding increase in the ARO asset. Under such circumstances, increases in Palo Verde accretion expense and depreciation expense will occur. While the Company attempts to seek amounts in rates to meet its decommissioning obligations, it is not able to conclude given the evidence available to it now that it is probable these costs will continue to be collected over the period until decommissioning begins in 2044. The Company is ultimately responsible for these costs and its future actions combined with future decisions from regulators will determine how successful the Company is in this effort.    

Spent Nuclear Fuel and Waste Disposal. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "NWPA"), 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

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NOTES TO FINANCIAL STATEMENTS

Verde’s spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011. On August 18, 2014, APS and the DOE entered into a settlement agreement stipulating to a dismissal of the lawsuit and payment of $57.4 millionby the DOE to the Palo Verde Participants for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. On October 8, 2014, the Company received approximately$9.1 million, representing its share of the award, of which $7.9 million was refunded to customers through the applicable fuel adjustment clauses. On October 31, 2014, APS, acting on behalf of itself and the Palo Verde Participants, submitted to the government an additional request for reimbursement of spent nuclear fuel storage costs for the period July 1, 2011 through June 30, 2014. The accepted claim amount was$42.0 million. On June 1, 2015, the Company received approximately$6.6 million, representing its share of the award, of which $5.8 million was credited to customers through the applicable fuel adjustment clauses in March 2015. After June 2015, APS will file annual claims for the period July 1 of the then-previous year to June 30 of the then-current year. On November 2, 2015, APS filed a $12.0 million claim for the period July 1, 2014 through June 30, 2015. In February 2016, the DOE notified APS of the approval of the claim.The Company's share of this claim is approximately$1.9 million, of which $1.6 million was credited to customers through the applicable fuel adjustment clauses in March 2016. On October 31, 2016 APS filed an $11.3 million claim for the period July 1, 2015 through June 30, 2016. The Company's share of this claim is approximately$1.8 million. On February 1, 2017, the DOE notified APS of the approval of the claim. Any reimbursement is anticipated to be received in the second quarter of 2017, and the majority of the award received by the Company will be credited to customers through 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, and the proceeding has not been conclusively decided by the NRC or the courts.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 $12.9 million for the current policy period.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

Four Corners

On February 17, 2015, the Company and APS entered intothePurchase and Sale Agreementproviding for the sale of the Company’s interests in Four Corners to APS. Four Corners continued to provide energy to serve the Company's native load up to the closing date of the sale onJuly 6, 2016. Also on July 6, 2016, prior to the closing of the transaction, the Company and APS entered into an amendment to the Purchase and Sale Agreement pursuant to which APS assigned its right, title and interest in the Purchase and Sale Agreement to its affiliate 4C Acquisition, LLC ("APS's affiliate"), and Pinnacle West Capital Corporation, the parent company of APS and APS's affiliate ("Pinnacle West"), guaranteed APS's affiliate's obligations under the Purchase and Sale Agreement. The sales price was$32.0 million, which was based on the net book value as defined in the Purchase and Sale Agreement. The sales price was adjusted downward by$7.0 millionand$19.5 million, respectively, to reflect the assumption by APS's affiliate of the Company's obligation to pay for future plant decommissioning and mine reclamation expenses. The sales price was also adjusted downward by approximately$1.3 millionfor estimated closing adjustments and other assets and liabilities assumed by APS's affiliate. At the closing, the Company received approximately$4.2 millionin cash, subject to post-closing adjustments. No significant gain or loss was recorded after the closing date. 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 complies with the FASB guidance for ARO. 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 2013 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, spent fuel 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, 2016 is $255.7 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. In December 2013, the Company implemented the 2013 Palo Verde decommissioning study, and as a result, revised its ARO related to Palo Verde to decrease its estimated cash flows from the 2010 Study to the 2013 Study (see Part II, Item 8, Financial Statements and Supplementary Data, Note E). The assumptions used to calculate 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	3.60	%	6.20	%

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

An analysis of the activity of the Company’s total ARO liability from January 1, 2014 through December 31, 2016, including the effects of each year’s estimate revisions, is presented below. In 2016, the settled liabilities reflect the sale of the Company's interest in Four Corners including the related ARO. In 2014, the estimate revision includes an adjustment to Four Corners due to the early recognition of the obligation resulting from the Purchase and Sale Agreement with APS.

	2016			2015		2014
ARO liability at beginning of year	$	81,621		$	74,577	$	65,214
Liabilities incurred	—			189		—
Liabilities settled	(6,993		)	—		—
Revisions to estimate	—			—		3,561
Accretion expense	7,172			6,855		5,802
ARO liability at end of year	$	81,800		$	81,621	$	74,577

The Company has transmission and distribution lines which are operated under various property easement agreements. If the easements were to be released, 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 easements 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. 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 are fully vested and are expensed at fair value on the date of grant. Previously directors could elect to receive retainers and meeting fees in cash, restricted stock, or a combination of cash and stock. On May 29, 2014, the Board of Directors voted to revise the terms of the restricted stock awards granted to directors in lieu of cash for retainers and meeting fees. Stock elections by directors in lieu of cash for retainer and meeting fees are now fully vested and are expensed at fair value on the date of grant. The modification to 13,863 outstanding restricted stock awards granted to directors resulted in forfeiture of those awards and the granting of new awards which were fully vested and expensed at $37.81 per share, the fair value on the date of grant. Effective fiscal year ended December 31, 2015, other stock-based awards are not included in the tables below.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The expense, deferred tax benefit, and current tax expense recognized related to restricted stock and other stock-based awards in 2016, 2015 and 2014 is presented below (in thousands):

	2016		2015		2014
Expense (a)	$	2,594	$	2,755	$	3,471
Deferred tax benefit	908		964		1,215
Current tax benefit recognized	183		43		39

_____________________

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

The aggregate intrinsic value and fair value at grant date of restricted stock and other stock-based awards which vested in 2016, 2015 and 2014 is presented below (in thousands):

	2016		2015		2014
Aggregated intrinsic value	$	2,515	$	3,451	$	3,441
Fair value at grant date	1,993		3,327		3,330

The unvested restricted stock transactions for 2016 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, 2015	91,210		$	36.61
Stock awards	74,181		40.95
Vested	(55,503	)	35.91
Forfeitures	(495	)	36.88
Restricted shares outstanding at December 31, 2016	109,393		39.90		$	1,767	$	5,087

_______________________

(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.

The weighted average fair value per share at grant date for restricted stock and other stock-base awards granted during 2016, 2015 and 2014 were:

	2016		2015		2014
Weighted average fair value per share	$	40.95	$	37.17	$	36.95

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 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	—
February 18, 2014	0	%	0	954		2011-2013	—

In 2017, 2018 and 2019, subject to meeting certain performance criteria, additional performance shares could be awarded. 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. Excluding the 2014 award, the maximum number of shares that can be issued under the plan are 206,898 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 plan’s 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, 2015 (a)	130,136		$	32.72
Performance share awards	60,835		38.11
Performance shares expired	(24,527	)	34.69
Performance shares outstanding at December 31, 2016 (a)	166,444		34.40		$	2,189	$	7,740

_______________________

(a) On December 15, 2015, the Company issued a stock based retention grant to the Chief Executive Officer (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.

(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.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

A summary of information related to performance shares for 2016, 2015 and 2014 is presented below:

	2016		2015		2014
Weighted average per share grant date fair value per share of performance shares awarded	$	38.11	$	35.72	$	26.36
Compensation expense (in thousands) (a) (b)	1,655		1,042		1,181
Deferred tax benefit related to compensation expense (in thousands) (b)	579		365		413

_____________________

(a) Includes adjustments for estimated forfeitures.

(b) Includes CEO retention grant.

Repurchase Program

No shares of the Company's common stock were repurchased during the twelve months ended December 31, 2016. Detail regarding the Company's stock repurchase program are presented below:

	Since 1999 (a)		Authorized Shares
Shares repurchased (b)	25,406,184
Cost, including commission (in thousands)	$	423,647
Total remaining shares available for repurchase at December 31, 2016			393,816

______________________

(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 188,005 shares out of treasury stock during 2016.

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 30, 2016, the Company paid $12.6 million in quarterly cash dividends to shareholders. The Company paid a total of $49.6 million, $47.1 million and $44.6 million in cash dividends during the twelve months ended December 31, 2016, 2015 and 2014, respectively. On January 26, 2017, the Board of Directors declared a quarterly cash dividend of $0.31 per share payable on March 31, 2017 to shareholders of record as of the close of business on March 17, 2017.

76

EL PASO ELECTRIC COMPANY

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,
	2016			2015			2014
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	40,350,688			40,274,986			40,190,991
Dilutive effect of unvested performance awards	57,345			33,576			20,726
Diluted number of common shares outstanding	40,408,033			40,308,562			40,211,717
Basic net income per common share:
Net income	$	96,768		$	81,918		$	91,428
Income allocated to participating restricted stock	(321		)	(243		)	(301		)
Net income available to common shareholders	$	96,447		$	81,675		$	91,127
Diluted net income per common share:
Net income	$	96,768		$	81,918		$	91,428
Income reallocated to participating restricted stock	(321		)	(243		)	(301		)
Net income available to common shareholders	$	96,447		$	81,675		$	91,127
Basic net income per common share:
Distributed earnings	$	1.225		$	1.165		$	1.105
Undistributed earnings	1.165			0.865			1.165
Basic net income per common share	$	2.390		$	2.030		$	2.270
Diluted net income per common share:
Distributed earnings	$	1.225		$	1.165		$	1.105
Undistributed earnings	1.165			0.865			1.165
Diluted net income per common share	$	2.390		$	2.030		$	2.270

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,
	2016	2015	2014
Restricted stock awards	53,703	56,375	60,455
Performance shares (a)	47,246	66,804	96,208

_____________________

(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.

77

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, 2013		$	(21,330	)	$	36,240		$	(12,298	)	$	2,612
	Other comprehensive income (loss) before reclassifications	(12,628		)	8,694			—			(3,934		)
	Amounts reclassified from accumulated other comprehensive income (loss)	(926		)	(5,977		)	224			(6,679		)
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	)

78

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

Amounts reclassified from Accumulated Other Comprehensive Income (Loss) for the twelve months ended December 31, 2016, 2015 and 2014 are as follows (in thousands):

Details about Accumulated Other Comprehensive Income (Loss) Components		2016			2015			2014			Affected Line Item in the Statements of Operations
Amortization of pension and post-retirement benefit costs:
	Prior service benefit	$	7,407		$	6,574		$	7,659		(a)
	Net loss	(4,965		)	(8,622		)	(6,182		)	(a)
		2,442			(2,048		)	1,477			(a)
	Income tax effect	(1,020		)	810			(551		)	Income tax expense
		1,422			(1,238		)	926			Net income
Marketable securities:
	Net realized gain on sale of securities	7,640			11,114			7,350			Investment and interest income, net
		7,640			11,114			7,350			Income before income taxes
	Income tax effect	(1,434		)	(2,177		)	(1,373		)	Income tax expense
		6,206			8,937			5,977			Net income
Loss on cash flow hedge:
	Amortization of loss	(498		)	(467		)	(438		)	Interest on long-term debt and revolving credit facility
		(498		)	(467		)	(438		)	Income before income taxes
	Income tax effect	339			203			214			Income tax expense
		(159		)	(264		)	(224		)	Net income
	Total reclassifications	$	7,469		$	7,435		$	6,679

(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.

79

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

I.    Long-Term Debt and Financing Obligations

Outstanding long-term debt and financing obligations are as follows:

	December 31,
	2016			2015 (1)
	(In thousands)
Long-Term Debt:
Pollution Control Bonds (2):
7.25% 2009 Series A refunding bonds, due 2040 (7.46% effective interest rate)	$	62,619		$	62,582
4.50% 2012 Series A refunding bonds, due 2042 (4.63% effective interest rate)	58,471			58,441
7.25% 2009 Series B refunding bonds, due 2040 (7.49% effective interest rate)	36,492			36,465
1.875% 2012 Series A refunding bonds, due 2032 (2.35% effective interest rate)	33,193			33,011
Total Pollution Control Bonds	190,775			190,499
Senior Notes (3):
6.00% Senior Notes, net of discount, due 2035 (7.12% effective interest rate)	393,861			393,693
7.50% Senior Notes, net of discount, due 2038 (7.67% effective interest rate)	147,331			147,282
3.30% Senior Notes, net of discount, due 2022 (3.43% effective interest rate)	148,939			148,783
5.00% Senior Notes, net of discount, due 2044 (4.93% effective interest rate)	302,955			147,717
Total Senior Notes	993,086			837,475
RGRT Senior Notes (4):
4.47% Senior Notes, Series B, due 2017 (4.62% effective interest rate)	49,950			49,883
5.04% Senior Notes, Series C, due 2020 (5.16% effective interest rate)	44,845			44,803
Total RGRT Senior Notes	94,795			94,686
Total long-term debt	1,278,656			1,122,660
Financing Obligations:
Revolving Credit Facility ($81,574 due in 2017) (5)	81,574			141,738
Total long-term debt and financing obligations	1,360,230			1,264,398
Current Portion (amount due within one year):
Current maturities of long term debt	(83,143		)	—
Short-term borrowings under the revolving credit facility	(81,574		)	(141,738		)
	$	1,195,513		$	1,122,660

_____________________

(1) The Company implemented ASU 2015-03, Interest - Imputation of Interest, which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The impact of ASU 2015-03 on the Company's Balance Sheet was to reclassify $11.6 million of other deferred charges to long-term debt, net of current portion at December 31, 2015.

(2) Pollution Control Bonds ("PCBs")

The Company has four series of tax exempt unsecured PCBs in aggregate principal amount of $193.1 million. The 1.875% 2012 Series A (El Paso Electric Company Four Corners Project) Pollution Control Refunding Revenue Bonds with an aggregate principal amount of $33.3 million are subject to mandatory tender for purchase in September 2017 at which time the Company will either repay or remarket these bonds.

(3) 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

80

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

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.

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.

(4) 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 (the "Notes"). In August 2015, $15.0 million of these Notes matured and were paid with borrowings from the RCF. In August 2017, $50.0 million of these Senior Notes will mature. The Company will either repay or refinance this $50.0 million of Notes upon maturity. The Company guarantees the payment of principal and interest on the 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 Notes on February 15, and August 15 of each year until maturity. RGRT may redeem the 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 2016.

The sale of the 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 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 Notes and amounts borrowed from the RCF.

(5) 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

81

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

with certain covenants, including a total debt to capitalization ratio. The Company was in compliance with these requirements throughout 2016. In August 2015, $15.0 million aggregate principal amount of Series A 3.67% Senior Notes of RGRT matured and were paid utilizing borrowings under the RCF. As of December 31, 2016, the total amount borrowed by RGRT was $37.6 million for nuclear fuel under the RCF. As of December 31, 2016, $44.0 million of borrowings were outstanding under this facility for working capital and general corporate purposes. The weighted average interest rate on the RCF was 2.0% as of December 31, 2016.

As of December 31, 2016, the principal amount of scheduled maturities for the next five years of long-term debt are as follows (in thousands):

2017	$	83,300
2018	—
2019	—
2020	45,000
2021	—

The $37.6 million of borrowings outstanding on the RCF for nuclear fuel financing purposes is anticipated to be paid in 2017.

J.    Income Taxes

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2016 and 2015 are presented below (in thousands):

	December 31,
	2016			2015
Deferred tax assets:
Benefit of tax loss carryforwards	$	60,749		$	35,153
Alternative minimum tax credit carryforward	16,620			16,620
Pensions and benefits	57,756			61,673
Asset retirement obligation	26,929			28,042
Deferred fuel	—			1,488
Other	(200		)	15,421
Total gross deferred tax assets	161,854			158,397
Deferred tax liabilities:
Plant, principally due to depreciation and basis differences	(668,303		)	(608,738		)
Decommissioning	(43,463		)	(41,100		)
Deferred fuel	(3,962		)	—
Other	(1,192		)	(3,796		)
Total gross deferred tax liabilities	(716,920		)	(653,634		)
Net accumulated deferred income taxes	$	(555,066	)	$	(495,237	)

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

82

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The Company recognized income tax expense for 2016, 2015 and 2014 as follows (in thousands):

	Years Ended December 31,
	2016			2015			2014
Income tax expense:
Federal:
Current	$	2,642		$	2,319		$	(1,250	)
Deferred	47,909			32,819			38,810
Total federal income tax	50,551			35,138			37,560
State:
Current	766			1,730			3,209
Deferred	3,285			(1,650		)	641
Total state income tax	4,051			80			3,850
Generation (amortization) of accumulated investment tax credits	(684		)	(323		)	(322		)
Total income tax expense	$	53,918		$	34,895		$	41,088

As of December 31, 2016, the Company had $16.6 million of AMT credit carryforwards that have an unlimited life. As of December 31, 2016, the Company had $59.3 million of federal and $2.2 million of state tax loss carryforwards. If unused, both the federal and state tax loss carryforwards have lives of 20 years and 5 years respectively. As of December 31, 2016, the Company had $0.2 million of unrecognized tax benefits related to stock compensation which cannot be recognized until federal tax loss carryforwards are fully utilized.

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):

	Years Ended December 31,
	2016			2015			2014
Federal income tax expense computed on income at statutory rate	$	52,740		$	40,885		$	46,381
Difference due to:
State taxes, net of federal benefit	2,633			52			1,902
AEFUDC	(475		)	(2,345		)	(3,757		)
Permanent tax differences	(2,369		)	(2,898		)	(2,921		)
Other	1,389			(799		)	(517		)
Total income tax expense	$	53,918		$	34,895		$	41,088
Effective income tax rate	35.8		%	29.9		%	31.0		%

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

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 final orders from the PUCT and the NMPRC in its 2015 rate cases, effective January 1, 2016. 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 $5.1 million for the year ended December 31, 2016.

83

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

In November 2015, the FASB issued new guidance (ASU 2015-17, Balance Sheet Classification of Deferred Taxes) to simplify the presentation of deferred income taxes. ASU 2015-17 requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. ASU 2015-17 can be applied prospectively or retrospectively and is effective for financial statements issued for annual periods beginning after December 15, 2016 and interim periods within those annual periods and early adoption is permitted. The Company elected to implement ASU 2015-17 on a retrospective basis for financial statements issued beginning March 31, 2016. The implementation of ASU 2015-17 did not have a material impact on the Company's results of operations. The impact of ASU 2015-17 on the Company's Balance Sheet was to reclassify $21.6 million of current deferred tax assets to long-term deferred tax liabilities at December 31, 2015.

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 $0.4 million (net of an increase of $0.5 million), an unrecognized tax position of $0.8 million, and $2.1 million, in 2016, 2015, and 2014 respectively, related to transmission and distribution costs and other amounts deducted in current and prior year Texas franchise tax returns. The Company recorded a decrease of $0.3 million in 2016 and a decrease of $1.3 million (net of an increase of $0.4 million) in 2014 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, 2016, 2015 and 2014 amounts of unrecognized tax benefits are as follows (in thousands):

	2016			2015		2014
Balance at January 1	$	6,000		$	5,200	$	7,200
Additions for tax positions related to the current year	400			500		300
Reductions for tax positions related to the current year	—			—		—
Additions for tax positions of prior years	100			300		2,200
Reductions for tax positions of prior years	(1,200		)	—		(4,500		)
Balance at December 31	$	5,300		$	6,000	$	5,200

If recognized, $2.6 million of the unrecognized tax position at December 31, 2016, would reduce the effective tax rate. The Company recognized an income tax benefit for the decrease in unrecognized tax positions of $0.7 million for the year ended December 31, 2016.

The Company recognizes in tax expense interest and penalties related to tax benefits that have not been recognized. For the years ended December 31, 2016, 2015, and 2014 the Company recognized interest expense of $0.1 million, $0.2 million, and $0.1 million, respectively. The Company had approximately $0.8 million and $0.7 million accrued for the payment of interest and penalties at December 31, 2016 and 2015, respectively.

84

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 June 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 April 2034	May 2014
Power Purchase Agreement	Newman Solar LLC		10	MW	December 2014 through November 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.

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.

85

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 millionfor environmental mitigation projects. At December 31, 2016, the Company has accrued its remaining unpaid share of approximately$0.2 millionrelated to this matter.

New Mexico Tax Matter Related to Coal Supplied to Four Corners

On May 23, 2013, the New Mexico Taxation and Revenue Department ("NMTRD") issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30.0 million related to coal supplied under the coal supply agreement for Four Corners (the "Assessment"). The Company's share of the Assessment is approximately $1.5 million. On behalf of the Four Corners participants, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with respect to that partial payment in August 2013. The NMTRD denied the refund claim. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed complaints with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial. On June 30, 2015, the court ruled that the Assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statute. The NMTRD filed a Notice of Appeal on August 31, 2015 with respect to the decision. Thereafter, APS and the coal supplier entered into a final settlement agreement with the NMTRD with respect to the Assessment. Pursuant to the final settlement agreement, the NMTRD agreed to release the Assessment, dismiss its filed appeal, and release its rights to any other surtax claims with respect to the coal supply agreement. APS and the other Four Corners participants agreed to forgo refund rights with respect to all the contested amounts previously paid under the applicable tax statute, in addition to a $1.0 million settlement payment. The Company paid its share of this settlement, approximately $47,000, in April 2016.

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 4 years. The Company has transmission and distribution lines which are operated under various property easement agreements. The majority of these easements include renewal options which the Company routinely exercises. These lease agreements 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.

86

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The Company's total annual rental expense related to operating leases was $1.7 million, $1.9 million, and $1.8 million for 2016, 2015 and 2014, respectively. As of December 31, 2016, the Company’s minimum future rental payments for the next five years are as follows (in thousands):

2017	$	808
2018	662
2019	666
2020	664
2021	562

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.

L.    Litigation

The Company is involved in various legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. The Company regularly analyzes current information and, as necessary, makes provisions in its financial statements for probable liabilities for the eventual disposition of these matters. While the outcome of these matters cannot be predicted with certainty, based upon a review of the matters and applicable insurance coverage, the Company believes that none of these matters will have a material adverse effect on the financial position, results of operations or cash flows of the Company. The Company expenses legal costs, including expenses related to loss contingencies, as they are incurred.

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.

87

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 collected from customers in the Company's Texas and New Mexico jurisdictions and the annual 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 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.

During the quarter ended March 31, 2014, the Company implemented certain amendments to the Retirement Plan and Excess Benefit Plan. In the first quarter of 2014, the Company offered a cash balance pension plan as an alternative to its current final average pay pension plan for employees hired prior to January 1, 2014. The cash balance pension plan also included an enhanced employer matching contribution to the employee’s respective 401(k) Defined Contribution Plan (discussed below). For employees that elected the new cash balance feature of the plans, the pension benefit earned under the existing final average pay feature of the plans was frozen as of March 31, 2014. Employees hired after January 1, 2014 were automatically enrolled in the cash balance pension plan. The amendments to the plans were effective April 1, 2014. As a result of these actions, the Company remeasured the assets and liabilities of the plans, based on actuarially determined estimates, using the close of the alternative choice election period of February 28, 2014, as the remeasurement date.

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 plan covers employees beginning on their employment commencement date or re-employment commencement date in any plan year in which the employee completes at least a minimum number of hours of service. Retirement benefits under the cash balance pension plan are based on the employee’s cash balance account, consisting of pay credits and interest credits.

The Company complies with the FASB guidance on disclosure for pension and other post-retirement plans that requires disclosure of investment policies and strategies, categories of investment and fair value measurements of plan assets, and significant concentrations of risk.

88

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

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

	December 31,
	2016						2015
	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	$	325,706		$	26,958		$	341,133		$	28,397
Service cost	7,705			296			8,530			262
Interest cost	12,161			878			13,477			1,018
Actuarial (gain) loss	7,988			1,267			(19,290		)	(810		)
Benefits paid	(15,792		)	(1,937		)	(18,144		)	(1,909		)
Benefit obligation at end of year	337,768			27,462			325,706			26,958
Change in plan assets:
Fair value of plan assets at end of prior year	260,035			—			272,939			—
Actual return (loss) on plan assets	18,223			—			(3,760		)	—
Employer contribution	7,300			1,937			9,000			1,909
Benefits paid	(15,792		)	(1,937		)	(18,144		)	(1,909		)
Fair value of plan assets at end of year	269,766			—			260,035			—
Funded status at end of year	$	(68,002	)	$	(27,462	)	$	(65,671	)	$	(26,958	)

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

	December 31,
	2016						2015
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Current liabilities	$	—		$	(2,696	)	$	—		$	(2,102	)
Noncurrent liabilities	(68,002		)	(24,766		)	(65,671		)	(24,856		)
Total	$	(68,002	)	$	(27,462	)	$	(65,671	)	$	(26,958	)

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

	December 31,
	2016						2015
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Projected benefit obligation	$	(337,768	)	$	(27,462	)	$	(325,706	)	$	(26,958	)
Accumulated benefit obligation	(314,071		)	(25,550		)	(302,446		)	(25,785		)
Fair value of plan assets	269,766			—			260,035			—

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

	Years Ended December 31,
	2016						2015
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Net loss	$	121,052		$	10,073		$	118,963		$	9,592
Prior service benefit	(23,877		)	(185		)	(27,344		)	(224		)
Total	$	97,175		$	9,888		$	91,619		$	9,368

89

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

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

	December 31,
	2016						2015
			Non-Qualified						Non-Qualified
	Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan		Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan
Discount rate	4.29	%	3.76	%	4.34	%	4.57	%	3.99	%	4.59	%
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 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, 2016 retirement plans' projected benefit obligation by 11.5%. A 1% decrease in the discount rate would increase the December 31, 2016 retirement plans' projected benefit obligation by 14.1%.

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

	Years Ended December 31,
	2016						2015						2014
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Service cost	$	7,705		$	296		$	8,530		$	262		$	8,284		$	303
Interest cost	12,161			878			13,477			1,018			14,001			1,041
Expected return on plan assets	(18,879		)	—			(19,795		)	—			(18,699		)	—
Amortization of:
Net loss	6,554			785			9,710			937			8,178			675
Prior service benefit	(3,467		)	(39		)	(3,467		)	(39		)	(2,889		)	(17		)
Net periodic benefit cost	$	4,074		$	1,920		$	8,455		$	2,178		$	8,875		$	2,002

In 2016,the Companychanged the method used to estimate the service and interest components of net periodic benefit cost forpensionbenefits. This change, compared to the previous method, resulted in a decrease in the service cost and interest cost components in 2016, and is expected to result in a decrease in the service cost and interest cost components in future periods. Historically,the Companyestimated 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 Companyelected 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 believesthe 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 Companyaccounted for this change as a change in accounting estimate and accordingly, accounted for this prospectively. The change in estimate decreased the service and interest components of net periodic benefit costin 2016 by approximately$2.9 million.

90

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

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

	Years Ended December 31,
	2016						2015						2014
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Net (gain) loss	$	8,644		$	1,266		$	4,266		$	(811	)	$	47,324		$	3,508
Prior service benefit	—			—			—			—			(33,700		)	(500		)
Amortization of:
Net loss	(6,554		)	(785		)	(9,710		)	(937		)	(8,178		)	(675		)
Prior service benefit	3,467			39			3,467			39			2,889			17
Total recognized in other comprehensive income	$	5,557		$	520		$	(1,977	)	$	(1,709	)	$	8,335		$	2,350

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

	Years Ended December 31,
	2016				2015				2014
	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	$	9,631	$	2,440	$	6,478	$	469	$	17,210	$	4,352

The following are amounts in accumulated other comprehensive income that are expected to be recognized as components of net periodic benefit cost during 2017 (in thousands):

	Retirement Income Plan			Non-Qualified Retirement Plans
Net loss	$	7,530		$	825
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 endedDecember 31:

	2016						2015						2014 (a)
			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	4.57	%	3.99	%	4.63	%	4.0	%	3.4	%	4.1	%	4.9	%	3.9	%	4.9	%
Service cost	4.83	%	N/A		4.87	%	4.0	%	N/A		4.1	%	4.9	%	N/A		4.9	%
Interest cost	3.86	%	3.04	%	3.9	%	4.0	%	3.4	%	4.1	%	4.9	%	3.9	%	4.9	%
Expected long-term return on plan assets	7.0	%	N/A		N/A		7.5	%	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	%	4.75	%	N/A		4.75	%

 _____________________

(a) The Retirement Plan and the Excess Benefit Plan were remeasured on February 28, 2014 due to the above mentioned plan amendment. The discount rate used to remeasure the benefit obligation was 4.6% for the Retirement Plan and 4.5% for the Excess Benefit Plan, compared to 4.9% for both plans as of January 1, 2014. All other assumptions remained consistent with assumptions used at January 1, 2014.

91

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The Company’s overall expected long-term rate of return on assets is 7.0% effective January 1, 2016 and January 1, 2017, 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, 2016
Equity securities	50	%
Fixed income	40	%
Alternative investments	10	%
Total	100	%

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. 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.

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 NAV provided by the administrator of the fund. The NAV price is quoted on a restrictive market although the underlying investments are traded on active markets. During the third quarter of 2016, the Company concluded that the NAV used for determining the fair value of the investments in the Common Collective Trusts have readily determinable fair values. Accordingly, such fund values have been re-categorized from Level 2 to Level 1 hierarchy.

Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. 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.

92

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The fair value of the Company’s Retirement Plan assets at December 31, 2016 and 2015, 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, 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	$	—	$	—

Description of Securities	Fair Value as of December 31, 2015		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Cash and Cash Equivalents	$	1,266	$	1,266	$	—	$	—
Common Collective Trusts (a)
Equity funds	144,279		144,279		—		—
Fixed income funds	103,877		103,877		—		—
Real Estate Funds	2,025		2,025		—		—
Total Common Collective Trusts	250,181		250,181		—		—
Limited Partnership Interest in Real Estate (b)(c)	8,588
Total Plan Investments	$	260,035	$	251,447	$	—	$	—

 _____________________

(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 guidance. 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. ASU 2015-07 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years.

93

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, 2014	$	8,748
Unrealized loss in fair value	(160		)
Balances at December 31, 2015	8,588
Sale of land	(775		)
Unrealized loss in fair value	(822		)
Balances at December 31, 2016	$	6,991

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, 2016 and 2015. 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, 2016 and 2015.

The Company adheres 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 seeks 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 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 Company expects to contribute at least $10.0 million to its retirement plans in 2017.

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
2017	$	16,113	$	2,698
2018	19,080		2,060
2019	18,771		2,025
2020	18,923		1,957
2021	19,755		1,907
2022-2026	107,916		8,949

401(k) Defined Contribution Plans

The Company sponsors 401(k) defined contribution plans covering substantially all employees. Annual matching contributions made to the savings plans for the years 2016, 2015 and 2014 were $4.1 million, $3.9 million, and $3.0 million, respectively. Historically, the Company had provided a 50 percent matching contribution up to 6 percent of the employee’s compensation subject to certain other limits and exclusions. Effective April 1, 2014, for employees who enrolled in the cash balance pension plan (discussed above), the Company provided a 100 percent matching contribution up to 6 percent of the employee's compensation subject to certain other limits and exclusions.

Other Post-retirement Benefits

The Company provides certain health care benefits for retired employees and their eligible dependents and life insurance benefits for retired employees only. Substantially all of the Company’s employees may become eligible for those benefits if they retire while working for the Company. Contributions from the Company are based on various factors such as the Plan's funded status, the IRS tax deductible limit, state and federal regulatory requirements, amounts collected from customers in the Company's Texas and New Mexico jurisdictions and the annual cost of the Plan, as actuarially calculated. The assets of the plan are primarily invested in institutional funds which hold equity securities, debt securities, and cash equivalents and are managed by a professional investment manager appointed by the Company.

94

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The following table contains a reconciliation of the change in the benefit obligation, the fair value of plan assets, and the funded status of the plan (in thousands):

	December 31,
	2016			2015
Change in benefit obligation:
Benefit obligation at end of prior year	$	92,643		$	100,700
Service cost	2,769			3,454
Interest cost	3,167			4,035
Actuarial loss (gain)	10,751			(11,423		)
Amendment (a) (b)	(32,697		)	(824		)
Benefits paid	(4,428		)	(4,544		)
Retiree contributions	1,310			1,245
Benefit obligation at end of year	73,515			92,643
Change in plan assets:
Fair value of plan assets at end of prior year	38,090			41,358
Actual return (loss) on plan assets	2,443			(469		)
Employer contribution	1,700			500
Benefits paid	(4,428		)	(4,544		)
Retiree contributions	1,310			1,245
Fair value of plan assets at end of year	39,115			38,090
Funded status at end of year	$	(34,400	)	$	(54,553	)

_____________________

(a) During October 2016, the Company approved and communicated a plan amendment that resulted in a remeasurement of the Company's 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 were covered by a fully insured Medicare advantage plan.

(b) Amendment relates to modification of the Company's Other Post-retirement Benefit Plan which increased mail order co-payments for post age 65. The amendment was approved in 2015 and became effective January 1, 2016.

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

	December 31,
	2016			2015
Current liabilities	$	—		$	—
Noncurrent liabilities	(34,400		)	(54,553		)
Total	$	(34,400	)	$	(54,553	)

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

	December 31,
	2016			2015
Net gain	$	(26,285	)	$	(38,802	)
Prior service benefit	(41,009		)	(12,213		)
Total	$	(67,294	)	$	(51,015	)

95

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

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

	December 31,
	2016		2015
Discount rate at end of year	4.36	%	4.59	%
Health care cost trend rates:
Initial
Pre-65 medical	6.50	%	7.00	%
Post-65 medical	4.50	%	7.00	%
Pre-65 drug	7.50	%	7.00	%
Post-65 drug	10.50	%	7.00	%
Ultimate	4.50	%	4.50	%
Year ultimate reached (a)	2026		2026

_____________________ (a) Pre-65 medical reaches the ultimate trend rate in 2025. Additionally, the Post-65 medical trend is assumed to be 4.50% for all years into the future.

The discount rate is reviewed 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, 2016 accumulated post-retirement benefit obligation by 13.1%. A 1% decrease in the discount rate would increase the December 31, 2016 accumulated post-retirement benefit obligation by 16.7%.

Net periodic benefit cost is made up of the components listed below (in thousands):

	Years Ended December 31,
	2016			2015			2014
Service cost	$	2,769		$	3,454		$	2,845
Interest cost	3,167			4,035			4,463
Expected return on plan assets	(1,835		)	(2,070		)	(2,116		)
Amortization of:
Prior service benefit	(3,901		)	(3,068		)	(4,753		)
Net gain	(2,374		)	(2,025		)	(2,671		)
Net periodic benefit cost	$	(2,174	)	$	326		$	(2,232	)

In 2016,the Companychanged the method used to estimate the service and interest components of net periodic benefit cost forother post-retirementbenefits. This change, compared to the previous method, resulted in a decrease in the service cost and interest cost components in 2016, and is expected to result in a decrease in the service cost and interest cost components in future periods. Historically,the Companyestimated 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 Companyelected 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 believesthe 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 Companyaccounted for this change as a change in accounting estimate and accordingly, accounted for this prospectively. The change in estimate decreased the service and interest components of net periodic benefit costin 2016 by approximately$0.8 million.

96

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

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

	Years Ended December 31,
	2016			2015			2014
Net (gain) loss	$	10,143		$	(8,884	)	$	3,496
Prior service benefit	(32,697		)	(824		)	—
Amortization of:
Prior service benefit	3,901			3,068			4,753
Net gain	2,374			2,025			2,671
Total recognized in other comprehensive income	$	(16,279	)	$	(4,615	)	$	10,920

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

	Years Ended December 31,
	2016			2015			2014
Total recognized in net periodic benefit cost and other comprehensive income	$	(18,453	)	$	(4,289	)	$	8,688

The amount in accumulated other comprehensive income that is expected to be recognized as a component of net periodic benefit cost during 2017 is a prior service benefit of $6.2 million and a net gain of $1.6 million.

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

	2016 (a)				2015		2014
Discount rate:	January 1 - September 30		October 1 - December 31
Benefit obligation	4.59	%	3.75	%	4.1	%	4.9	%
Service cost	4.91	%	4.03	%	4.1	%	4.9	%
Interest cost	3.86	%	3.15	%	4.1	%	4.9	%
Expected long-term return on plan assets	4.875%				5.2	%	5.2	%
Health care cost trend rates:
Initial	7.00%				7.25	%	7.5	%
Ultimate	4.5%				4.5	%	4.5	%
Year ultimate reached	2026				2026		2026

_____________________

(a) The actuarial assumptions are evaluated by the Company at each measurement date. The Other Post-retirement Benefits Plan was remeasured at October 1, 2016 due to a plan amendment.

For measurement purposes, a 7.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2016. The rate was assumed to decrease gradually to 4.5% for 2026 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. The effect of a 1% change in these assumed health care cost trend rates would increase or decrease the December 31, 2016 benefit obligation by $11.2 million or $9.0 million, respectively. In addition, a 1% change in said rate would increase or decrease the aggregate 2016 service and interest cost components of the net periodic benefit cost by $1.3 million or $1.0 million, respectively.

97

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The Company’s overall expected long-term rate of return on assets, on an after-tax basis, is 4.875% effective January 1, 2016 and January 1, 2017. The expected long-term rate of return is based on the after-tax weighted average of the expected returns on investments based upon the target asset allocation. The Company’s target allocations for the plan’s assets are presented below:

	December 31, 2016
Equity securities	65	%
Fixed income	30	%
Alternative investments	5	%
Total	100	%

The Other Post-retirement Benefit Plan invests the majority of its plan assets in institutional funds which includes a diversified portfolio of domestic and international equity securities and fixed income securities. The asset portfolio also includes cash equivalents and a real estate limited partnership. The expected rates of return 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 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.

The FASB guidance on disclosure for other post-retirement benefit 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 Other Post-retirement Benefits Plan are primarily obtained from independent pricing services. These prices are based on observable market data. The institutional funds are valued using the NAV provided by the administrator of the fund. The NAV price is quoted on a restrictive market although the underlying investments are traded on active markets. During the third quarter of 2016, the Company concluded that the NAV used for determining the fair value of the investments in the institutional funds have readily determinable fair values. Accordingly, such fund values have been re-categorized from Level 2 to Level 1 hierarchy.

• Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. 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.

98

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The fair value of the Company’s Other Post-retirement Benefits Plan assets at December 31, 2016 and 2015, 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, 2016		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Institutional Funds (a)
Equity funds	$	26,133	$	26,133	$	—	$	—
Fixed income funds	11,671		11,671		—		—
Total Institutional Funds	37,804		37,804		—		—
Limited Partnership Interest in Real Estate (b) (c)	1,311
Total Plan Investments	$	39,115	$	37,804	$	—	$	—
Description of Securities	Fair Value as of December 31, 2015		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Institutional Funds (a)
Equity funds	$	24,881	$	24,881	$	—	$	—
Fixed income funds	11,599		11,599		—		—
Total Institutional Funds	36,480		36,480		—		—
Limited Partnership Interest in Real Estate (b) (c)	1,610
Total Plan Investments	$	38,090	$	36,480	$	—	$	—

 ___________________

(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.

(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 of 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 guidance. 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. ASU 2015-07 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years.

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

	Fair Value of Investments  in Real Estate
Balance at December 31, 2014	$	1,640
Unrealized loss in fair value	(30		)
Balance at December 31, 2015	1,610
Sale of land	(145		)
Unrealized loss in fair value	(154		)
Balance at December 31, 2016	$	1,311

99

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

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, 2016 and 2015. 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, 2016 and 2015.

The Company adheres 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 seeks 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 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 ERISA and DOL regulations.

The Company expects to contribute $1.5 million to its other post-retirement benefits plan in 2017. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):

2017	$	2,622
2018	2,880
2019	3,057
2020	3,320
2021	3,510
2022-2026	20,084

Annual Short-Term Incentive Plan

The Annual Short-Term Incentive Plan (the "Incentive Plan") provides for the payment of cash awards to eligible Company employees, including each of its named executive officers. Payment of awards is based on the achievement of performance measures reviewed and approved by the Company’s Board of Directors’ Compensation Committee. Generally, these performance measures are based on meeting certain financial, operational and individual performance criteria. The financial performance goals are based on earnings per share and the operational performance goals are based on compliance, customer satisfaction, and reliability. If a specified level of earnings per share is not attained, no amounts will be paid under the Incentive Plan, unless the Compensation Committee determines otherwise. In 2016, the Company reached the required levels of earnings per share, customer satisfaction, reliability, compliance, and safety goals for an incentive payment of $12.5 million. In 2015 and 2014, the Company reached the required levels of earnings per share, safety, compliance, and customer satisfaction goals for an incentive payment of $10.5 million and $7.4 million, respectively. The Company has renewed the Incentive Plan in 2017 with similar goals.

100

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

N.     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 to4.00%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 at3.25%of gross revenues, but the 2010 amendment added an incremental fee equal to0.75%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 onJuly 31, 2030.

The Company does not have a written franchise agreement with the City of Las Cruces, the second largest city in its service territory. The Company provides electric distribution service to the City of Las Cruces under an implied franchise by satisfying all obligations under the franchise agreement that expired onApril 30, 2009. The Company pays the City of Las Cruces a franchise fee of2.00%of gross revenues the Company receives from services within the City of Las Cruces.

Military Installations

The Company serves HAFB, White Sands Missile Range ("White Sands") and Fort Bliss. These military installations represent approximately2.8% 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 provided under the applicable New Mexico tariffs.

101

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

O.     Financial Instruments and Investments

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

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

	December 31,
	2016				2015
	Carrying Amount (1)		Estimated Fair Value		Carrying Amount (1)		Estimated Fair Value
Pollution Control Bonds	$	190,775	$	206,818	$	190,499	$	212,624
Senior Notes	993,086		1,112,285		837,475		829,864
RGRT Senior Notes (2)	94,795		98,855		94,686		100,345
RCF (2)	81,574		81,574		141,738		141,738
Total	$	1,360,230	$	1,499,532	$	1,264,398	$	1,284,571

 __________________

(1) The Company implemented ASU 2015-03, Interest - Imputation of Interest, which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The impact of ASU 2015-03 on the Company's Balance Sheet was to reclassify $11.6 million of other deferred charges to long-term debt, net of current portion at December 31, 2015.

(2) Nuclear fuel financing, as of December 31, 2016 and December 31, 2015, is funded through the $95 million RGRT Senior Notes and $37.6 million and $33.7 million, respectively under the RCF. As of December 31, 2016, $44.0 million was outstanding under the RCF for working capital or general corporate purposes. As of December 31, 2015, $108.0 million amount was outstanding under the RCF for working capital or general corporate purposes. The interest rate on the Company’s borrowings under the RCF is reset throughout the period reflecting current market rates. Consequently, the carrying value approximates fair value.

Treasury Rate Locks. The Company entered into treasury rate lock agreements in 2005 to hedge against potential movements in the treasury reference interest rate pending the issuance of the 6% Senior Notes. The treasury rate lock agreements met the criteria for hedge accounting and were designated as a cash flow hedge. In accordance with cash flow hedge accounting, the Company recorded the loss associated with the fair value of the cash flow hedge, net of tax, as a component of accumulated other comprehensive loss and amortizes the accumulated comprehensive loss to earnings as interest expense over the life of the 6% Senior Notes. In 2017, approximately $0.5 million of this accumulated other comprehensive loss item will be reclassified to interest expense.

Contracts and Derivative Accounting. The Company uses commodity contracts to manage its exposure to price and availability risks for fuel purchases and power sales and purchases and these contracts generally have the characteristics of derivatives. The Company does not trade or use these instruments with the objective of earning financial gains on the commodity price fluctuations. The Company has determined that all such contracts outstanding at December 31, 2016, except for certain natural gas commodity contracts with optionality features, that had the characteristics of derivatives met the "normal purchases and normal sales" exception provided in the FASB guidance for accounting for derivative instruments and hedging activities, and, as such, were not required to be accounted for as derivatives.

102

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

Marketable Securities. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair value which was $255.7 million and $239.0 million at December 31, 2016 and 2015, respectively. These securities are classified as available for sale and recorded at their estimated fair value using the FASB guidance for certain investments in debt and equity securities. The reported fair values include gross unrealized losses on marketable securities whose impairment the Company has deemed to be temporary. The tables below present the gross unrealized losses and the fair value of these securities, aggregated by investment category and length of time that individual securities have been in a continuous unrealized loss position (in thousands):

	December 31, 2016
	Less than 12 Months					12 Months or Longer					Total
	Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses
Description of Securities (1):
Federal Agency Mortgage Backed Securities	$	11,582	$	(239	)	$	436	$	(22	)	$	12,018	$	(261	)
U.S. Government Bonds	31,655		(762		)	17,976		(835		)	49,631		(1,597		)
Municipal Obligations	9,596		(394		)	4,067		(372		)	13,663		(766		)
Corporate Obligations	7,971		(172		)	2,092		(172		)	10,063		(344		)
Total Debt Securities	60,804		(1,567		)	24,571		(1,401		)	85,375		(2,968		)
Common Stock	2,760		(167		)	—		—			2,760		(167		)
Institutional Funds-International Equity	22,945		(110		)	—		—			22,945		(110		)
Total Temporarily Impaired Securities	$	86,509	$	(1,844	)	$	24,571	$	(1,401	)	$	111,080	$	(3,245	)

 ____________________

(1) Includes approximately 152 securities.

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

 ______________________

(2) Includes approximately 133 securities.

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

For the twelve months ended December 31, 2016, 2015, and 2014, the Company recognized other than temporary impairment losses on its available-for-sale securities as follows (in thousands):

	2016			2015			2014
Unrealized holding losses included in pre-tax income	$	(352	)	$	(338	)	$	—

103

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

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

	December 31, 2016				December 31, 2015
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
Description of Securities:
Federal Agency Mortgage Backed Securities	$	7,430	$	319	$	9,589	$	438
U.S. Government Bonds	12,237		138		12,033		136
Municipal Obligations	2,481		144		8,671		332
Corporate Obligations	12,350		655		10,110		368
Total Debt Securities	34,498		1,256		40,403		1,274
Common Stock	61,884		34,066		72,636		37,001
Equity Mutual Funds	42,244		3,345		18,853		91
Cash and Cash Equivalents	6,002		—		8,204		—
Total	$	144,628	$	38,667	$	140,096	$	38,366

The Company’s marketable securities include investments in mortgage backed securities, municipal, corporate and federal debt obligations. The contractual year for maturity for these available-for-sale securities as of December 31, 2016 is as follows (in thousands):

	Total		2017		2018 through 2021		2022 through 2026		2027 and Beyond
Municipal Debt Obligations	$	16,144	$	990	$	6,253	$	8,139	$	762
Corporate Debt Obligations	22,413		—		8,664		6,090		7,659
U.S. Government Bonds	61,868		14,272		22,495		14,786		10,315
Federal Agency Mortgage Backed Securities	19,448		—		5		390		19,053

The Company’s marketable securities in its decommissioning trust funds are sold from time to time and the Company uses the specific identification basis to determine the amount to reclassify out of accumulated other comprehensive income and into net income. The proceeds from the sale of these securities during the twelve months ended December 31, 2016, 2015, and 2014 and the related effects on pre-tax income are as follows (in thousands):

	2016			2015			2014
Proceeds from sales of available-for-sale securities	$	91,268		$	102,567		$	108,311
Gross realized gains included in pre-tax income	$	9,212		$	12,379		$	7,858
Gross realized losses included in pre-tax income	(1,220		)	(927		)	(508		)
Gross unrealized losses included in pre-tax income	(352		)	(338		)	—
Net gains in pre-tax income	$	7,640		$	11,114		$	7,350
Net unrealized holding gains (losses) included in accumulated other comprehensive income	$	8,444		$	(2,906	)	$	10,827
Net (gains) losses reclassified out of accumulated other comprehensive income	(7,640		)	(11,114		)	(7,350		)
Net gains (losses) in other comprehensive income	$	804		$	(14,020	)	$	3,477

Fair Value Measurements. The FASB guidance requires the Company to provide expanded quantitative disclosures for financial assets and liabilities recorded on the balance sheet at fair value. Financial assets carried at fair value include the Company's decommissioning trust investments and investments in debt securities which are included in deferred charges and other assets on the Balance Sheets. The Company has no liabilities that are measured at fair value on a recurring basis. The FASB guidance

104

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

• Level 1 - Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Financial assets utilizing Level 1 inputs include the nuclear decommissioning trust investments in active exchange-traded equity securities, mutual funds and U.S. Treasury securities that are in a highly liquid and active market. The Institutional Funds are valued using the NAV provided by the administrator of the fund. The NAV price is quoted on a restrictive market although the underlying investments are traded on active markets. During the third quarter of 2016, the Company concluded that the NAV used for determining the fair value of the Institutional Funds- International Equity investments have readily determinable fair values. Accordingly, such fund values have been re-categorized from Level 2 to Level 1 hierarchy.

• Level 2 - Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. Financial assets utilizing Level 2 inputs include the nuclear decommissioning trust investments in fixed income securities. The fair value of these financial instruments is based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences.

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

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

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

Description of Securities	Fair Value as  of December 31, 2016		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Trading Securities:
Investments in Debt Securities	$	1,421	$	—	$	—	$	1,421
Available for sale:
U.S. Government Bonds	$	61,868	$	61,868	$	—	$	—
Federal Agency Mortgage Backed Securities	19,448		—		19,448		—
Municipal Obligations	16,144		—		16,144		—
Corporate Obligations	22,413		—		22,413		—
Subtotal, Debt Securities	119,873		61,868		58,005		—
Common Stock	64,644		64,644		—		—
Equity Mutual Funds	42,244		42,244		—		—
Institutional Funds-International Equity	22,945		22,945		—		—
Cash and Cash Equivalents	6,002		6,002		—		—
Total available for sale	$	255,708	$	197,703	$	58,005	$	—

105

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

Description of Securities	Fair Value as  of December 31, 2015		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Trading Securities:
Investments in Debt Securities	$	1,543	$	—	$	—	$	1,543
Available for sale:
U.S. Government Bonds	$	50,399	$	50,399	$	—	$	—
Federal Agency Mortgage Backed Securities	20,085		—		20,085		—
Municipal Obligations	24,345		—		24,345		—
Corporate Obligations	18,475		—		18,475		—
Subtotal, Debt Securities	113,304		50,399		62,905		—
Common Stock	76,220		76,220		—		—
Equity Mutual Funds	18,853		18,853		—		—
Institutional Funds-International Equity	22,454		22,454		—		—
Cash and Cash Equivalents	8,204		8,204		—		—
Total available for sale	$	239,035	$	176,130	$	62,905	$	—

Below is a reconciliation of the beginning and ending balance of the fair value of the investment in debt securities (in thousands):

	2016			2015
Balance at January 1	$	1,543		$	1,653
Net unrealized gains (losses) in fair value recognized in income (a)	(122		)	(110		)
Balance at December 31	$	1,421		$	1,543

_____________________

(a) These amounts are reflected in the Company's statements of operations as investment and interest income.

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, 2016 and 2015. There were no purchases, sales, issuances, and settlements related to the assets in the Level 3 fair value measurement category during the twelve month periods ending December 31, 2016 and 2015.

106

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

P.    Supplemental Statements of Cash Flows Disclosures

	Years Ended December 31,
	2016		2015			2014
	(In thousands)
Cash paid for:
Interest on long-term debt and borrowing under the revolving credit facility	$	69,990	$	62,297		$	54,792
Income taxes, net of refund	2,328		1,000			6,876
Non-cash investing and financing activities:
Sale of Interest in Four Corners Generating Station (a)	27,720		—			—
Changes in accrued plant additions	4,789		(6,660		)	7,314
Grants of restricted shares of common stock	1,236		1,567			3,025

(a) The Company sold its interest in Four Corners for approximately $32.0 million based on the book value as defined in the Purchase and Sale Agreement. The sales price was adjusted downward by $7.0 million and $19.5 million to reflect APS's affiliate assumption of the Company's obligation to pay for future plant decommissioning and mine reclamation expense, respectively. The sales price was also adjusted downward by approximately $1.3 million for closing adjustments and other assets and liabilities assumed by APS's affiliate. At the closing of the sale, the Company received approximately $4.2 million in cash, subject to post-closing adjustments.

107

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

Q.     Selected Quarterly Financial Data (Unaudited)

The following table summarizes the Company’s unaudited results of operations on a quarterly basis. The quarterly earnings per share amounts for a year will not add to the earnings per share for that year due to the weighting of shares used in calculating per share data.

	2016 Quarters									2015 Quarters
	4th		3rd (2)		2nd		1st			4th		3rd		2nd		1st
					(In thousands except for share data)
Operating revenues (1)	$	188,037	$	323,225	$	217,865	$	157,809		$	176,902	$	289,713	$	219,508	$	163,746
Operating income (loss)	20,470		129,857		44,697		(163		)	8,312		88,047		41,872		7,960
Net income (loss)	5,656		74,636		22,284		(5,808		)	648		56,740		21,072		3,458
Basic earnings per share:
Net income (loss)	0.14		1.84		0.55		(0.14		)	0.02		1.40		0.52		0.09
Diluted earnings per share:
Net income (loss)	0.14		1.84		0.55		(0.14		)	0.02		1.40		0.52		0.09
Dividends declared per share of common stock	0.310		0.310		0.310		0.295			0.295		0.295		0.295		0.280

 ________________

(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.

(2) For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2015 Texas Retail Rate Case until it received the PUCT Final Order on August 25, 2016. Accordingly, it reported in the third quarter of 2016 the cumulative effect of the PUCT Final Order which related back to January 12, 2016. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.

108

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

None.

Item 9A. Controls and Procedures

Evaluation of disclosure controls and procedures. Under the supervision and with the participation of our management, including our chief executive officer and our chief financial officer, we conducted an evaluation pursuant to Rule 13a-15(b) under the Exchange Act of our disclosure controls and procedures as defined in Rule 13a-15(e) under the Exchange Act. Based on that evaluation, our chief executive officer and our chief financial officer concluded that, as of December 31, 2016, our disclosure controls and procedures are effective.

Management’s Annual Report on Internal Control Over Financial Reporting. Management’s Annual Report on Internal Control over Financial Reporting is included herein under the caption "Management Report on Internal Control Over Financial Reporting" on page 49 of this Annual Report on Form 10-K.

Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting in connection with the evaluation required by paragraph (d) of the Exchange Act Rules 13a-15 or 15d-15, that occurred during the quarter ended December 31, 2016, that materially affected, or that were reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

109

PART III

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

The information called for by Item 10 concerning our directors will be set forth in our definitive proxy statement for the 2017 Annual Meeting of Shareholders (the "2017 Proxy Statement") under the heading "Nominees and Directors of the Company" and is incorporated herein by reference pursuant to Instruction G to Form 10-K. The information called for by Item 10 regarding our executive officers is included herein under the caption "Executive Officers of the Registrant" and is incorporated herein by reference.

The information called for by Item 10 concerning the identification of our standing audit committee will be set forth in the 2017 Proxy Statement under the caption "Committees" under the heading "Directors' Meetings, Compensation and Committees," and under the heading "Audit Committee Report" and is incorporated herein reference pursuant to Instruction G to Form 10-K.

The information called for by Item 10 concerning our audit committee financial experts will be set forth in the 2017 Proxy Statement under the caption "Committees" under the heading "Directors', Meetings, Compensation and Committees" and is incorporated herein by reference pursuant to Instruction G to Form 10-K.

The information called for by Item 10 concerning compliance with Section 16(a) of the Exchange Act will be set forth in the 2017 Proxy Statement under the heading "Section 16(a) Beneficial Ownership Reporting Compliance," and is incorporated herein by reference pursuant to Instruction G to Form 10-K.

We have adopted a Code of Ethics. The information called for by Item 10 concerning our Code of Ethics will be set forth in the 2017 Proxy Statement under the caption "Business Conduct Policies" under the heading "Corporate Governance," and is incorporated herein by reference pursuant to Instruction G to Form 10-K.

Executive Officers of the Registrant

The executive officers of the Company are elected annually and serve at the discretion of the Board of Directors. The executive officers of the Company as of February 24, 2017 were as follows:

Name	Age	Current Position and Business Experience
Mary E. Kipp	49	Chief Executive Officer since December 2015; 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	53	Senior Vice President and Chief Financial Officer since October 2013; Vice President and Controller from March 2010 to October 2013.
Steven T. Buraczyk	49	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	64	Senior Vice President of Corporate Services and Chief Compliance Officer since December 2015; 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	65	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.
John R. Boomer	55	Senior Vice President and General Counsel since December 2015; Vice President and General Counsel from September 2014 to December 2015; Vice President and Treasurer from April 2014 to September 2014; Senior Vice President for Helen of Troy Limited from February 2012 to January 2014; Senior Vice President-International for Helen of Troy Limited from July 2008 to February 2012.
Russell G. Gibson	64	Vice President and Controller since September 2014; Chief Financial Officer and Vice President for ReadyOne Industries, Inc. from June 2006 to September 2014.

110

Item 11. Executive Compensation

The information called for by Item 11 will be set forth in the 2017 Proxy Statement under the heading "Summary of Compensation" and is incorporated herein by reference pursuant to Instruction G to Form 10-K.

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

The information called for by Item 12 will be set forth in the 2017 Proxy Statement under the heading "Security Ownership of Certain Beneficial Owners and Management" and is incorporated herein by reference pursuant to Instruction G to Form 10-K.

Equity Compensation Plan Information

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	—	$	—	1,421,342
Equity compensation plans
not approved by security holders	—	—		—
Total	—	$	—	1,421,342

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

The information called for by Item 13 will be set forth in the 2017 Proxy Statement under the heading "Certain Relationships and Related Party Transactions."

Item 14. Principal Accounting Fees and Services

The information called for by Item 14 will be set forth in the 2017 Proxy Statement under the heading "Independent Registered Public Accounting Firm."

111

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) Documents filed as a part of this report:

		Page
1.	Financial Statements:
	See Index to Financial Statements	50
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

Certain of the following documents are filed herewith. Certain other of the following exhibits have heretofore been filed with the Securities and Exchange Commission, and, pursuant to Rule 12b-32 and Regulation 201.24, are incorporated herein by reference.

112

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 3.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
	3.02	–	Bylaws of the Company, dated February 6, 1996. (Exhibit 3.02 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
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, and First Supplemental Indenture, dated as of February 1, 1996, including form of Series A through H First Mortgage Bonds. (Exhibit 4.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
4.01-01		–	Second Supplemental Indenture, dated as of August 19, 1997, to Exhibit 4.01. (Exhibit 4.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1997)
4.01-02		–	Third Supplemental Indenture, dated as of January 29, 1999, to Exhibit 4.01. (Exhibit 4.3 to the Company’s Registration Statement on Form S-3, dated March 29, 2005)
4.01-03		–	Fourth Supplemental Indenture, dated as of January 25, 2002, to Exhibit 4.01. (Exhibit 4.4 to the Company’s Registration Statement on Form S-3, dated March 29, 2005)
4.01-04		–	Fifth Supplemental Indenture, dated as of December 17, 2004, to Exhibit 4.01. (Exhibit 4.01-02 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004)
4.01-05		–	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. (Exhibit 4.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005)
4.01-06		–	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. (Exhibit 4.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015)
4.01-07		–	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. (Exhibit 4.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015)
	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)

113

Exhibit Number			Title
	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	–	Ordinance No. 2012-1256 adopted by the City Council of Farmington, New Mexico on June 12, 2012 authorizing and providing for the issuance by the City of Farmington, New Mexico of $33,300,000 in aggregate principal amount of its Pollution Control Revenue Refunding Bonds, 2012 Series A (El Paso Electric Company Four Corners Project). (Exhibit 4.01 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
	4.10	–	Debt Securities Indenture, dated as of May 1, 2005. (Exhibit 4.1 to the Company's Current Report on Form 8-K, filed on May 19, 2005)
	4.11	–	First Supplemental Indenture, dated as of May 19, 2008. (Exhibit 4.4 to the Company's Registration Statement on Form S-3, filed on May 20, 2008)
	4.12	–	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)
	4.13	–	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)
	4.14	–	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)
	4.15	–	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)
	4.16	–	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, and Amendments No. 1 through 13 thereto. (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. 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)
10.01-02		–	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)
10.01-03		–	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)
	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.

114

Exhibit Number			Title
	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 Form 8-K, filed on August 18, 2010)
	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)

115

Exhibit Number			Title
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 June 3, 2008, to Exhibit 10.28. (Exhibit 10.42-01 to the Company's Annual Report on Form 10-K for the year ended December 31, 2010)
10.28-02		–	Letter Agreement, dated November 26, 2008, to Exhibit 10.28. (Exhibit 10.42-02 to the Company's Annual Report on Form 10-K for the year ended December 31, 2010)
10.28-03		–	Letter Agreement, dated November 12, 2010, to Exhibit 10.28. (Exhibit 10.42-03 to the Company's Annual Report on Form 10-K for the year ended December 31, 2010)
10.28-04		–	Letter Agreement, dated April 29, 2011, to Exhibit 10.28. (Exhibit 10.04 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011)
10.28-05		–	Letter Agreement, dated May 13, 2013, to Exhibit 10.28. (Exhibit 10.42-05 to the Company's Annual Report on Form 10-K for the year ended December 31, 2014)
10.28-06		–	Letter Agreement, dated September 17, 2014, to Exhibit 10.28. (Exhibit 10.42-06 to the Company's Annual Report on Form 10-K for the year ended December 31, 2014)
10.28-07		–	Letter Agreement, dated October 13, 2015, to Exhibit 10.28. (Exhibit 10.07 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2015)
*10.28-08		–	Letter Agreement, dated October 24, 2016, to Exhibit 10.28.
	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 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)
#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 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 120 of this report)
Exhibit 24 –		Power of Attorney:
*24.01		–	Power of Attorney (set forth on page 118 of this report)

116

Exhibit Number			Title
*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	–	Reserved
	99.03	–	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)
	99.04	–	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)
	99.05	–	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, 2002)
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.
††	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.

117

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each of El Paso Electric Company, a Texas corporation, and the undersigned directors and officers of El Paso Electric Company, hereby constitutes and appoints Mary E. Kipp, Nathan T. Hirschi, John R. Boomer and Russell G. Gibson, its, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for it, him or her and its, his or her name, place and stead, in any and all capacities, with full power of each to act alone, to sign this report and any and all amendments to this report, and to file each such amendment to this report, with all exhibits thereto, and any and all documents in connection therewith, with the Securities and Exchange Commission, hereby granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform any and all acts and things requisite and necessary to be done in connection therewith, as fully to all intents and purposes as it, he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them or his or her or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

118

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 24th day of February 2017.

EL PASO ELECTRIC COMPANY
By:	/s/ MARY E. KIPP
	Mary E. Kipp
	Chief Executive Officer (Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

Signature	Title	Date
/s/ MARY E. KIPP	Chief Executive Officer and Director (Principal Executive Officer)	February 24, 2017
(Mary E. Kipp)
/s/ NATHAN T. HIRSCHI	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	February 24, 2017
(Nathan T. Hirschi)
/s/ RUSSELL G. GIBSON	Vice President and Controller (Principal Accounting Officer)	February 24, 2017
(Russell G. Gibson)
/s/ CATHERINE A. ALLEN	Director	February 24, 2017
(Catherine A. Allen)
/s/ JOHN ROBERT BROWN	Director	February 24, 2017
(John Robert Brown)
/s/ JAMES W. CICCONI	Director	February 24, 2017
(James W. Cicconi)
/s/ EDWARD ESCUDERO	Director	February 24, 2017
(Edward Escudero)
/s/ JAMES W. HARRIS	Director	February 24, 2017
(James W. Harris)
/s/ WOODLEY L. HUNT	Director	February 24, 2017
(Woodley L. Hunt)
/s/ THOMAS V. SHOCKLEY III	Director	February 24, 2017
(Thomas V. Shockley III)
/s/ ERIC B. SIEGEL	Director	February 24, 2017
(Eric B. Siegel)
/s/ STEPHEN N. WERTHEIMER	Director	February 24, 2017
(Stephen N. Wertheimer)
/s/ CHARLES A. YAMARONE	Director	February 24, 2017
(Charles A. Yamarone)

119

EX-10.07

	Exhibit 10.07
EL PASO ELECTRIC COMPANY
EXCESS BENEFIT PLAN
Effective as of April 1, 2014

TABLE OF CONTENTS
			Page
ARTICLE 1 DEFINITIONS
	1.1	Beneficiary		2
	1.2	Board		2
	1.3	Cash Balance Account Excess Benefit		2
	1.5	Code		2
	1.5	Committee		2
	1.6	Company		2
	1.7	Early Retirement Age		3
	1.8	ERISA		3
	1.9	Final Average Pay Excess Benefit		3
	1.10	Normal Retirement Date		3
	1.11	Participant		3
	1.12	Plan		3
	1.13	Post-Death Cash Balance Account Excess Benefit		3
	1.14	Post-Death Final Average Pay Excess Benefit		3
	1.15	Qualified Plan		3
	1.16	Separation from Service		3
	1.17	Specified Employee		5
	1.18	Spouse		5
	1.19	Surviving Spouse		5
	1.20	Total Excess Benefit		5
	1.21	Total Post-Death Excess Benefit		5
ARTICLE 2 ELIGIBILITY
ARTICLE 3 EXCESS BENEFIT
	3.1	Amount of Total Excess Benefit		6
		(a)	Final Average Pay Excess Benefit	6
		(b)	Cash Balance Account Excess Benefit	7
	3.2	Payment of Total Excess Benefit for Individuals who Become Participants before April 1, 2014		8
		(a)	Annuity Benefit	8
		(b)	Commencement of Annuity Benefit	8
	3.3	Payment of Total Excess Benefit for Individuals who Become Participants on or after April 1, 2014		9
		(a)	Lump Sum Benefit	9
		(b)	Time of Lump Sum Benefit Payment	9
	3.4	Deferred Benefit Commencement Date		9
	3.5	Actuarial Equivalent		10
		(a)	Cash Balance Account Excess Benefit Payable as an Annuity	10

i

		(b)	Final Average Pay Excess Benefit Payable as a Lump Sum	10
		(c)	Plan Benefits Payable in the Form of an Annuity other than a Single Life Annuity	10
	3.6	Distribution of de Minimis Amounts		10
	3.7	Accelerated Distribution under Certain Circumstances		10
	3.8	Delay of Payment under Certain Circumstances		11
ARTICLE 4 POST-DEATH EXCESS BENEFIT
	4.1	Eligibility		11
	4.2	Amount of Total Post-Death Excess Benefit		11
		(a)	Post-Death Final Average Pay Excess Benefit	12
		(b)	Post-Death Cash Balance Account Excess Benefit	12
	4.3	Payment of Total Post-Death Excess Benefit		12
		(a)	Annuity Benefit Payable if Plan Participation Commenced before April 1, 2014	12
		(b)	Lump Sum Benefit Payable if Plan Participation Commenced on or after April 1, 2014	12
ARTICLE 5 ADMINISTRATION OF THE PLAN
	5.1	Appointment of Plan Administrator		13
	5.2	Company Duties		13
	5.3	Powers of Plan Administrator		13
	5.4	Interpretations		13
	5.5	Determinations		14
	5.6	Indemnification		14
	5.7	Bond and Expenses		14
	5.8	Right to Suspend Benefits and Correct Errors		14
	5.9	Reliance on Tables		14
	5.10	Designated Payment Dates		15
ARTICLE 6 CLAIMS PROCEDURES
	6.1	Presentation of Claim		15
	6.2	Notification of Decision		15
	6.3	Review of a Denied Claim		16
	6.4	Decision on Review		16
	6.5	Designation of Authorized Representative		17
	6.6	Legal Action		17
ARTICLE 7 AMENDMENT OR TERMINATION
	7.1	Amendment or Termination		17
	7.2	Effect of Amendment or Termination		17
ARTICLE 8 GENERAL PROVISIONS
	8.1	Funding		17
	8.2	General Conditions		17
	8.3	No Guaranty of Benefits		18
	8.4	No Employment Rights		18

ii

8.5	Unsecured General Creditors	18
8.6	No Assignment	18
8.7	Court Order	19
8.8	Effect of Payment	19
8.9	Spendthrift Provision	19
8.10	Applicable Law	19
8.11	Withholding of Taxes	19
8.12	Incompetent	19
8.13	Corporate Successors	20
8.14	Payment in the Event of Taxation	20
8.15	Overpayment and Underpayment of Benefits	20
8.16	Captions and Construction	20
8.17	Severability	21
8.18	Limitations on Liability	21
8.19	Spouse’s Interest	21
8.20	Code Section 409A Compliance	21

iii

EL PASO ELECTRIC COMPANY

EXCESS BENEFIT PLAN

WHEREAS, the El Paso Electric Company Excess Benefit Plan (the “Plan”) was established by El Paso Electric Company (the “Company”) effective January 1, 2004 and has since been maintained as an unfunded plan primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees of the Company who participate in the Retirement Income Plan for Employees of El Paso Electric Company (the “Qualified Plan”), which Plan consists, in part, of an “excess benefit plan,” as defined in Section 3(36) of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”);

WHEREAS, it is the intention of the Company that the Plan be unfunded for tax purposes and for purposes of Title I of ERISA;

WHEREAS, the Plan, which is subject to the requirements of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”), was amended to comply with the provisions of Code Section 409A effective January 1, 2009, and was later amended and construed to resolve certain inconsistencies in the provisions of the Plan, to provide additional details with respect to certain Code Section 409A issues then addressed in the Plan, and to correct certain references in the Plan provisions;

WHEREAS, benefits provided under the Plan are not considered to be grandfathered for purposes of Code Section 409A;

WHEREAS, the benefits provided to a participant under the Plan are generally determined as the benefits that would be provided to the participant under the Qualified Plan if the participant’s Qualified Plan benefits were calculated without giving effect to any limitation on benefits or compensation imposed by the Code with respect to qualified plans, and as if the participant’s compensation, considered for purposes of calculating the participant’s benefits under the Qualified Plan, included bonuses paid under the Company’s short term bonus plan (which bonuses are not considered under the Qualified Plan for purposes of calculating Qualified Plan benefits), reduced by the participant’s Qualified Plan benefits;

WHEREAS, in connection with amendments being made to the Qualified Plan, effective April 1, 2014, to introduce cash balance account benefits under the Qualified Plan for employment with the Company with respect to periods beginning or after April 1, 2014 for some, but not all, Qualified Plan participants, the Company wishes to amend the Plan to be consistent with the existing final average pay benefit provisions of the Qualified Plan (based primarily on a participant’s average monthly earnings and benefit accrual service under the Qualified Plan) and the new cash balance account benefits under the Qualified Plan; and

WHEREAS, as provided in this amendment and restatement of the Plan, although a participant’s benefits under the Plan will be based on the participant’s benefits under the Qualified Plan (whether such benefits are final average pay benefits, cash balance account benefits, or a combination of both), the time and form of payment for a participant’s benefits

1

under the Plan will continue to be established and governed solely by the provisions of the Plan, with the Plan benefits of individuals who become participants in the Plan before April 1, 2014 being paid as annuities beginning at the later of Separation from Service, as defined in Section 1.16 (“Separation from Service”) or attainment of “early retirement age,” as hereinafter defined (consistent with the Plan provisions in effect prior to April 1, 2014), and with the Plan benefits of individuals who become participants in the Plan on or after April 1, 2014 being paid as lump sum distributions on the first day of the second month following Separation from Service, all as determined under the provisions of the Plan;

NOW, THEREFORE, the Plan is amended and restated, effective April 1, 2014, as follows:

ARTICLE 1

DEFINITIONS

Wherever used herein, the following terms shall have the meanings hereinafter set forth:

1.1“Beneficiary” means (a) in the case of benefits commencing during a Participant’s life, the Spouse or other individual designated by the Participant, in accordance with Section 3.2(a), to receive monthly annuity payments following the Participant’s death, as well as (b) in the case of benefits not paid or commencing during a Participant’s life, the Spouse or other individual designated by the Participant, in accordance with Section 4.3, to receive any Post Death Cash Balance Account Excess Benefit that may be payable with respect to the Participant under Article 4. “Beneficiary” shall include any Surviving Spouse entitled to a benefit hereunder, any individual designated by the Participant under Section 3.6, and any beneficiary of the former Spouse of a Participant. Any beneficiary designation shall be on a form approved by the Committee and will be effective only when such form is filed with the Committee during the life of the Participant or other individual making the beneficiary designation. If the Participant fails to designate a Beneficiary and the Participant’s Surviving Spouse is not entitled to the Participant’s benefit hereunder, any benefit payable with respect to the Participant shall be paid to the Participant’s executor or administrator.

1.2“Board” means the Board of Directors of the Company.

1.3“Cash Balance Account Excess Benefit” is calculated as provided in Section 3.1(b).

1.4“Code” means the Internal Revenue Code of 1986, as amended, and any Treasury Regulations relating thereto.

1.5“Committee” means the Compensation Committee of the Board or its designee charged with the administration of the Plan.

1.6“Company” means El Paso Electric Company or, to the extent provided in Section 8.13, any successor corporation or other entity resulting from a merger or consolidation into or with the Company or a transfer or sale of substantially all of the assets of the Company.

2

1.7“Early Retirement Age” means the date on which a Participant has attained age 55 and is fully vested in a benefit under the Qualified Plan.

1.8“ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

1.9“Final Average Pay Excess Benefit” is calculated as provided in Section 3.1(a).

1.10“Normal Retirement Date” means the first day of the month coincident with or next following a Participant’s Separation from Service with the Company after the date such Participant has attained (a) age 65, or (b) if later, his fifth anniversary of joining the Qualified Plan.

1.11“Participant” means an employee who becomes a participant in the Plan pursuant to Article 2 hereof, and any former employee who is entitled to benefits under the Plan.

1.12“Plan” means the El Paso Electric Company Excess Benefit Plan, as set forth herein and as amended from time to time.

1.13“Post-Death Cash Balance Account Excess Benefit” is calculated as provided in Section 4.2(b).

1.14“Post-Death Final Average Pay Excess Benefit” is calculated as provided in Section 4.2(a).

1.15“Qualified Plan” means the Retirement Income Plan for Employees of El Paso Electric Company, as amended from time to time, and any successor or replacement thereto.

1.16“Separation from Service” means

(a)with respect to an employee, the employee’s ceasing to provide services to the Company as a result of the employee’s death, retirement or termination of employment. For purposes of determining whether a separation from service has occurred, a “termination of employment” shall mean that the surrounding facts and circumstances indicate that the Company and the employee reasonably anticipate that no further services will be performed after a certain date, or that the level of bona fide services the employee would perform after such date (whether as an employee or as an independent contractor) would permanently decrease to no more than 20 percent of the average level of bona fide services performed (whether as an employee or an independent contractor) over the immediately preceding 36-month period (or the full period of services to the employer if the employee has been providing services to the employer less than 36 months).

Notwithstanding the foregoing, the employment relationship will be treated as continuing intact while an individual is on military leave, sick leave, or other bona fide leave of absence if the period of such leave does not exceed six months, or if longer, so long as the

3

individual retains a right to reemployment with the Company under an applicable statute or by contract. If the period of a military leave, sick leave, or other bona fide leave of absence exceeds six months and the Participant does not have a right to reemployment under an applicable statute or by contract, the employment relationship will be considered to be terminated for purposes of this Plan as of the first day immediately following the end of such six-month period. In applying the provisions of this paragraph, a leave of absence will be considered a bona fide leave of absence only if there is a reasonable expectation that the Participant will return to perform services for the Company.

(b)For a Participant who provides services to the Company as both an employee and an independent contractor, a Separation from Service generally will not occur until the Participant has ceased providing services for the Company both as an employee and as an independent contractor as determined in accordance with the provisions set forth in paragraphs (a) and (b) of this Section 1.16, respectively. Except as otherwise provided herein, in the case of an independent contractor, a Separation from Service will occur upon the expiration of the contract (or in the case of more than one contract, all contracts) under which services are performed for the Company, provided that the expiration of such contract or contracts is determined by the Company to constitute a good faith and complete termination of the contractual relationship between the Participant and the Company. If a Participant ceases providing services for the Company as an employee and begins providing services for the Company as an independent contractor, the Participant will not be considered to have experienced a Separation from Service until the Participant has ceased providing services for the Company in both capacities, as determined in accordance with the applicable provisions set forth in paragraphs (a) and (b) of this Section 1.16.

Notwithstanding the foregoing provisions in this paragraph (b), if a Participant provides services for the Company as both an employee and as a member of the Board, to the extent permitted by Regulation Section 1.409A-1(h)(5), the services provided by the Participant as a director will not be taken into account in determining whether the Participant has experienced a Separation from Service as an employee.

(c)Notwithstanding the provisions of this Section 1.16, where, as part of a sale or other disposition of substantial assets by the Company to an unrelated buyer, a Participant would otherwise experience a Separation from Service as defined above, the Company and the buyer shall retain the discretion to specify, and may specify, that a Participant performing services for the Company immediately before the asset purchase transaction and providing services to the buyer after and in connection with the asset purchase transaction shall not experience a Separation from Service for purposes of the Plan and the Participant shall be bound by same, provided that such transaction and the specification meet the requirements of Code Section 409A and the Treasury Regulations and other guidance thereunder.

(d)For purposes of this definition, “Company” means (1) the entity for which the Participant performs services and with respect to which the legally binding right to benefits under the Plan arises; and (2) all other entities with which the entity described in paragraph (d)(1) of this Section 1.16 would be aggregated and treated as a single employer under Code Section 414(b) (controlled group of corporations) and Code Section 414(c) (group of trades or

4

businesses under common control), as applicable. To identify the group of entities described in the preceding sentence, an ownership threshold of 50 percent shall be used as a substitute for the 80 percent minimum ownership threshold that appears in, and otherwise must be used when applying, the applicable provisions of (A) Code Section 1563 and the Treasury Regulations thereunder for determining a controlled group of corporations under Code Section 414(b), and (B) Treasury Regulation Section 1.414(c)-2 for determining the trades or businesses that are under common control under Code Section 414(c).

1.17“Specified Employee” means any Participant who, as of the Participant’s Separation from Service, is determined to be a “key employee” (as defined under Code Section 416(i)(1)(A)(i), (ii) or (iii) (applied in accordance with the Treasury Regulations thereunder and disregarding Code Section 416(i)(5)) for the applicable period, as determined by the Company in accordance with Treasury Regulation Section 1.409A-l(i). For purposes of determining Specified Employees under this Section 1.17, the Company uses the following default provisions under Regulation Section 1.409A-1(i): First, for purposes of identifying a Specified Employee by applying the requirements of Code Sections 416(i)(1)(A)(i), (ii) and (iii), the definition of compensation under Regulation Section 1.415(c)-2(a) is used, applied as if the Company were not using any safe harbor provided in Regulation Section 1.415(c)-2(d), were not using any of the special timing rules provided in Regulation Section 1.415(c)-2(e), and were not using any of the special rules provided in Regulation Section 1.415(c)-2(g). Second, the specified employee identification date is December 31. Third, the specified employee effective date is the first day of the fourth month following the specified employee identification date.

1.18“Spouse” means a Participant’s legal spouse, including a same sex spouse recognized as such in the state where the marriage is performed, except that such term does not include (a) a common law spouse in the absence of a Declaration and Registration of Informal Marriage filed with the County Clerk and provided to the Company, (b) an opposite sex domestic partner, or (c) a same sex domestic partner.

1.19“Surviving Spouse” means a Spouse who is married to a Participant at the date of his death and for at least one year prior thereto.

1.20“Total Excess Benefit” is calculated as provided in Section 3.1.

1.21“Total Post-Death Excess Benefit” is calculated as provided in Section 4.2.

ARTICLE 2

ELIGIBILITY

Any employee of the Company who holds the office of Vice President or any office above Vice President, with the Company, and who has not previously been selected for participation in the Plan under the prior provisions of the Plan, shall become a Participant upon the latest of (1) the employee’s date of hire as a Vice President or above, (2) the employee’s date of promotion to Vice President or above, and (3) April 1, 2014. In addition to those employees who become Participants under the preceding sentence, the Company may select any other employee of the Company, who is in a select group of management or highly compensated

5

employees of the Company, and who has not previously been selected for participation in the Plan, as a Participant in the Plan.

In order to be vested in a benefit under the Plan, a Participant must be fully vested in a benefit under the provisions of the Qualified Plan. In general, and subject to the provisions of the Plan, such a vested Participant is entitled to a benefit under the Plan if his Qualified Plan benefit is subject to any limitation on benefits or compensation imposed by any provision of the Code (as in effect on the date for commencement of the Participant’s Qualified Plan benefit, or as in effect at any time thereafter), or if the Participant receives bonuses pursuant to the Company’s short term bonus program (which bonuses are not considered under the Qualified Plan for purposes of calculating Qualified Plan benefits). Any benefit payable under the Plan to a Participant shall be by reason of the Participant’s Separation from Service, in accordance with the provisions of Article 3, or by reason of the Participant’s death, in accordance with the provisions of Article 4. In no event will a Participant receive a benefit under the Plan with respect to any amounts earned, through a consulting arrangement or otherwise, after the Participant’s termination of employment with the Company.

ARTICLE 3

EXCESS BENEFIT

3.1Amount of Total Excess Benefit. The amount of the “Total Excess Benefit” for each Participant under the Plan shall be calculated as the sum of (1) the Participant’s Final Average Pay Excess Benefit, as defined under Section 3.1(a), if any, plus (2) the Participant’s Cash Balance Account Excess Benefit, as defined under Section 3.1(b), if any. Some Participants will have only a Final Average Pay Excess Benefit or only a Cash Balance Account Excess Benefit, while other Participants will have both a Final Average Pay Excess Benefit and a Cash Balance Account Excess Benefit. A Participant shall have a Cash Balance Account Excess Benefit under the Plan only to the extent that the Participant is eligible for and has a “cash balance account” established for him on or after April 1, 2014 under the provisions of the Qualified Plan.

(a)Final Average Pay Excess Benefit. A Participant’s “Final Average Pay Excess Benefit” shall be calculated as

(1) the monthly amount to which the Participant would be entitled under the Qualified Plan based on the Participant’s “average monthly earnings,” as determined under the Qualified Plan, except that “annualized rate of basic compensation (excluding bonuses, overtime pay, expense allowances, profit sharing and any other extra compensation such as supplemental payments and other extra compensation in any form),” as used in the Qualified Plan’s definition of “average monthly earnings,” shall be adjusted to include bonuses paid pursuant to the Company’s short term bonus program (but not to include any other bonuses that may be paid by the Company), and “benefit accrual service,” as determined under the Qualified Plan, without giving effect to any limitation on benefits or compensation imposed by any provision of the Code (and without considering the Participant’s “cash balance benefits,” if any, under the Qualified Plan),

6

LESS

(2) the monthly amount to which the Participant is entitled under the Qualified Plan (whether from the Trust that funds the Qualified Plan or from annuities purchased under the Qualified Plan) based on the Participant’s “average monthly earnings” and “benefit accrual service,” as determined under the Qualified Plan, considering any limitation on benefits or compensation imposed by any provision of the Code (and without considering the Participant’s “cash balance benefits,” if any, under the Qualified Plan).

The amounts described in (1) and (2) of the preceding sentence shall be computed as of the date of the Participant’s Separation from Servicein the form of a single life only annuity payable over the lifetime of the Participant commencing as of the Participant’s Normal Retirement Date, and amounts determined as of any date other than Normal Retirement Date shall be actuarially adjusted as provided under Section 3.5.

(b)Cash Balance Account Excess Benefit. A Participant’s “Cash Balance Account Excess Benefit” shall be calculated as

(1) the “cash balance account” to which the Participant would be entitled under the Qualified Plan if “pay credits” to the Participant’s Qualified Plan “cash balance account” were calculated considering “base pay,” as determined under the Qualified Plan, adjusted to include bonuses paid pursuant to the Company’s short term bonus plan (but not to include any other bonuses that may be paid by the Company), without giving effect to any limitation on benefits or compensation imposed by any provision of the Code, and “years of vesting service,” as determined under the Qualified Plan, and if “interest credits” to the Participant’s Qualified Plan “cash balance account” were calculated in the manner provided under the Qualified Plan (without considering the Participant’s benefits, if any, under the Qualified Plan other than his “cash balance benefits”),

LESS

(2) the “cash balance account” to which the Participant is entitled under the Qualified Plan based on “pay credits” to the Participant’s Qualified Plan “cash balance account” (which are based on the Participant’s “years of vesting service” and “base pay,” as determined under the Qualified Plan) and “interest credits” to the Participant’s Qualified Plan “cash balance account,” considering any limitation on benefits or compensation imposed by any provision of the Code (and without considering the Participant’s benefits, if any, under the Qualified Plan other than his “cash balance benefits”).

The amounts described in (1) and (2) of the preceding sentence shall be computed as of the date of the Participant’s Separation from Service; provided, however, that in determining a Participant’s Cash Balance Account Excess Benefit, “interest credits,” calculated in the manner provided under the Qualified Plan, shall continue to be credited through the last day of the month preceding the date as of which a distribution commences or occurs under Section 3.2, 3.3, 3.4, 3.6, 3.7 (to the extent that a distribution is made under 3.7), 3.8 or 4.3, as applicable.

7

3.2Payment of Total Excess Benefit for Individuals who Become Participants before April 1, 2014.

(a)Annuity Benefit. Each individual who becomes a Participant in the Plan, as provided in Article 2, before April 1, 2014, and who is vested, as provided in Article 2, shall receive his Total Excess Benefit, as determined under Section 3.1, in the form of

(1)a single life only annuity for the life of the Participant if the Participant is not married to a Spouse on the date payment of the Participant’s benefits commence under Section 3.2(b), 3.4 or 3.8, or if the Participant has not been married to his Spouse for at least one year on the date payment of the Participant’s benefits commence under Section 3.2(b), 3.4 or 3.8;

(2)a joint life annuity payable for the life of the Participant with a survivor annuity for the life of his Spouse equal to 50 percentof the amount of the annuity payable during the joint lives of the Participant and his Spouse, if the Participant is married to a Spouse, and has been married to his Spouse for at least one year, on the date payment of the Participant’s benefits commence under Section 3.2(b), 3.4 or 3.8, which joint life and 50 percent survivor annuity described in this paragraph (2) shall be actuarially equivalent, as determined under Section 3.5, to the Participant’s single life only annuity for the life of the Participant described in paragraph (a)(1) of this Section 3.2; or

(3)one of the following three optional forms of benefit elected by the Participant. If the Participant is married to a Spouse, and has been married to his Spouse for at least one year on the date payment of the Participant’s benefits commence under Section 3.2(b), 3.4 or 3.8, the election of an optional form of benefit is subject to the consent of the Participant’s Spouse on a form acceptable to the Committee. Each optional from of benefit will be adjusted for actuarial equivalence as provided in Section 3.5.

(A)a joint life annuity payable for the life of the Participant with a survivor annuity for the life of any individual designated by the Participant on a form acceptable to the Committee. The amount payable to the survivor will be a percentage, elected by the Participant, of the amount of the annuity payable during the joint lives of the Participant and the individual designated.

(B)an annuity payable for the life of the Participant, with 120 monthly payments guaranteed, regardless of whether the Participant dies before all 120 payments have been made. In the event of the Participant’s death prior to payment of 120 monthly installments, the same amount of annuity will be payable for the remainder of the 120 months to the individual designated by the Participant on a form acceptable to the Committee.

(C)a single life only annuity payable for the life of a Participant until the Participant’s death.

(b)Commencement of Annuity Benefit.

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(1)Except as provided in Section 3.8(b), if an individual, who becomes a Participant, as provided in Article 2, before April 1, 2014, and who is vested, as provided in Article 2, experiences a Separation from Service before the Participant reaches Early Retirement Age, the payment of the Participant’s Total Excess Benefit, as determined under Section 3.1, shall commence no earlier than the Participant’s Early Retirement Age and no later than the first day of the month following the month in which the Participant reaches Early Retirement Age.

(2)Except as provided in Section 3.8(b), if an individual, who becomes a Participant, as provided in Article 2, before April 1, 2014, experiences a Separation from Service after reaching Early Retirement Age, the payment of the Participant’s Total Excess Benefit, as determined under Section 3.1, shall commence no later than the first day of the month following the month in which the Participant experiences his Separation from Service.

3.3Payment of Total Excess Benefit for Individuals who Become Participants on or after April 1, 2014.

(a)Lump Sum Benefit. Each individual who becomes a Participant, as provided in Article 2, on or after April 1, 2014, and who is vested, as provided in Article 2, shall receive his Total Excess Benefit, as determined under Section 3.1, in the form of a lump sum payment.

(b)Time of Lump Sum Benefit Payment. Except as provided in Section 3.8(b), each individual who becomes a Participant, as provided in Article 2, on or after April 1, 2014, and who is vested, as provided in Article 2, shall receive his Total Excess Benefit, as determined under Section 3.1, in the form of a lump sum benefit payment on the first day of the second month following the Participant’s Separation from Service.

3.4Deferred Benefit Commencement Date. A Participant may delay the commencement of his annuity benefit under Section 3.2(b), or the payment of his lump sum benefit under Section 3.3(b), as applicable, provided that:

(a)the Participant’s election to defer the commencement or payment of his benefit is made on a form acceptable to the Committee;

(b)the Participant files the form with the Committee on a date that is at least 12 months prior to the then current benefit commencement or payment date;

(c)the Participant’s election to defer the commencement or payment of his benefit, as evidenced by a properly completed and executed distribution form, shall not be effective until at least 12 months after the date on which the election is made;

(d)the deferred benefit commencement or payment date is at least the fifth anniversary of the current benefit commencement or payment date; and

(e)the Committee, in its sole discretion, consents to the change.

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3.5Actuarial Equivalent. Subject to the provisions of Regulation Section 1.409A-2(b)(2)(ii), actuarial equivalent calculations under the Plan are determined as follows:

(a)Cash Balance Account Excess Benefit Payable as an Annuity. If the Cash Balance Account Excess Benefit is payable in the form of an annuity (e.g., the Cash Balance Account Excess Benefit of an individual who becomes a Participant before April 1, 2014), the Cash Balance Account Excess Benefit shall be converted to an actuarially equivalent single life annuity based on the actuarial assumptions specified in Section 2.2(e) of the Qualified Plan and, if payable in an annuity form other than a single life annuity, shall be further adjusted as described in paragraph (c) of this Section 3.5.

(b)Final Average Pay Excess Benefit Payable as a Lump Sum. If the Final Average Pay Excess Benefit is payable in the form of a lump sum (e.g., the Final Average Pay Excess Benefit of an individual who becomes a Participant on or after April 1, 2014), the Final Average Pay Excess Benefit shall be converted to an actuarially equivalent single lump sum based on the actuarial assumptions specified in Section 2.2(e) of the Qualified Plan.

(c)Plan Benefits Payable in the Form of an Annuity other than a Single Life Annuity. If benefits are payable in an alternative annuity form of payment, other than a single life annuity (e.g., for an individual who becomes a Participant before April 1, 2014), such alternative annuity form of payment amount will be determined by converting the single life annuity to such actuarially equivalent alternative annuity form of payment based on the actuarial assumptions specified in Section 2.2(a) of the Qualified Plan.

3.6Distribution of de Minimis Amounts. If, as of a vested Participant’s Separation from Service, or any payment date subsequent to the Participant’s Separation from Service, (a) the actuarially equivalent present value of the Participant’s Total Excess Benefit under the Plan, as determined under Section 3.1, and all agreements, methods, programs or other arrangements with respect to which deferrals of compensation are treated as having been deferred under a single nonqualified deferred compensation plan under Regulation Section 1.409A-1(c)(2), is less than the applicable dollar limit under Code Section 402(g)(1)(B), and (b) the payment results in the termination and liquidation of the entirety of the Participant’s interest under the Plan, and all agreements, methods, programs or other arrangements with respect to which deferrals of compensation are treated as having been deferred under a single nonqualified deferred compensation plan under Regulation Section 1.409A-1(c)(2), the Committee may require that the remaining unpaid vested benefit be paid to the Participant, or the individual designated by the Participant on a form acceptable to the Committee, in a lump sum in lieu of any further benefit payments under the Plan. The Committee’s discretion to require lump sum benefit payments under this Section 3.6 shall be evidenced in writing no later than the date of such payments.

3.7Accelerated Distribution under Certain Circumstances. Notwithstanding any provision of the Plan to the contrary, the Committee, in its discretion, may accelerate payment of a Participant’s benefit in accordance with the provisions of Regulation Sections 1.409A-3(j)(4)(ii) through (xiv), as applicable.

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3.8Delay of Payment under Certain Circumstances. Notwithstanding any provision of the Plan to the contrary,

(a)payment of a Participant’s benefit may be delayed by the Committee under circumstances described in Regulation Section 1.409A-2(b)(7), provided that the Committee treats all payments to similarly situated Participants on a reasonably consistent basis.

(b)if as of a Participant’s Separation from Service, other than as a result of the Participant’s death, the Participant is a Specified Employee, no payment on account of the Separation from Service may be made with respect to such Participant before the date that is six months after the Participant’s Separation from Service, or if earlier than the end of the six-month period, the date of the Participant’s death. In such case, any payment that would have, but for this Section 3.8(b), been distributed to the Participant during the six-month period following the Participant’s Separation from Service, will be accumulated and paid to the Participant (or if the Participant is no longer living, the Participant’s executor or administrator), in a single lump sum as soon as is administratively practicable following the end of the six-month period, but in no event more than 60 days after the end of the such six-month period.

ARTICLE 4

POST-DEATH EXCESS BENEFIT

4.1Eligibility. In no event shall a post-death benefit under this Article 4 be payable with respect to a Participant if, at his death, he has already commenced an annuity distribution under Section 3.2(b), 3.4 or 3.8, or he has already received a lump sum payment under Section 3.3(b), 3.4, 3.6 or 3.8. Otherwise, a post-death benefit shall be payable with respect to any vested Participant who has a cash balance account benefit under the Qualified Plan (in which case, the Participant’s Surviving Spouse, or other Beneficiary, shall receive the Participant’s Post-Death Cash Balance Account Excess Benefit in accordance with Section 4.3), and a post-death benefit shall be payable with respect to any vested Participant who has a benefit, other than a cash balance account benefit (i.e. a final average pay benefit) under the Qualified Plan only if, at his death, the Participant has a Surviving Spouse (in which case, the Participant’s Surviving Spouse shall receive the Post-Death Final Average Pay Excess Benefit in accordance with Section 4.3).

4.2Amount of Total Post-Death Excess Benefit. The amount of the “Total Post-Death Excess Benefit” for each Participant shall be calculated as the sum of (1) the Participant’s Post-Death Final Average Pay Excess Benefit, as defined under Section 4.2(a), if any, plus (2) the Participant’s Post-Death Cash Balance Account Excess Benefit, as defined under Section 4.2(b), if any. Some Participants will have only a Post-Death Final Average Pay Excess Benefit or only a Post-Death Cash Balance Account Excess Benefit, while other Participants will have both a Post-Death Final Average Pay Excess Benefit and a Post-Death Cash Balance Account Excess Benefit. A Participant shall have a Post-Death Cash Balance Account Excess Benefit under the Plan only to the extent that the Participant is eligible for and has a cash balance account established for him on or after April 1, 2014 under the provisions of the Qualified Plan.

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(a)Post-Death Final Average Pay Excess Benefit. The “Post-Death Final Average Pay Excess Benefit” shall be calculated as the death benefit that would be payable to the Surviving Spouse of a Participant under the Qualified Plan (either as a “qualified pre-retirement survivor annuity” under Section 2.65 of the Qualified Plan, or as a “pre-retirement death benefit” under Section 6.8 of the Qualified Plan), considering only the Participant’s Final Average Pay Excess Benefit, as calculated under Section 3.1(a). A Post-Death Final Average Pay Excess Benefit shall be payable following the death of a Participant only if the requirements set forth in Section 2.65 or 6.8, as applicable, of the Qualified Plan are satisfied.

(b)Post-Death Cash Balance Account Excess Benefit. The “Post-Death Cash Balance Account Excess Benefit” shall be calculated as the death benefit that would be payable under the Qualified Plan considering only the Participant’s Cash Balance Account Excess Benefit, as calculated under Section 3.1(b).

4.3Payment of Total Post-Death Excess Benefit.

(a)Annuity Benefit Payable if Plan Participation Commenced before April 1, 2014. Subject to the conditions set forth in Section 4.1, following the death of any individual who becomes a Participant, as provided in Article 2, before April 1, 2014, the Surviving Spouse of the Participant shall receive his Total Post-Death Excess Benefit in the form of an annuity over the lifetime of the Surviving Spouse, in monthly installments commencing

(1)no earlier than the date the Participant would have reached Early Retirement Age and no later than the first day of the month following the month in which the Participant would have reached Early Retirement Age, if the Participant dies before reaching Early Retirement Age, or

(2)no later than the first day of the month following the month in which the Participant dies, if the Participant dies after reaching Early Retirement Age.

The preceding provisions of this Section 4.3(a) notwithstanding, to the extent that an individual who becomes a Participant before April 1, 2014 accrues a Cash Balance Account Excess Benefit with respect to his post-March 31, 2014 service, and with respect to whom a Post-Death Cash Balance Account Excess Benefit is payable, if the Participant does not have a Surviving Spouse, his Post-Death Cash Balance Account Excess Benefit shall be payable in the form of an annuity over the lifetime of the individual designated by the Participant on a form acceptable to the Committee, beginning on the date that annuity payments to a Surviving Spouse would have commenced under this Section 4.3(a).

(b)Lump Sum Benefit Payable if Plan Participation Commenced on or after April 1, 2014. Subject to the conditions set forth in Section 4.1, following the death of any individual who becomes a Participant, as provided in Article 2, on or after April 1, 2014, the Participant’s Total Post-Death Excess Benefit shall be paid, in the form of a lump sum benefit, to the Participant’s Surviving Spouse, or if there is no Surviving Spouse, to the individual designated by the Participant on a form acceptable to the Committee. The lump sum benefit

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provided for under the preceding sentence shall be paid in a single lump sum payment on the first day of the second month following the date of the Participant’s death.

ARTICLE 5

ADMINISTRATION OF THE PLAN

5.1Appointment of Plan Administrator. The Committee shall be the plan administrator. Any action (including decisions, determinations and interpretations) that may be taken by the plan administrator under the Plan may be delegated by the Committee to another person to be performed on behalf of, and as a designee of, the plan administrator. If the title for this position changes, the title used herein shall be read as the new title.

5.2Company Duties. The Company shall, upon request or as may be specifically required under the Plan, furnish or cause to be furnished all of the information or documentation in its possession or control that is necessary or required by the plan administrator to perform its duties and functions under the Plan.

5.3Powers of Plan Administrator. The plan administrator shall have all powers and discretion as may be necessary to discharge its duties and responsibilities under the Plan, including the power to:

(a)maintain and preserve records relating to Participants, former Participants and Beneficiaries;

(b)prepare and furnish to Participants all information required under applicable law or the provisions of the Plan;

(c)maintain sufficient Participant data and make required payments of benefits;

(d)prepare and file or publish with all appropriate government officials all reports, filings and other information required under law to be so filed or published;

(e)interpret and construe the Plan;

(f)make rules and regulations for the administration of the Plan; and

(g)retain records on elections and waivers by Participants, their Surviving Spouses and others, as applicable, as further set forth herein.

The plan administrator may engage agents to assist it and may engage legal counsel, who may be counsel for the Company. The plan administrator shall not be responsible for any action taken or not taken on the advice of such counsel.

5.4Interpretations. Subject to the express provisions of the Plan, the plan administrator may interpret the Plan, prescribe, amend and rescind rules and regulations relating

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to it, and make all other determinations it deems necessary or advisable for the administration of the Plan.

5.5Determinations. The plan administrator’s determinations under the Plan need not be uniform and may be made selectively among Participants who have a benefit under the Plan, whether or not such Participants are similarly situated, consistent with Code Section 409A. The determination of the plan administrator on all matters regarding the Plan shall be conclusive.

5.6Indemnification. To the extent permitted by the laws of the State of Texas, the plan administrator and the person(s) who may act to fulfill the responsibilities of the plan administrator or the Company shall be indemnified by the Company against any and all liabilities arising by reason of any act, or failure to act, pursuant to the provisions of the Plan, including expenses reasonably incurred in the defense of any claim relating to the Plan, even if the same is judicially determined to be due to such person’s negligence, but not when the same is judicially determined to be due to the gross negligence or willful misconduct of such person.

5.7Bond and Expenses. The plan administrator shall serve without bond unless state or federal statutes require otherwise, in which event the Company shall pay the premium of any statutorily required bond. Except as may otherwise be provided herein, the expenses of the plan administrator shall be paid by the Company. Such expenses shall include all expenses incident to the functioning of the plan administrator, including litigation costs, fees of accountants, counsel and other specialists, and other costs of administering the Plan.

5.8Right to Suspend Benefits and Correct Errors. The plan administrator shall take such steps as are considered necessary and appropriate to remedy any inequity that results from incorrect information received or communicated in good faith or as the consequence of an administrative error. The plan administrator may suspend the payment of any benefit under the Plan until satisfied as to the correctness of the payment or the individual to receive the payment or to allow filing in any court of competent jurisdiction of a suit in such form as the plan administrator considers appropriate for a legal determination of the benefits to be paid and the individuals to receive them. The plan administrator specifically reserves the right to correct errors of every sort, and the Participant hereby agrees as Participant, and on behalf of any Surviving Spouse or Beneficiary, to any method of error correction that the plan administrator shall specify. The objective of any such method of error correction shall be, to the extent reasonably possible, to adjust the benefit paid to the Participant by reversing transactions or taking other actions to approach the situation that would have existed if the error had not been made. The plan administrator shall also be authorized to recover any payment made in error including the right to make deductions from future benefits. To the extent that corrections contemplated by this Section 5.8 are required to be made in accordance with IRS correction guidance, including Notice 2008-113, such corrections shall be made in accordance with such guidance.

5.9Reliance on Tables. In administering the Plan, the plan administrator and the Company shall be entitled, to the extent permitted by law, to rely conclusively on all tables, valuations, certificates, opinions and reports that are furnished by accountants, actuaries, legal counsel or other experts employed or engaged by the plan administrator or the Company.

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5.10Designated Payment Dates. The following designated payment dates are set forth in the Plan: under Section 3.3(b), the first day of the second month following the Participant’s Separation from Service, and under Section 4.3(b), the first day of the second month following the date of the Participant’s death. In accordance with Regulation Section 1.409A-3(d), a payment is treated as made upon the designated payment date if the payment is made (a) on the designated payment date or a later date within the Participant’s same taxable year, or if later, by the 15^th day of the third calendar month following the designated payment date, or (b) no earlier than 30 days before the designated payment date; provided, however, that the Participant must not be permitted, directly or indirectly, to designate the taxable year of the payment.

ARTICLE 6

CLAIMS PROCEDURES

6.1Presentation of Claim. Any Participant or Beneficiary, or the authorized representative of either (such Participant or Beneficiary being referred to as a “Claimant”), may deliver to the plan administrator a written claim for a determination with respect to the amounts distributable to such Claimant from the Plan. If such a claim relates to the contents of a notice received by the Claimant, the claim must be made within 60 days after such notice was received by the Claimant. All other claims must be made within 180 days of the date on which the event that caused the claim to arise occurred. The claim must state with particularity the determination desired by the Claimant.

6.2Notification of Decision. The plan administrator shall consider a Claimant’s claim within a reasonable time, but no later than 90 days after receiving the claim. If the plan administrator determines that special circumstances require an extension of time for processing the claim, written notice of the extension shall be furnished to the Claimant prior to the termination of the initial 90 day period. In no event shall such extension exceed a period of 90 days from the end of the initial period. The extension notice shall indicate the special circumstances requiring an extension of time and the date by which the plan administrator expects to render the benefit determination. The plan administrator shall notify the Claimant in writing:

(a)that the Claimant’s requested determination has been made, and that the claim has been allowed in full; or

(b)that the plan administrator has reached a conclusion contrary, in whole or in part, to the Claimant’s requested determination, in which event such notice shall set forth in a manner calculated to be understood by the Claimant;

(1)the specific reason(s) for the denial of the claim, or any part of it, or other adverse benefit determination;

(2)specific reference(s) to pertinent provisions of the Plan upon which such adverse benefit determination was based;

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(3)a description of any additional material or information necessary for the Claimant to perfect the claim, and an explanation of why such material or information is necessary;

(4)an explanation of the claim review procedure set forth in Section 6.3; and

(5)a statement of the Claimant’s right to bring a civil action under Section 5.02(a) of ERISA following an adverse benefit determination on review.

6.3Review of a Denied Claim. On or before 60 days after receiving a notice from the plan administrator that a claim has been denied, in whole or in part, or that there has been any other adverse benefit determination, a Claimant (or the Claimant’s duly authorized representative) may file with the plan administrator a written request for a review of the adverse benefit determination. The Claimant (or the Claimant’s duly authorized representative):

(a)may, upon request and free of charge, have reasonable access to, and copies of, all documents, records and other information relevant to the claim for benefits;

(b)may submit written comments, documents, records and other information relating to the claim; and/or

(c)may request a hearing, which the plan administrator, in its sole discretion, may grant.

6.4Decision on Review. The plan administrator shall render its decision on review promptly, and no later than 60 days after the plan administrator receives the Claimant’s written request for a review of the adverse benefit determination. If the plan administrator determines that special circumstances require an extension of time for processing the claim, written notice of the extension shall be furnished to the Claimant prior to the termination of the initial 60-day period. In no event shall such extension exceed a period of 60 days from the end of the initial period. The extension notice shall indicate the special circumstances requiring an extension of time and the date by which the plan administrator expects to render the benefit determination. In rendering its decision, the plan administrator shall take into account all comments, documents, records and other information submitted by the Claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination. The decision shall be written in a manner calculated to be understood by the Claimant, and shall contain:

(a)specific reasons for the decision;

(b)specific reference(s) to the pertinent Plan provisions upon which the decision was based;

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(c)a statement that the Claimant is entitled to receive, upon request and free of charge, reasonable access to and copies of, all documents, records and other information relevant (as defined in applicable ERISA regulations) to the Claimant’s claim for benefits; and

(d)a statement of the Claimant’s right to bring a civil action under Section 502(a) of ERISA.

6.5Designation of Authorized Representative. Pursuant to such procedures as the plan administrator may from time to time establish, a Participant or the Surviving Spouse may designate an authorized representative to represent him in connection with a claim for benefits.

6.6Legal Action. A Claimant’s compliance with the foregoing provisions of this Article 6 is a mandatory prerequisite to a Claimant’s right to commence any legal action with respect to any claim for benefits under the Plan.

ARTICLE 7

AMENDMENT OR TERMINATION

7.1Amendment or Termination. Although the Company anticipates that the Plan will continue indefinitely, the Company reserves the right to amend or terminate the Plan when, in the sole opinion of the Company, such amendment to termination is advisable. Any such amendment or termination shall be made pursuant to a resolution of the Compensation Committee of the Board and shall be effective as of the date of such resolution. This Section 7.1 incorporates the termination restrictions referred to in Section 3.7.

7.2Effect of Amendment or Termination. No amendment or termination of the Plan shall directly or indirectly deprive any current or former Participant, Surviving Spouse or Beneficiary of all or any portion of any benefit that has commenced prior to the effective date of such amendment or termination, or that would be payable followingthe Participant’s Separation from Service for any reason, including death, on such effective date; provided, however, that consistent with the termination restrictions referred to in Section 3.7, which are incorporated into this Section 7.2, Plan benefits may be accelerated upon Plan termination.

ARTICLE 8

GENERAL PROVISIONS

8.1Funding. The Plan at all times shall be entirely unfunded and no provision shall at any time be made with respect to segregating any assets of the Company for payment of any benefits hereunder. No Participant, Surviving Spouse or other person shall have any interest in any particular assets of the Company by reason of the right to receive a benefit under the Plan, and any such Participant, Surviving Spouse or other person shall have only the rights of a general unsecured creditor of the Company with respect to any rights under the Plan.

8.2General Conditions. Except as otherwise expressly provided herein, and to the extent consistent with Code Section 409A, all terms and conditions of the Qualified Plan applicable to benefits payable under the Qualified Plan shall also be applicable to benefits

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payable hereunder. Any benefit payable under the Qualified Plan shall be paid solely in accordance with the terms and conditions of the Qualified Plan and nothing in this Plan shall operate or be construed in any way to modify, amend or affect the terms and provisions of the Qualified Plan.

8.3No Guaranty of Benefits. Nothing contained in the Plan shall constitute a guaranty by the Company or any other entity or person that the assets of the Company will be sufficient to pay any benefit hereunder.

8.4No Employment Rights. Neither the Plan nor any action taken under the Plan shall be construed as giving to any Participant the right to be retained by the Company an employeeor in any other capacity, or as affecting the right of the Company to terminate its employment relationship with a Participant at any time, with or without cause.

8.5Unsecured General Creditors. Participants and Beneficiaries, and their heirs, successors and assigns shall have no legal or equitable rights, interests or claims in any property or assets of the Company. For purposes of the payment of benefits under the Plan, any and all of the Company’s assets shall be, and remain, the general, unpledged unrestricted assets of the Company. The Company’s obligation under the Plan shall be merely that of an unfunded and unsecured promise to make benefit payments in the future.

8.6No Assignment. The right of any Participant or other person to the payment of a benefit under the Plan shall not be anticipated, alienated, sold, transferred, assigned, pledged, encumbered, attached or garnished, either voluntarily or by operation of law, except as provided in this Section 8.6 or Section 8.7 with respect to former Spouses. If any person shall attempt to anticipate, alienate, sell, transfer, assign, pledge, encumber, attach or garnish any amount payable under the Plan, or if by reason of his bankruptcy or other event happening at any time any such payment would be made subject to his debts or liabilities or would otherwise devolve upon anyone else and not be enjoyed by him, his Surviving Spouse or Beneficiary, as applicable, the plan administrator may, in its sole discretion, terminate such person’s interest in any such payment and direct that the same be held and applied to or for the benefit of such person, his Spouse, children or other dependents, or any other persons deemed to be the natural objects of his bounty, or any of them, in such manner as the plan administrator may deem proper. Notwithstanding the foregoing, if a Participant’s Spouse is awarded all or a portion of a Participant’s benefit under the Plan pursuant to a division of property in connection with a divorce, such Spouse’s share of the Participant’s benefit shall be her separate property, and to the extent that a benefit is available under the Plan following the death of the former Spouse, shall be transferable by the Participant’s former Spouse by beneficiary designation on a form approved by, and filed with, the Committee. In order to be effective, notice of such division of the Participant’s benefit under the Plan pursuant to a division of property in connection with divorce must be provided to the Committee. Any such share of a Participant’s benefit to which the Participant’s former Spouse may be entitled shall be distributed to the former Spouse in a lump sum in cash as soon as is administratively practicable following the plan administrator’s approval of the division of property as prescribed in this Section 8.6 or in Section 8.7.

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8.7Court Order. The plan administrator is authorized to comply with any court order in any action in which the Plan or the plan administrator has been named as a party, including any action involving a determination of the rights or interests in a Participant’s benefits under the Plan. Notwithstanding the foregoing, the plan administrator shall, to the extent necessary, interpret this provision in a manner that is consistent with Code Section 409A and other applicable tax law. In addition, if necessary to comply with a qualified domestic relations order, as defined in Code Section 414(p)(1)(B), pursuant to which a court has determined that a Spouse or former Spouse of a Participant has an interest in the Participant’s benefits under the Plan, the plan administrator, in its sole discretion, shall have the right to immediately distribute the Spouse’s or former Spouse’s interest in the Participant’s benefits under the Plan to such Spouse or former Spouse.

8.8Effect of Payment. The full payment of the benefit to which a Participant, Surviving Spouse or Beneficiary (as applicable) is entitled under the terms of this Plan shall completely discharge all obligations of the Company to the Participant, Surviving Spouse or Beneficiary (as applicable).

8.9Spendthrift Provision. Except as may be provided in Section 8.6 or 8.7 with respect to a Spouse being awarded all or a portion of a Participant’s benefit pursuant to a division of property in connection with a divorce, or pursuant to a valid court order, no interest of any person or entity in, or right to receive a benefit under, the Plan shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, encumbrance, attachment or garnishment of any kind; nor may such interest or right to receive a benefit be taken, either voluntarily or involuntarily, for the satisfaction of the debts of, or other obligations or claims against, such person or entity, including claims for alimony, support, separate maintenance and claims in bankruptcy proceedings.

8.10Applicable Law. The Plan shall be construed and administered under the laws of the State of Texas, except to the extent preempted by applicable federal law.

8.11Withholding of Taxes. The Company shall deduct from the amount of any benefits that may be or become payable (before the amount is paid or made available to the Participant), or payments made pursuant to the Plan, any amounts required to be paid or withheld by the federal government or any state or local government, including a payment to pay the income tax at source on wages imposed by the Code as a result of such payment and to pay the additional income tax at source on wages imposed by the Code attributable to such additional wages and taxes (not to exceed the aggregate of the tax amount and the income tax withholding related to such amount). By the Participant’s participation in the Plan, the Participant, Surviving Spouse and Beneficiary agree to all deductions.

8.12Incompetent. If the plan administrator determines in its discretion that a benefit under the Plan is to be paid to a person declared incompetent or to a person incapable of handling his affairs because of accident or illness, the plan administrator may direct payment of such benefit to the guardian, legal representative or person having the care and custody of the incompetent or incapable person. The plan administrator may require such proof of incompetence, incapacity or guardianship, as it may deem appropriate prior to distribution of the

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benefits. Any payment of a benefit under this Section 8.12 shall be a payment for the account of the Participant, Surviving Spouse or Beneficiary, as the case may be, and shall be a complete discharge of any liability under the Plan for such payment amount.

8.13Corporate Successors. The Plan shall not be automatically terminated by a transfer or sale of assets of the Company, or by the merger or consolidation of the Company into or with any other corporation or other entity, but the Plan shall be continued after such sale, merger or consolidation only if and to the extent that the transferee, purchaser or successor entity agrees to continue the Plan. In the event that the Plan is not continued by the transferee, purchaser or successor entity, then the Plan shall terminate subject to the provisions of Sections 3.7, 7.1 and 7.2.

8.14Payment in the Event of Taxation. If, for any reason, all or any portion of a Participant’s benefit fails to meet the requirements of Code Section 409A and becomes taxable to the Participant prior to receipt, the Committee, on behalf of the Company, may, in its discretion, pay to the Participant that portion of the Participant’s benefit that has become taxable prior to the date otherwise provided in the Plan. The payment shall not exceed the amount required to be included in income as a result of the failure to comply with the requirements of Code Section 409A and the Regulations thereunder. The preceding provisions of this Section 8.14 notwithstanding, (a) discretion under this Section 8.14 is provided only to the Committee, not directly or indirectly to the Participant, and (b) in exercising discretion under this Section 8.14, the Committee shall not treat similarly situated Participants differently.

8.15Overpayment and Underpayment of Benefits. The Committee may adopt, in its sole discretion, whatever rules, procedures and accounting practices that comply with Code Section 409A and are appropriate in providing for the collection of any overpayment of benefits. To the extent permitted by Code Section 409A, if an overpayment is made to a Participant, Surviving Spouse, Beneficiary or any other person, for whatever reason, the Committee may, in its sole discretion, withhold payment of any further benefits under the Plan until the overpayment has been collected or may require repayment of benefits paid under this Plan, without regard to further benefits to which the person may be entitled and, to the extent deemed necessary by the Committee, in its sole discretion, the Committee may seek repayment of such overpaid amounts through any and all available legal actions, including filing suit in a court with appropriate jurisdiction. If a Participant, Surviving Spouse, Beneficiaryor any other person receives an underpayment of benefits, the Committee shall direct that immediate payment be made to make up for the underpayment; provided, however, that such payment shall be made in a manner that complies with Code Section 409A. To the extent that corrections contemplated by this Section 8.15 are required to be made in accordance with IRS correction guidance, including Notice 2008-113 regarding compliance by the Plan with Code Section 409A, such corrections shall be made in accordance with such guidance.

8.16Captions and Construction. The captions preceding the Articles and Sections of the Plan have been inserted solely as a matter of convenience and in no way define or limit the scope or intent of any provisions of the Plan. Where the context admits or requires, words used in the masculine gender shall be construed to include the feminine and the neuter also, the plural

20

shall include the singular, and the singular shall include the plural. As used herein, references to “including” shall be construed to mean “including, but not limited to.”

8.17Severability. In case any one or more of the provisions contained in the Plan shall be found to be invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions in the Plan shall not in any way be affected or impaired.

8.18Limitations on Liability. Notwithstanding any provision of the Plan, neither the Company nor any individual acting as an employee or agent of the Company shall be liable to any Participant, Surviving Spouse, Beneficiary or any other person for any claim, loss, liability or expense incurred in connection with the Plan.

8.19Spouse’s Interest. Except as may be provided in Sections 8.6 and 8.7, with respect to a Spouse being awarded all or a portion of a Participant’s benefit pursuant to a division of property in connection with a divorce, or pursuant to a valid court order, the interest in a Participant’s benefit hereunder of a Participant’s Spouse, if any, who has predeceased the Participant shall automatically pass to the Participant and shall not be transferable by such Spouse or such Spouse’s estate in any manner, including such Spouse’s will, nor shall such interest pass under the laws of intestate succession.

8.20Code Section 409A Compliance. In all cases, the Plan shall continue to be construed and operated in a manner that is consistent with the requirements of Code Section 409A and guidance issued thereunder.

IN WITNESS WHEREOF, the Company has caused this Plan to be executed by a duly authorized officer this 27 day of March, 2014.

	EL PASO ELECTRIC COMPANY
By:	/s/ William Stiller
Name:	William Stiller
Title:	SRVP of Human Resources and
	Customer Care

21

EX-10.28-08

Exhibit 10.28-08

	P.O. Box 982
	El Paso, Texas
	79960-0982
	(915) 543-5711

Emmanuel Villalobos

Senior Forward Marketer, Long-Term Trading

El Paso Electric Company

October 24, 2016

Mr. Don Stoneberger

Freeport-McMoRan Copper & Gold Energy Services

333 North Central Avenue Suite 21.021

Phoenix, AZ 85004

Re:    Power Purchase and Sale Agreeement between Freeport-McMoRan Copper & Gold Energy

Services, LLC and El Paso Electric Company

Dear Mr. Stoneberger,

Pursuant to Section 3.4 of the Power Purchase and Sale Agreement (“Agreement”) between Freeport-McMoRan Copper & Gold Energy Services, LLC (“FMES”) (formerly, Phelps Dodge Energy Services, LLC) and El Paso Electric Company (“EPE”), as memorialized by letter agreement dated March 23, 2015 among FMES, EPE and Samchully Power & Utilities 1, LLC, FMES and EPE (collectively the “Parties”) hereby agree to maintain the quantity for energy to be purchased and sold under Sections 3.1 and 3.2 of the Agreement at 125 MW per hour through 11:59 p.m. Mountain Standard Time on December 31, 2018. This is in accordance with our recent phone conversations, and subsequent acceptance of FMES’ offer for an additional 25 MW for the period of two years. The parties further agree that the quantity of firm energy that may be dispatched by EPE pursuant to Section 3.6 of the Agreement is 125 MW per hour, less the quantity of energy sold and delivered by FMES pursuant to Section 3.1. The amount of energy to be purchased and sold under the Agreement was set to revert to the original base contract amount of 100 MW per hour, on 11:59 p.m. Mountain Standard Time on December 31, 2016, based on a October 13, 2015 agreement between the Parties.

Please indicate FMES' acknowledgment of the foregoing agreement by signing this letter in the place indicated below and returning the original or a copy thereof to my attention at your earliest convenience.

Sincerely,

/s/ Emmanuel Villalobos

Emmanuel Villalobos

Page 1 of 2

[AUTHORIZING SIGNATURES]

El Paso Electric Company

/s/ David C. Hawkins

VP System Operations Resource Planning & Management

Freeport-McMoRan Copper & Gold Energy Services, LLC

/s/ Don Stoneberger

President, Freeport-McMoRan Copper & Gold Energy Services, LLC

Cc:    D.H. Kim

Samchully Power & Utilities 1, LLC

Page 2 of 2

EX-12.01

EXHIBIT 12.01

El Paso Electric Company
Computation of Ratios of Earnings to Fixed Charges
(Dollars in Thousands)
	Years Ended December 31,
	2016			2015			2014			2013			2012
Earnings from Continuing
Operations (a)	$	150,080		$	116,813		$	132,516		$	132,238		$	137,825
Fixed Charges (b)
Interest charges	72,847			67,164			60,278			59,066			55,822
Interest portion of rent expense	607			857			829			823			939
Total Fixed Charges	73,454			68,021			61,107			59,889			56,761
Capitalized Interest	(16,996		)	(22,544		)	(28,122		)	(21,362		)	(20,312		)
Earnings (c)	$	206,538		$	162,290		$	165,501		$	170,765		$	174,274
Ratio of Earnings to Fixed Charges	2.8			2.4			2.7			2.9			3.1

_______________________

(a) Earnings from continuing operations consist of income from continuing operations before income taxes, extraordinary item and cumulative effects of accounting changes.

(b) Fixed charges consist of all interest on indebtedness, amortization of debt discount and expense and the estimated portion of rental expense that represents an interest factor.

(c) Earnings consist of earnings from continuing operations and fixed charges less AFUDC and capitalized interest.

EX-23.01

EXHIBIT 23.01

Consent of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

El Paso Electric Company:

We consent to the incorporation by reference in the registration statement (Nos. 333-142557 and 333-196628) on Form S-8 and (No. 333-198989) on Form S‑3 of El Paso Electric Company of our report dated February 24, 2017, with respect to the balance sheets of El Paso Electric Company as of December 31, 2016 and 2015, 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, 2016, and the effectiveness of internal control over financial reporting as of December 31, 2016, which report appears in the December 31, 2016 annual report on Form 10-K of El Paso Electric Company.

/s/ KPMG LLP

Houston, Texas

February 24, 2017

EX-24.02

EXHIBIT 24.02

EL PASO ELECTRIC COMPANY

CERTIFICATE OF RESOLUTION

I, Jessica Goldman, Corporate Secretary of El Paso Electric Company, a Texas corporation (the “Company”), do hereby certify that attached hereto is a true, correct and complete copy of the resolution authorizing signatures pursuant to a Power of Attorney for the 2016 Annual Report on Form 10-K, duly adopted by the Board of Directors of the Company at a meeting of said Board duly convened and held on January 26, 2017.

IN WITNESS THEREOF, I have hereunto set my hand and have affixed the seal of the Company this 26^th day of January 2017.

/s/ JESSICA GOLDMAN

Jessica Goldman

Corporate Secretary

(Corporate Seal)

EXHIBIT 24.02

EL PASO ELECTRIC COMPANY

RESOLUTION OF THE BOARD OF DIRECTORS

January 26, 2017

RESOLVED, that Mary E. Kipp, Nathan T. Hirschi, John R. Boomer and Russell G. Gibson are hereby duly appointed the Company’s, and its Officers’ and Directors’, true and lawful attorneys-in-fact and agents, for their place and stead, in any and all capacities, with full power to act alone, to sign the Company’s 2016 Annual Report on Form 10-K, and in any and all amendments thereto, and to file such 2016 Annual Report on Form 10-K and each such amendment, with all exhibits thereto, and any and all documents in connection therewith, with the Securities and Exchange Commission, hereby granting unto each of the said attorneys-in-fact and agents, full power and authority to do and perform any and all acts and things requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

EX-31.01

EXHIBIT 31.01

CERTIFICATIONS

I, Mary E. Kipp, certify that:

1. I have reviewed this annual report on Form 10-K of El Paso Electric Company (the "Company"):

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this report;

4. The Company's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Company and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the Company's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the Company's internal control over financial reporting that occurred during the Company's most recent fiscal quarter (the Company's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting; and

5. The Company's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Company's auditors and the audit committee of the Company's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Company's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Company's internal control over financial reporting.

Dated: February 24, 2017

EL PASO ELECTRIC COMPANY
By:	/s/ Mary E. Kipp
	Mary E. Kipp
	Chief Executive Officer
	(Principal Executive Officer)

I, Nathan T. Hirschi, certify that:

1. I have reviewed this annual report on Form 10-K of El Paso Electric Company (the "Company"):

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this report;

4. The Company's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Company and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the Company's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the Company's internal control over financial reporting that occurred during the Company's most recent fiscal quarter (the Company's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting; and

5. The Company's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Company's auditors and the audit committee of the Company's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Company's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Company's internal control over financial reporting.

Dated: February 24, 2017

EL PASO ELECTRIC COMPANY
By:	/s/ Nathan T. Hirschi
	Nathan T. Hirschi
	Senior Vice President -
	Chief Financial Officer
	(Principal Financial Officer)

EX-32.01

EXHIBIT 32.01

February 24, 2017

The certification set forth below is being submitted in connection with the Annual Report on Form 10-K for the fiscal year ended December 31, 2016 (the "Report") of El Paso Electric Company (the "Company") for the purpose of complying with Rule 13a-14(b) or Rule 15d-14(b) of the Securities Exchange Act of 1934 (the "Exchange Act") and Section 1350 of Chapter 63 of Title 18 of the United States Code.

Mary E. Kipp and Nathan T. Hirschi, each certifies that, to the best of their knowledge:

1.the Report fully complies with the requirements of Section 13(a) or 15(d) of the Exchange Act; and

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

 /s/ Mary E. Kipp

Mary E. Kipp

Chief Executive Officer

/s/ Nathan T. Hirschi

Nathan T. Hirschi

Senior Vice President -

Chief Financial Officer

XML

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Jan. 31, 2017	Jun. 30, 2016
Document and Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	FY
Trading Symbol	EE
Entity Registrant Name	EL PASO ELECTRIC CO /TX/
Entity Central Index Key	0000031978
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		40,557,679
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 1,883,999,218

XML

BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Utility plant:
Electric plant in service	$ 3,791,566	$ 3,616,301
Less accumulated depreciation and amortization	(1,244,332)	(1,329,843)
Net plant in service	2,547,234	2,286,458
Construction work in progress	154,738	293,796
Nuclear fuel; includes fuel in process of $57,315 and $51,854, respectively	194,842	190,282
Less accumulated amortization	(75,602)	(75,031)
Net nuclear fuel	119,240	115,251
Net utility plant	2,821,212	2,695,505
Current assets:
Cash and cash equivalents	8,420	8,149
Accounts receivable, principally trade, net of allowance for doubtful accounts of $2,156 and $2,046, respectively	88,452	66,326
Inventories, at cost	47,216	48,697
Under-collection of fuel revenues	11,123	0
Prepayments and other	8,988	9,872
Total current assets	164,199	133,044
Deferred charges and other assets:
Decommissioning trust funds	255,708	239,035
Regulatory assets	118,861	115,127
Other	16,298	17,896
Total deferred charges and other assets	390,867	372,058
Total assets	3,376,278	3,200,607
Capitalization:
Common stock, stated value $1 per share, 100,000,000 shares authorized, 65,685,615 and 65,709,819 shares issued, and 137,017 and 118,834 restricted shares, respectively	65,823	65,829
Capital in excess of stated value	322,643	320,073
Retained earnings	1,114,561	1,067,396
Accumulated other comprehensive loss, net of tax	(7,116)	(13,914)
Total stockholders' equity subtotal before treasury stock	1,495,911	1,439,384
Treasury stock, 25,304,914 and 25,384,834 shares, respectively, at cost	(421,515)	(422,846)
Common stock equity	1,074,396	1,016,538
Long-term debt, net of current portion	1,195,513	1,122,660	[1]
Total capitalization	2,269,909	2,139,198
Current liabilities:
Current maturities of long-term debt	83,143	0	[1]
Short-term borrowings under the revolving credit facility	81,574	141,738	[1]
Accounts payable, principally trade	62,953	59,978
Taxes accrued	32,488	30,351
Interest accrued	13,287	12,649
Over-collection of fuel revenues	255	4,023
Other	29,709	28,325
Total current liabilities	303,409	277,064
Deferred credits and other liabilities:
Accumulated deferred income taxes	555,066	495,237
Accrued pension liability	92,768	90,527
Accrued postretirement benefit liability	34,400	54,553
Asset retirement obligation	81,800	81,621
Regulatory liabilities	18,435	24,303
Other	20,491	38,104
Total deferred credits and other liabilities	802,960	784,345
Commitments and contingencies
Total capitalization and liabilities	$ 3,376,278	$ 3,200,607

[1] The Company implemented ASU 2015-03, Interest - Imputation of Interest, which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The impact of ASU 2015-03 on the Company's Balance Sheet was to reclassify $11.6 million of other deferred charges to long-term debt, net of current portion at December 31, 2015.

XML

BALANCE SHEETS (Parentheticals) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Nuclear fuel; fuel in process	$ 57,315	$ 51,854
Allowance for Doubtful Accounts Receivable, Current	$ 2,156	$ 2,046
Common Stock, Par or Stated Value Per Share	$ 1	$ 1
Common Stock, Shares Authorized	100,000,000	100,000,000
Common Stock, Shares Issued	65,685,615	65,709,819
Common Stock, Restricted Shares	137,017	118,834
Treasury Stock, Shares	25,304,914	25,384,834

XML

STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating revenues	$ 886,936	$ 849,869	$ 917,525
Energy expenses:
Fuel	173,738	188,400	251,005
Purchased and interchanged power	59,727	53,545	64,804
Cost of services, energy services	233,465	241,945	315,809
Operating revenues net of energy expenses	653,471	607,924	601,716
Other operating expenses:
Other operations	242,014	242,950	238,832
Maintenance	66,746	65,223	65,629
Depreciation and amortization	84,317	89,824	83,342
Taxes other than income taxes	65,533	63,736	62,750
Utilities operating expense	458,610	461,733	450,553
Operating income	194,861	146,191	151,163
Other income (deductions):
Allowance for equity funds used during construction	7,023	10,639	14,662
Investment and interest income, net	14,083	17,508	13,633
Miscellaneous non-operating income	1,292	2,062	4,075
Miscellaneous non-operating deductions	(3,699)	(4,328)	(4,199)
Nonoperating income (expense)	18,699	25,881	28,171
Interest charges (credits):
Interest on long-term debt and revolving credit facility	71,544	65,851	59,028
Other interest	1,303	1,313	1,250
Capitalized interest	(4,990)	(4,968)	(5,092)
Allowance for borrowed funds used during construction	(4,983)	(6,937)	(8,368)
Interest expense	62,874	55,259	46,818
Income before income taxes	150,686	116,813	132,516
Income tax expense	53,918	34,895	41,088
Net income	$ 96,768	$ 81,918	$ 91,428
Basic earnings per share	$ 2.390	$ 2.030	$ 2.270
Diluted earnings per share	2.390	2.030	2.270
Dividends declared per share of common stock	$ 1.225	$ 1.165	$ 1.105
Weighted average number of shares outstanding	40,350,688	40,274,986	40,190,991
Weighted average number of shares and dilutive potential shares outstanding	40,408,033	40,308,562	40,211,717

XML

STATEMENTS OF COMPREHENSIVE OPERATIONS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net income	$ 96,768	$ 81,918	$ 91,428
Unrecognized pension and post-retirement benefit costs:
Net gain (loss) arising during period	(20,053)	5,429	(54,328)
Prior service benefit	32,697	824	34,200
Reclassification adjustments included in net income for amortization of:
Prior service benefit	(7,407)	(6,574)	(7,659)
Net loss	4,965	8,622	6,182
Net unrealized gains/losses on marketable securities:
Net holding gains (losses) arising during period	8,444	(2,906)	10,827
Reclassification adjustments for net gains included in net income	(7,640)	(11,114)	(7,350)
Net losses on cash flow hedges:
Reclassification adjustment for interest expense included in net income	498	467	438
Total other comprehensive income (loss) before income taxes	11,504	(5,252)	(17,690)
Income tax benefit (expense) related to items of other comprehensive income (loss):
Unrecognized pension and post-retirement benefit costs	(4,261)	(3,286)	8,051
Net unrealized (gains) losses on marketable securities	(106)	2,828	(760)
Losses on cash flow hedges	(339)	(203)	(214)
Total income tax benefit (expense)	(4,706)	(661)	7,077
Other comprehensive income (loss), net of tax	6,798	(5,913)	(10,613)
Comprehensive income	$ 103,566	$ 76,005	$ 80,815

XML

STATEMENTS OF CHANGES IN COMMON STOCK EQUITY - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss), Net of Tax	Treasury Stock
Balances at beginning of period (in shares) at Dec. 31, 2013		65,759,625				25,492,919
Balances at beginning of period at Dec. 31, 2013	$ 943,833	$ 65,760	$ 314,443	$ 985,665	$ 2,612	$ (424,647)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted common stock grants and deferred compensation (in shares)		103,672
Restricted common stock grants and deferred compensation	4,279	$ 104	4,175
Stock awards withheld for taxes (in shares)		(4,696)
Stock awards withheld for taxes	(188)	$ (5)	(183)
Forfeited restricted common stock (in shares)		(19,162)
Forfeited restricted common stock	(19)	$ (19)
Deferred taxes on stock incentive plan	(302)		(302)
Grants of share based compensation (in shares)		(10,104)
Grants of share based compensation	392	$ 10	382
Net income	91,428			91,428
Other comprehensive income (loss)	(10,613)				(10,613)
Dividends, Common Stock, Cash	(44,556)			(44,556)
Balances at end of period (in shares) at Dec. 31, 2014		65,849,543				25,492,919
Balances at end of period at Dec. 31, 2014	984,254	$ 65,850	318,515	1,032,537	(8,001)	$ (424,647)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted common stock grants and deferred compensation (in shares)		6,356
Restricted common stock grants and deferred compensation	3,829	$ 6	2,266
Stock Issued During Period, Shares, Treasury Stock Reissued						(93,455)
Stock Issued During Period, Value, Treasury Stock Reissued						$ 1,557
Stock awards withheld for taxes (in shares)		(15,031)
Stock awards withheld for taxes	(571)	$ (15)	(556)
Forfeited restricted common stock (in shares)		(12,215)				(871)
Forfeited restricted common stock	(26)	$ (12)				$ (14)
Deferred taxes on stock incentive plan	(475)		(475)
Grants of share based compensation (in shares)						(15,501)
Grants of share based compensation	581		323			$ 258
Net income	81,918			81,918
Other comprehensive income (loss)	(5,913)				(5,913)
Dividends, Common Stock, Cash	$ (47,059)			(47,059)
Balances at end of period (in shares) at Dec. 31, 2015	65,709,819	65,828,653				25,384,834
Balances at end of period at Dec. 31, 2015	$ 1,016,538	$ 65,829	320,073	1,067,396	(13,914)	$ (422,846)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted common stock grants and deferred compensation	$ 4,252		3,017
Stock Issued During Period, Shares, Treasury Stock Reissued	(188,005)					(74,181)
Stock Issued During Period, Value, Treasury Stock Reissued						$ 1,235
Stock awards withheld for taxes (in shares)		(5,723)
Stock awards withheld for taxes	$ (267)	$ (6)	(261)
Forfeited restricted common stock (in shares)		(298)				(197)
Forfeited restricted common stock	(3)					$ (3)
Deferred taxes on stock incentive plan	(364)		(364)
Grants of share based compensation (in shares)						(5,936)
Grants of share based compensation	277		178			$ 99
Net income	96,768			96,768
Other comprehensive income (loss)	6,798				6,798
Dividends, Common Stock, Cash	$ (49,603)			(49,603)
Balances at end of period (in shares) at Dec. 31, 2016	65,685,615	65,822,632				25,304,914
Balances at end of period at Dec. 31, 2016	$ 1,074,396	$ 65,823	$ 322,643	$ 1,114,561	$ (7,116)	$ (421,515)

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Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net income	$ 96,768	$ 81,918	$ 91,428
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service	84,317	89,824	83,342
Amortization of nuclear fuel	43,748	43,099	43,864
Deferred income taxes, net	50,510	30,846	39,129
Allowance for equity funds used during construction	(7,023)	(10,639)	(14,662)
Other amortization and accretion	17,295	17,707	18,380
Gain on sale of property, plant and equipment	(545)	(658)	(2,092)
Net gains on sale of decommissioning trust funds	(7,640)	(11,114)	(7,350)
Other operating activities	1,279	517	(93)
Change in:
Accounts receivable	(17,511)	4,839	(5,815)
Inventories	265	(2,859)	(786)
Net over-collection (under-collection) of fuel revenues	(14,891)	13,344	(3,121)
Prepayments and other	(1,184)	(3,984)	(2,750)
Accounts payable	(2,140)	(11,235)	9,684
Taxes accrued	1,945	4,512	(2,209)
Other current liabilities	2,022	3,719	1,198
Deferred charges and credits	(16,065)	(3,165)	(4,807)
Net cash provided by operating activities	231,150	246,671	243,340
Cash flows from investing activities:
Cash additions to utility property, plant and equipment	(225,361)	(281,458)	(277,078)
Cash additions to nuclear fuel	(42,383)	(41,966)	(37,877)
Capitalized interest and AFUDC:
Utility property, plant and equipment	(12,006)	(17,576)	(23,030)
Nuclear fuel	(4,990)	(4,968)	(5,092)
Allowance for equity funds used during construction	7,023	10,639	14,662
Decommissioning trust funds:
Purchases, including funding of $4.5 million	(99,497)	(110,223)	(117,675)
Sales and maturities	91,268	102,567	108,311
Proceeds from sale of property, plant, and equipment	4,841	721	2,395
Other investing activities	5,373	(470)	4,192
Net cash used for investing activities	(275,732)	(342,734)	(331,192)
Cash flows from financing activities:
Dividends paid	(49,603)	(47,059)	(44,556)
Borrowings under the revolving credit facility:
Proceeds	355,607	344,398	231,399
Payments	(415,771)	(217,192)	(231,219)
Payment on maturing RGRT senior notes	0	(15,000)	0
Proceeds from issuance of senior notes	157,052	0	149,468
Other financing activities	(2,432)	(1,439)	(2,328)
Net cash provided by financing activities	44,853	63,708	102,764
Net increase (decrease) in cash and cash equivalents	271	(32,355)	14,912
Cash and cash equivalents at beginning of period	8,149	40,504	25,592
Cash and cash equivalents at end of period	$ 8,420	$ 8,149	$ 40,504

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Statements of Cash Flows Parenthetical - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Payments To Fund Decommissioning Fund	$ 4.5	$ 4.5	$ 4.5

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Significant Accounting Policies

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 generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company evaluates its estimates on an on-going basis, including those related to depreciation, unbilled revenue, income taxes, fuel costs, pension and other post-retirement obligations and asset retirement obligations ("ARO"). Actual results could differ from those estimates.

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 2016, 2015 and 2014 was 2.28%, 2.64%, and 2.60%, 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 in the most recent final orders from the Public Utility Commission of Texas ("PUCT") and the New Mexico Public Regulation Commission ("NMPRC") and changes in the estimated life of certain intangible software assets. See Part II, Item 8, Financial Statements and Supplementary Data, Note C and Note E.

Previously, the Company recorded gains and losses on the disposition of vehicles in earnings when realized. However, beginning in 2016, the Company began crediting the proceeds (salvage) on the disposition of vehicles to accumulated depreciation.

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 Nuclear 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.

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. AFUDC is compounded on a semi-annual basis. The average AFUDC rates used in 2016, 2015 and 2014 were 6.43%, 7.18% and 8.15%, 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. All temporary cash investments with an original maturity of three months or less are considered cash equivalents.

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 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 $21.0 million and $21.7 million as of December 31, 2016 and 2015, 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 2016, 2015 and 2014 are as follows (in thousands):

	2016		2015		2014
Balance at beginning of year	$	2,046	$	2,253	$	2,261
Additions:
Charged to costs and expense	2,427		2,057		2,755
Recovery of previous write-offs	1,395		1,613		1,516
Uncollectible receivables written off	3,712		3,877		4,279
Balance at end of year	$	2,156	$	2,046	$	2,253

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. Historically, 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. 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.

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 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.

Reclassification. Certain amounts in the Company's financial statements for 2015 have been reclassified to conform to the 2016 presentation. The Company implemented Accounting Standards Update ("ASU") 2015-03 and ASU 2015-17 in the first quarter of 2016, retrospectively to all periods presented in the Company's financial statements. See Part II, Item 8, Financial Statements and Supplementary Data, Note I and Note O for impact of ASU 2015-03, and Note J for impact of ASU 2015-17.

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New Accounting Standards

12 Months Ended

Dec. 31, 2016

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncements and Changes in Accounting Principles

New Accounting Standards

In May 2014, the FASB issuedASU2014-09, 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. Early adoption of ASU 2014-09 is permitted after December 15, 2016, however, the Company plans to adopt the new standard for reporting periods beginning after December 15, 2017.

Under the new standard, companies may use either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). The Company has not concluded which transition method it will elect but it currently anticipates using the modified retrospective approach.

The Company is currently in the process of evaluating the impact of the new standard on its various revenue and cash flow streams, including the evaluation of the impact, if any, on changes to business processes, systems and controls to support recognition and disclosure 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 not completed its final evaluation of tariff sales under the new guidance but currently does not anticipate that ASU 2014-09 will have a material impact on the Company's revenue recognition for such sales. The Company is still considering the impacts of the guidance on several industry-related accounting issues, including the accounting for contributions in aid of construction ("CIAC"), assessing the collectability criterion and the presentation of revenues associated with alternative revenue programs. The Company's initial assessment may change as we execute our implementation plan and new guidance is provided by the American Institute of Certified Public Accountants Power and Utilities Industry Task Force.

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 public companies for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Upon adoption of the new standard, the Company expects to record the cumulative effects as of January 1, 2018 which will result in an adjustment to accumulated other comprehensive income (losses) and retained earnings for unrealized gains (losses) related to equity securities owned by the Company. Had the Company been required to adopt the new standard at January 1, 2016, accumulated other comprehensive income would decrease by$28.8 millionand retained earnings would increase by a corresponding amount. Furthermore, the Company would report for the year ended December 31, 2016 an increase in investment income of$1.2 million, an increase in income tax expense of$0.2 millionand a decrease in other comprehensive income of$1.0 million. The Company is continuing to assess the future impact of this ASU.

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

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. The Company will adopt the new standard effective January 1, 2017 and does not expect the effect of the adoption to be material to the Company's financial condition, results of operations or cash flows. The cumulative effect of the adoption of the new standard will be to increase net operating loss carryforward deferred tax assets and retained earnings by approximately$0.2 millionon January 1, 2017. The Company also expects to continue to account for its outstanding stock awards based on the equity method and therefore does not anticipate any changes in reporting related compensation expense.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326) ("ASU 2016-13"). 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. For public business entities, the provisions of ASU 2016-13 are effective for fiscal years and interim periods within that reporting period beginning after December 15, 2019. Early implementation is permitted as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. ASU 2016-13 will be applied in a modified-retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is implemented. The Company is currently assessing the future impact of 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 new guidance addresses the following classification issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon bonds; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. For public business entities, the provisions of ASU 2016-15 are effective for fiscal years and interim periods within that reporting period beginning after December 15, 2017. Early adoption is permitted, including adoption in an interim period. If an entity elects early adoption of ASU 2016-15 in an interim period, adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. 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 December 2016, the FASB issued ASU 2016-19, Technical Corrections and Improvements, which amends a number of Topics in the FASB ASC. This ASU is part of an ongoing FASB project to facilitate Codification updates for non-substantive technical corrections, clarifications, and improvements that are not expected to have a significant effect on accounting practice or create a significant administrative cost to most entities. Most of the amendments are effective upon issuance of ASU 2016-19 while certain amendments that require transition guidance are effective for the Company beginning January 1, 2017. The Company believes it is in compliance with those amendments that are effective immediately and that are applicable to the Company. The Company has not completed its evaluation of the new standard for amendments that require transition guidance.

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Regulation

12 Months Ended

Dec. 31, 2015

Public Utilities, General Disclosures [Abstract]

Regulation

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 (the "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 "Unopposed Settlement"). On August 25, 2016, the PUCT approved the Unopposed Settlement and issued its final order in Docket No. 44941 (the "PUCT Final Order"), as proposed. The 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 millionrelated to Four Corners Generating Station ("Four Corners") costs, which will be collected through a surcharge terminating on July 12, 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 millionin rate case expenses through a separate surcharge and (v) allowing the Company to recover revenues associated with the relate back of rates to consumption on and after January 12, 2016 through March 31, 2016 through a separate surcharge.

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

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

2017 Texas Retail Rate Case Filing.On February 13, 2017, the Company filed with the City of El Paso, other municipalities incorporated in the Company's Texas service territory and the PUCT in Docket No.46831, a request for an increase in non-fuel base revenues of approximately$42.5 million. The Company invoked its statutory right to have its new rates relate back for consumption on and after July 18, 2017, which is the 155th day after the filing. The difference in rates that would have been billed will be surcharged or refunded to customers after the PUCT's final order in Docket No. 46831. The PUCT has the authority to require the Company to surcharge or refund such difference over a period not to exceed 18 months. The Company cannot predict the outcome or the timing of this rate case at this time.

Energy Efficiency Cost Recovery Factor. On May 1, 2015, the Company filed its annual application to establish its energy efficiency cost recovery factor for 2016. In addition to projected energy efficiency costs for 2016 and a true-up to prior year actual costs, the Company requested approval of a $1.0 millionbonus for the 2014 energy efficiency program results in accordance with PUCT rules. This case was assigned PUCT Docket No. 44677. A stipulation and settlement agreement was filed September 24, 2015 and the PUCT approved the settlement on November 5, 2015. The settlement approved by the PUCT included a performance bonus of $1.0 million. The Company recorded the performance bonus in operating revenues in the fourth quarter of 2015.

On April 29, 2016, the Company filed its annual application to establish its energy efficiency cost recovery factor for 2017. In addition to projected energy efficiency costs for 2017 and true-up to prior year actual costs, the Company requested approval of a$0.7 millionbonus for the 2015 energy efficiency program results in accordance with PUCT rules. This case was assigned PUCT Docket No. 45885. Parties in the proceeding, including PUCT staff and the City of El Paso, filed a settlement in the case that approved the Company's proposal with a reduction to the 2015 program bonus of $0.2 million. The PUCT approved the settlement on October 28, 2016. The settlement approved by the PUCT included a performance bonus of$0.5 millionwhich was recorded in operating revenues in the third quarter of 2016.

Fuel and Purchased Power Costs.The Company's actual fuel costs, including purchased power energy costs, are recovered from customers through a fixed fuel factor. The PUCT has adopted a fuel cost recovery rule (the "Texas Fuel Rule") that allows the Company to seek periodic adjustments to its fixed fuel factor. The Company can seek to revise its fixed fuel factor based upon the approved formula at least four months after its last revision except in the month of December. The Texas Fuel Rule requires the Company to request to refund fuel costs in any month when the over-recovery balance exceeds a threshold material amount and it expects fuel costs to continue to be materially over-recovered. The Texas Fuel Rule also permits the Company to seek to surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount and it expects fuel cost recovery to continue to be materially under-recovered. Fuel over and under-recoveries are considered material when they exceed4%of the previous twelve months' fuel costs. All such fuel revenue and expense activities are subject to periodic final review by the PUCT in fuel reconciliation proceedings.

On April 15, 2015, the Company filed a request, which was assigned PUCT Docket No. 44633, to reduce its fixed fuel factor by approximately 24% to reflect reduced fuel expenses primarily related to a reduction in the price of natural gas used to generate power. The over-recovered balance was below the PUCT's materiality threshold. The reduction in the fixed fuel factor was effective on an interim basis May 1, 2015 and approved by the PUCT on May 20, 2015.

On November 30, 2016, the Company filed a request, which was assigned PUCT Docket No. 46610, to increase its fixed fuel factor by approximately28.8%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 December 31, 2016, the Company had under-recovered fuel costs in the amount of$11.1 millionfor the Texas jurisdiction.

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 millionof Texas fuel and purchased power expenses incurred during the period of April 1, 2013 through March 31, 2016. A procedural schedule has been adopted with hearings in April 2017. As of December 31, 2016, Texas jurisdictional fuel and purchased power costs subject to a future Texas fuel reconciliation are approximately$114.4 million. The Company cannot predict the outcome or the timing of this matter.

Montana Power Station Approvals.The Company received Certificate of Convenience and Necessity ("CCN") approval from the PUCT to constructfournatural gas fired generating units at Montana Power Station ("MPS") in El Paso County, Texas. The Company also obtained air permits from the Texas Commission on Environmental Quality (the "TCEQ") and the U.S. Environmental Protection Agency (the "EPA"). MPS Units 1 and 2 and associated transmission lines and common facilities were completed and placed into service inMarch 2015. MPS Units 3 and 4 were completed and placed into service onMay 3, 2016andSeptember 15, 2016, respectively.

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 a3 MWsolar photovoltaic system located at MPS. Participation will be on a voluntary basis, and customers will contract for a set capacity (kW) amount and receive all energy produced. This case was assigned PUCT Docket No. 44800. The Company filed a settlement agreement among all parties on July 1, 2016 approving the program, and the PUCT approved the settlement agreement and program on September 1, 2016. The Company expects completion of the solar facility and commencement of the program in the second quarter of 2017.

Four Corners. On February 17, 2015, the Company and Arizona Public Service Company ("APS") entered into an asset purchase agreement (the "Purchase and Sale Agreement") providing for the sale of the Company's interest in Four Corners to APS.The sale of the Company's interest in Four Corners closed onJuly 6, 2016. See Part II, Item 8,Financial Statements and Supplementary Data, Note Efor further details on the sale of Four Corners.

On June 10, 2015, the Company filed an application in Texas requesting reasonableness and public interest findings and certain rate and accounting findings related to the Purchase and Sale Agreement. This case was assigned PUCT Docket No. 44805. Subsequent to the filing of the application, the case has been subject to numerous procedural matters, including a March 23, 2016 order in which the PUCT determined not to dismiss the reasonableness and public interest issues in this docket but to consider the requested rate and accounting findings, including mine reclamation costs, in 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, and the parties are engaged in settlement discussions.

At December 31, 2016, the regulatory asset associated with the Four Corners mine reclamation costs for the Company's Texas jurisdiction was approximately$7.3 million. The Company currently continues to recover its mine reclamation costs in Texas under previous orders and decisions of the PUCT. If any future determinations made by the Company's regulators result in changes to how existing regulatory assets or previously incurred costs for Four Corners are recovered in rates, any such changes would be recognized only when it becomes probable future cash flows will change as a result of such regulatory actions.

Other Required Approvals. The Company has obtained other required approvals for tariffs and approvals required by the Public Utility Regulatory Act (the "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 millionin other service fees and a decrease in the Company's allowed return on equity to9.48%. 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.

Fuel and Purchased Power Costs. On January 8, 2014, the NMPRC approved the continuation of the Fuel and Purchased Power Cost Adjustment Clause (the "FPPCAC") without modification in NMPRC Case No. 13-00380-UT. Historically, fuel and purchased power costs were recovered through base rates and a FPPCAC that accounts for changes in the costs of fuel relative to the amount included in base rates. Effective July 1, 2016, with the implementation of the final order in Case No. 15-00127-UT, fuel and purchased power costs are no longer recovered through base rates 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. The Company recovers costs related to Palo Verde Unit 3 capacity and energy in New Mexico through the FPPCAC as purchased power using a proxy market price approved in Case No. 13-00380-UT. 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, 2016 that total approximately$114.6 million. At December 31, 2016, the Company had a net fuel over-recovery balance of$0.2 millionin New Mexico.

Montana Power Station Approvals.The Company received CCNs from the NMPRC to constructfourunits at MPS and the associated transmission lines. The Company also obtained all necessary air permits from the TCEQ and the EPA. A final order in NMPRC Case No. 13-00297-UT approving the CCN for MPS Units 3 and 4 was issued on June 11, 2014. MPS Units 1 and 2 and associated transmission lines and common facilities were completed and placed into service inMarch 2015. MPS Units 3 and 4 were completed and placed into service onMay 3, 2016andSeptember 15, 2016, respectively.

Four Corners.On June 15, 2016, in NMPRC Case No. 15-00109-UT, the NMPRC issued its final order approving the Company's sale and abandonment of its ownership interest in Four Corners to APS pursuant to a February 17, 2015 Purchase and Sale Agreement between the Company and APS.See Part II, Item 8,Financial Statements and Supplementary Data, Note Efor further details on the sale of Four Corners.

5 MW Holloman Air Force Base ("HAFB") Facility CCN.On October 7, 2015, in NMPRC Case No. 15-00185-UT, the NMPRC issued a final order approving a CCN for a5 MWsolar power generation facility located on HAFB in the Company's service territory in New Mexico. The Company and HAFB negotiated a special retail contract, which includes 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 second quarter of 2017.

Issuance of Long-Term Debt and Guarantee of Debt. On October 7, 2015 the Company received approval in NMPRC Case No. 15-00280-UT to issue up to$310.0 millionof new long-term debt and to guarantee the issuance of up to $65.0 millionof new debt by Rio Grande Resources Trust ("RGRT") to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. This approval supersedes prior approvals. Under this authorization, onMarch 24, 2016, the Company issued$150.0 millionaggregate principal amount of5.00%Senior Notes dueDecember 1, 2044. The net proceeds from the issuance of these senior notes, after deducting the underwriters' commission, were$158.1 million. These proceeds include accrued interest of$2.4 millionand a$7.1 millionpremium before expenses. These senior notes constitute an additional issuance of the Company's5.00%Senior Notes due2044, of which$150.0 millionwas previously issued onDecember 1, 2014, for a total principal amount outstanding of$300.0 million.

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

Federal Regulatory Matters

Four Corners.On June 26, 2015, APS filed an application requesting authorization from FERC to purchase100%of the Company’s ownership interest in Units 4 and 5 of Four Corners and the associated transmission interconnection facilities and rights. On December 22, 2015, FERC issued an order approving the proposed transaction. The sale of the Company's interest in Four Corners closed onJuly 6, 2016. See Part II, Item 8,Financial Statements and Supplementary Data, Note Efor further details on the sale of Four Corners.

Revolving Credit Facility; Issuance of Long-Term Debt and Guarantee of Debt. On October 19, 2015, the FERC issued an order in Docket No. ES15-66-000 approving the Company’s filing to issue short-term debt under the revolving credit facility ("RCF") up to$400.0 million outstanding at any time, to issue up to$310.0 million in long-term debt, and to guarantee the issuance of up to $65.0 millionof new long-term debt by RGRT to finance future nuclear fuel purchases. The authorization is effective from November 15, 2015 through November 15, 2017. This approval supersedes prior approvals.

Under this authorization, on March 24, 2016, the Company issued$150.0 millionaggregate principal amount of5.00%Senior Notes dueDecember 1, 2044. Additionally under this authorization, on January 9, 2017, the Company exercised its option to extend the maturity of the RCF by one year toJanuary 14, 2020and to increase the size of the facility by$50.0 millionto$350.0 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$50.0 million(up to a total of$400.0 million) upon the satisfaction of certain conditions, more fully set forth in the agreement, including obtaining commitments from lenders or third party financial institutions. Additionally, the Company agreed to reduce the letters of credit commitment to$50.0 millionfrom a total commitment, under the RCF, of$350.0 million.

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

United States Department of Energy ("DOE"). The DOE regulates the Company's exports of power to the Comisión Federal de Electricidad in Mexico pursuant to a license andtwopresidential permits issued by the DOE.

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

Sales for Resale

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.

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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2016

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets and Liabilities

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, 2016		December 31, 2015
Regulatory assets
Regulatory tax assets (a)	(b)	$	66,670	$	69,359
Loss on reacquired debt (c)	May 2035	15,780		16,632
Final coal reclamation (d)	(e)	9,581		9,520
Nuclear fuel postload daily financing charge	(e)	3,831		4,195
Unrecovered issuance costs due to reissuance of PCBs (c)	August 2042	794		827
Texas energy efficiency	(f)	—		25
Texas 2015 rate case costs	September 2018	2,670		1,882
Texas 2017 rate case costs	(g)	246		—
Texas relate back surcharge	(h)	6,455		—
New Mexico renewable energy credits and related costs (i)	June 2022	6,937		6,397
New Mexico 2010 FPPCAC audit	June 2019	398		434
New Mexico Palo Verde deferred depreciation	(b)	4,415		4,568
New Mexico 2015 rate case costs	June 2019	1,074		1,288
New Mexico 2017 rate case costs	(g)	10		—
Total regulatory assets		$	118,861	$	115,127
Regulatory liabilities
Regulatory tax liabilities (a)	(b)	$	10,648	$	17,266
Accumulated deferred investment tax credit (j)	(b)	3,328		4,011
Texas energy efficiency	(f)	1,288		—
New Mexico energy efficiency	(f)	2,159		2,238
Texas military base discount and recovery factor	(k)	184		788
New Mexico gain on sale of assets (l)	June 2019	828		—
Total regulatory liabilities		$	18,435	$	24,303

______________________________

(a) We do not earn a return on these items since the related accumulated deferred income tax assets and liabilities offset.

(b) The amortization periods for these assets and liabilities are based upon the life of the associated assets or liabilities.

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

(d) This item relates to coal reclamation costs associated with Four Corners. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.

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

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

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

(h) This item relates to the recovery of revenues through a separate surcharge beginning October 1, 2016 and ending September 30, 2017. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.

(i) This item relates to renewable energy credits and procurement plan costs, components approved for recovery in the New Mexico 2015 rate case.

(j) This item is excluded from rate base.

(k) 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.

(l) 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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Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant

12 Months Ended

Dec. 31, 2016

Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]

Schedule of Public Utility Property, Plant, and Equipment

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, 2016 (in thousands):

	Gross Plant		Accumulated Depreciation			Net Plant
Nuclear production	$	948,382	$	(320,000	)	$	628,382
Steam and other	926,419		(186,539		)	739,880
Total production	1,874,801		(506,539		)	1,368,262
Transmission	498,660		(259,488		)	239,172
Distribution	1,127,897		(365,601		)	762,296
General	205,866		(57,240		)	148,626
Intangible	84,342		(55,464		)	28,878
Total	$	3,791,566	$	(1,244,332	)	$	2,547,234

During 2016, depreciation decreased due to changes in rates approved in the PUCT Final Order and the NMPRC Final Order. The change, effective in January 2016 for Texas and July 2016 for New Mexico, reduced depreciation expense in 2016 by $10.9 million.

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). Effective July 2015, the Company changed the estimated useful life of certain large intangible software systems which decreased depreciation during 2015 by $1.8 million. 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):

2014	$	8,051
2015	6,482
2016	5,302
2017 (estimated)	5,148
2018 (estimated)	4,631
2019 (estimated)	4,242
2020 (estimated)	3,808
2021 (estimated)	3,227

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, 2016 and 2015 is as follows (in thousands):

	December 31, 2016						December 31, 2015
	Palo Verde			Other (a)			Palo Verde			Other (a)
Electric plant in service	$	948,382		$	67,621		$	917,483		$	229,627
Accumulated depreciation	(320,000		)	(44,377		)	(304,060		)	(181,886		)
Construction work in progress	50,598			1,895			48,938			9,528
Total	$	678,980		$	25,139		$	662,361		$	57,269

_______________

(a) 2015 other jointly-owned utility plant includes a 7% interest in Units 4 and 5 at Four Corners and certain other transmission facilities which the Company sold on July 6, 2016.

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 threePalo 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, 2016, the Company’s decommissioning trust fund had a balance of $255.7 million, which is above its minimum funding level. The Company monitors the status of its decommissioning funds and adjusts its deposits, if necessary.

Decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers retained by APS. In December 2013, the Palo Verde Participants approved the 2013 Palo Verde decommissioning study (the "2013 Study"). The 2013 Study estimated that the Company must fund approximately $380.7 million (stated in 2013 dollars) to cover its share of decommissioning costs which was an increase in decommissioning costs of $23.3 million (stated in 2013 dollars) from the 2010 Palo Verde decommissioning study. However, because the cash flows from the 2013 Study were less than the inflated amounts from the 2010 Study, the effect of this change lowered the ARO by $1.9 million which lowered annual expenses starting in January 2014. Although the 2013 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. A 2016 Palo Verde decommissioning study (the "2016 Study") is underway and is expected to be finalized in the second quarter of 2017 at which time the Company will record its effects. If the expected cash flows as identified in the 2016 Study exceed the expected cash flows identified in the 2013 Study (stated in 2016 dollars), the ARO will increase with a corresponding increase in the ARO asset. Under such circumstances, increases in Palo Verde accretion expense and depreciation expense will occur. While the Company attempts to seek amounts in rates to meet its decommissioning obligations, it is not able to conclude given the evidence available to it now that it is probable these costs will continue to be collected over the period until decommissioning begins in 2044. The Company is ultimately responsible for these costs and its future actions combined with future decisions from regulators will determine how successful the Company is in this effort.    

Spent Nuclear Fuel and Waste Disposal. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "NWPA"), the DOE is legally obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive waste generated by all domestic power reactors by 1998. The DOE's obligations are reflected in a contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (the "Standard Contract") with each nuclear power plant. The DOE failed to begin accepting spent nuclear fuel by 1998.On December 19, 2012, APS, acting on behalf of itself and the Palo Verde Participants, filed a second breach of contract lawsuit against the DOE. This lawsuit sought to recover damages incurred due to the DOE’s failure to accept Palo Verde’s spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011. On August 18, 2014, APS and the DOE entered into a settlement agreement stipulating to a dismissal of the lawsuit and payment of $57.4 millionby the DOE to the Palo Verde Participants for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. On October 8, 2014, the Company received approximately$9.1 million, representing its share of the award, of which $7.9 million was refunded to customers through the applicable fuel adjustment clauses. On October 31, 2014, APS, acting on behalf of itself and the Palo Verde Participants, submitted to the government an additional request for reimbursement of spent nuclear fuel storage costs for the period July 1, 2011 through June 30, 2014. The accepted claim amount was$42.0 million. On June 1, 2015, the Company received approximately$6.6 million, representing its share of the award, of which $5.8 million was credited to customers through the applicable fuel adjustment clauses in March 2015. After June 2015, APS will file annual claims for the period July 1 of the then-previous year to June 30 of the then-current year. On November 2, 2015, APS filed a $12.0 million claim for the period July 1, 2014 through June 30, 2015. In February 2016, the DOE notified APS of the approval of the claim.The Company's share of this claim is approximately$1.9 million, of which $1.6 million was credited to customers through the applicable fuel adjustment clauses in March 2016. On October 31, 2016 APS filed an $11.3 million claim for the period July 1, 2015 through June 30, 2016. The Company's share of this claim is approximately$1.8 million. On February 1, 2017, the DOE notified APS of the approval of the claim. Any reimbursement is anticipated to be received in the second quarter of 2017, and the majority of the award received by the Company will be credited to customers through 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, and the proceeding has not been conclusively decided by the NRC or the courts.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 $12.9 million for the current policy period.

Four Corners

On February 17, 2015, the Company and APS entered intothePurchase and Sale Agreementproviding for the sale of the Company’s interests in Four Corners to APS. Four Corners continued to provide energy to serve the Company's native load up to the closing date of the sale onJuly 6, 2016. Also on July 6, 2016, prior to the closing of the transaction, the Company and APS entered into an amendment to the Purchase and Sale Agreement pursuant to which APS assigned its right, title and interest in the Purchase and Sale Agreement to its affiliate 4C Acquisition, LLC ("APS's affiliate"), and Pinnacle West Capital Corporation, the parent company of APS and APS's affiliate ("Pinnacle West"), guaranteed APS's affiliate's obligations under the Purchase and Sale Agreement. The sales price was$32.0 million, which was based on the net book value as defined in the Purchase and Sale Agreement. The sales price was adjusted downward by$7.0 millionand$19.5 million, respectively, to reflect the assumption by APS's affiliate of the Company's obligation to pay for future plant decommissioning and mine reclamation expenses. The sales price was also adjusted downward by approximately$1.3 millionfor estimated closing adjustments and other assets and liabilities assumed by APS's affiliate. At the closing, the Company received approximately$4.2 millionin cash, subject to post-closing adjustments. No significant gain or loss was recorded after the closing date. 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.

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Accounting for Asset Retirement Obligations

12 Months Ended

Dec. 31, 2016

Accounting for Asset Retirement Obligations

Asset Retirement Obligation Disclosure

Accounting for Asset Retirement Obligation

The Company complies with the FASB guidance for ARO. 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 2013 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, spent fuel 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, 2016 is $255.7 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. In December 2013, the Company implemented the 2013 Palo Verde decommissioning study, and as a result, revised its ARO related to Palo Verde to decrease its estimated cash flows from the 2010 Study to the 2013 Study (see Part II, Item 8, Financial Statements and Supplementary Data, Note E). The assumptions used to calculate 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	3.60	%	6.20	%

An analysis of the activity of the Company’s total ARO liability from January 1, 2014 through December 31, 2016, including the effects of each year’s estimate revisions, is presented below. In 2016, the settled liabilities reflect the sale of the Company's interest in Four Corners including the related ARO. In 2014, the estimate revision includes an adjustment to Four Corners due to the early recognition of the obligation resulting from the Purchase and Sale Agreement with APS.

	2016			2015		2014
ARO liability at beginning of year	$	81,621		$	74,577	$	65,214
Liabilities incurred	—			189		—
Liabilities settled	(6,993		)	—		—
Revisions to estimate	—			—		3,561
Accretion expense	7,172			6,855		5,802
ARO liability at end of year	$	81,800		$	81,621	$	74,577

The Company has transmission and distribution lines which are operated under various property easement agreements. If the easements were to be released, 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 easements 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.

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Common Stock (Notes)

12 Months Ended

Dec. 31, 2016

Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

Shareholders' Equity and Share-based Payments , Including Earnings Per Share Information

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. 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 are fully vested and are expensed at fair value on the date of grant. Previously directors could elect to receive retainers and meeting fees in cash, restricted stock, or a combination of cash and stock. On May 29, 2014, the Board of Directors voted to revise the terms of the restricted stock awards granted to directors in lieu of cash for retainers and meeting fees. Stock elections by directors in lieu of cash for retainer and meeting fees are now fully vested and are expensed at fair value on the date of grant. The modification to 13,863 outstanding restricted stock awards granted to directors resulted in forfeiture of those awards and the granting of new awards which were fully vested and expensed at $37.81 per share, the fair value on the date of grant. Effective fiscal year ended December 31, 2015, other stock-based awards 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 2016, 2015 and 2014 is presented below (in thousands):

	2016		2015		2014
Expense (a)	$	2,594	$	2,755	$	3,471
Deferred tax benefit	908		964		1,215
Current tax benefit recognized	183		43		39

_____________________

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

The aggregate intrinsic value and fair value at grant date of restricted stock and other stock-based awards which vested in 2016, 2015 and 2014 is presented below (in thousands):

	2016		2015		2014
Aggregated intrinsic value	$	2,515	$	3,451	$	3,441
Fair value at grant date	1,993		3,327		3,330

The unvested restricted stock transactions for 2016 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, 2015	91,210		$	36.61
Stock awards	74,181		40.95
Vested	(55,503	)	35.91
Forfeitures	(495	)	36.88
Restricted shares outstanding at December 31, 2016	109,393		39.90		$	1,767	$	5,087

_______________________

(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.

The weighted average fair value per share at grant date for restricted stock and other stock-base awards granted during 2016, 2015 and 2014 were:

	2016		2015		2014
Weighted average fair value per share	$	40.95	$	37.17	$	36.95

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.

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 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	—
February 18, 2014	0	%	0	954		2011-2013	—

In 2017, 2018 and 2019, subject to meeting certain performance criteria, additional performance shares could be awarded. 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. Excluding the 2014 award, the maximum number of shares that can be issued under the plan are 206,898 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 plan’s 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, 2015 (a)	130,136		$	32.72
Performance share awards	60,835		38.11
Performance shares expired	(24,527	)	34.69
Performance shares outstanding at December 31, 2016 (a)	166,444		34.40		$	2,189	$	7,740

_______________________

(a) On December 15, 2015, the Company issued a stock based retention grant to the Chief Executive Officer (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.

(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 2016, 2015 and 2014 is presented below:

	2016		2015		2014
Weighted average per share grant date fair value per share of performance shares awarded	$	38.11	$	35.72	$	26.36
Compensation expense (in thousands) (a) (b)	1,655		1,042		1,181
Deferred tax benefit related to compensation expense (in thousands) (b)	579		365		413

_____________________

(a) Includes adjustments for estimated forfeitures.

(b) Includes CEO retention grant.

Repurchase Program

No shares of the Company's common stock were repurchased during the twelve months ended December 31, 2016. Detail regarding the Company's stock repurchase program are presented below:

	Since 1999 (a)		Authorized Shares
Shares repurchased (b)	25,406,184
Cost, including commission (in thousands)	$	423,647
Total remaining shares available for repurchase at December 31, 2016			393,816

______________________

(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 188,005 shares out of treasury stock during 2016.

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 30, 2016, the Company paid $12.6 million in quarterly cash dividends to shareholders. The Company paid a total of $49.6 million, $47.1 million and $44.6 million in cash dividends during the twelve months ended December 31, 2016, 2015 and 2014, respectively. On January 26, 2017, the Board of Directors declared a quarterly cash dividend of $0.31 per share payable on March 31, 2017 to shareholders of record as of the close of business on March 17, 2017.

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,
	2016			2015			2014
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	40,350,688			40,274,986			40,190,991
Dilutive effect of unvested performance awards	57,345			33,576			20,726
Diluted number of common shares outstanding	40,408,033			40,308,562			40,211,717
Basic net income per common share:
Net income	$	96,768		$	81,918		$	91,428
Income allocated to participating restricted stock	(321		)	(243		)	(301		)
Net income available to common shareholders	$	96,447		$	81,675		$	91,127
Diluted net income per common share:
Net income	$	96,768		$	81,918		$	91,428
Income reallocated to participating restricted stock	(321		)	(243		)	(301		)
Net income available to common shareholders	$	96,447		$	81,675		$	91,127
Basic net income per common share:
Distributed earnings	$	1.225		$	1.165		$	1.105
Undistributed earnings	1.165			0.865			1.165
Basic net income per common share	$	2.390		$	2.030		$	2.270
Diluted net income per common share:
Distributed earnings	$	1.225		$	1.165		$	1.105
Undistributed earnings	1.165			0.865			1.165
Diluted net income per common share	$	2.390		$	2.030		$	2.270

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,
	2016	2015	2014
Restricted stock awards	53,703	56,375	60,455
Performance shares (a)	47,246	66,804	96,208

_____________________

(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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Accumulated Other Comprehensive Income (Notes)

12 Months Ended

Dec. 31, 2016

Accumulated Other Comprehensive Income (Loss) [Line Items]

Comprehensive Income (Loss) Note

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, 2013		$	(21,330	)	$	36,240		$	(12,298	)	$	2,612
	Other comprehensive income (loss) before reclassifications	(12,628		)	8,694			—			(3,934		)
	Amounts reclassified from accumulated other comprehensive income (loss)	(926		)	(5,977		)	224			(6,679		)
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	)

Amounts reclassified from Accumulated Other Comprehensive Income (Loss) for the twelve months ended December 31, 2016, 2015 and 2014 are as follows (in thousands):

Details about Accumulated Other Comprehensive Income (Loss) Components		2016			2015			2014			Affected Line Item in the Statements of Operations
Amortization of pension and post-retirement benefit costs:
	Prior service benefit	$	7,407		$	6,574		$	7,659		(a)
	Net loss	(4,965		)	(8,622		)	(6,182		)	(a)
		2,442			(2,048		)	1,477			(a)
	Income tax effect	(1,020		)	810			(551		)	Income tax expense
		1,422			(1,238		)	926			Net income
Marketable securities:
	Net realized gain on sale of securities	7,640			11,114			7,350			Investment and interest income, net
		7,640			11,114			7,350			Income before income taxes
	Income tax effect	(1,434		)	(2,177		)	(1,373		)	Income tax expense
		6,206			8,937			5,977			Net income
Loss on cash flow hedge:
	Amortization of loss	(498		)	(467		)	(438		)	Interest on long-term debt and revolving credit facility
		(498		)	(467		)	(438		)	Income before income taxes
	Income tax effect	339			203			214			Income tax expense
		(159		)	(264		)	(224		)	Net income
	Total reclassifications	$	7,469		$	7,435		$	6,679

(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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Long-Term Debt and Financing Obligations (Notes)

12 Months Ended

Dec. 31, 2016

Long-Term Debt and Financing Obligations [Abstract]

Long-term Debt

Long-Term Debt and Financing Obligations

Outstanding long-term debt and financing obligations are as follows:

	December 31,
	2016			2015 (1)
	(In thousands)
Long-Term Debt:
Pollution Control Bonds (2):
7.25% 2009 Series A refunding bonds, due 2040 (7.46% effective interest rate)	$	62,619		$	62,582
4.50% 2012 Series A refunding bonds, due 2042 (4.63% effective interest rate)	58,471			58,441
7.25% 2009 Series B refunding bonds, due 2040 (7.49% effective interest rate)	36,492			36,465
1.875% 2012 Series A refunding bonds, due 2032 (2.35% effective interest rate)	33,193			33,011
Total Pollution Control Bonds	190,775			190,499
Senior Notes (3):
6.00% Senior Notes, net of discount, due 2035 (7.12% effective interest rate)	393,861			393,693
7.50% Senior Notes, net of discount, due 2038 (7.67% effective interest rate)	147,331			147,282
3.30% Senior Notes, net of discount, due 2022 (3.43% effective interest rate)	148,939			148,783
5.00% Senior Notes, net of discount, due 2044 (4.93% effective interest rate)	302,955			147,717
Total Senior Notes	993,086			837,475
RGRT Senior Notes (4):
4.47% Senior Notes, Series B, due 2017 (4.62% effective interest rate)	49,950			49,883
5.04% Senior Notes, Series C, due 2020 (5.16% effective interest rate)	44,845			44,803
Total RGRT Senior Notes	94,795			94,686
Total long-term debt	1,278,656			1,122,660
Financing Obligations:
Revolving Credit Facility ($81,574 due in 2017) (5)	81,574			141,738
Total long-term debt and financing obligations	1,360,230			1,264,398
Current Portion (amount due within one year):
Current maturities of long term debt	(83,143		)	—
Short-term borrowings under the revolving credit facility	(81,574		)	(141,738		)
	$	1,195,513		$	1,122,660

_____________________

(1) The Company implemented ASU 2015-03, Interest - Imputation of Interest, which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The impact of ASU 2015-03 on the Company's Balance Sheet was to reclassify $11.6 million of other deferred charges to long-term debt, net of current portion at December 31, 2015.

(2) Pollution Control Bonds ("PCBs")

The Company has four series of tax exempt unsecured PCBs in aggregate principal amount of $193.1 million. The 1.875% 2012 Series A (El Paso Electric Company Four Corners Project) Pollution Control Refunding Revenue Bonds with an aggregate principal amount of $33.3 million are subject to mandatory tender for purchase in September 2017 at which time the Company will either repay or remarket these bonds.

(3) 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.

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.

(4) 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 (the "Notes"). In August 2015, $15.0 million of these Notes matured and were paid with borrowings from the RCF. In August 2017, $50.0 million of these Senior Notes will mature. The Company will either repay or refinance this $50.0 million of Notes upon maturity. The Company guarantees the payment of principal and interest on the 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 Notes on February 15, and August 15 of each year until maturity. RGRT may redeem the 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 2016.

The sale of the 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 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 Notes and amounts borrowed from the RCF.

(5) 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 2016. In August 2015, $15.0 million aggregate principal amount of Series A 3.67% Senior Notes of RGRT matured and were paid utilizing borrowings under the RCF. As of December 31, 2016, the total amount borrowed by RGRT was $37.6 million for nuclear fuel under the RCF. As of December 31, 2016, $44.0 million of borrowings were outstanding under this facility for working capital and general corporate purposes. The weighted average interest rate on the RCF was 2.0% as of December 31, 2016.

As of December 31, 2016, the principal amount of scheduled maturities for the next five years of long-term debt are as follows (in thousands):

2017	$	83,300
2018	—
2019	—
2020	45,000
2021	—

The $37.6 million of borrowings outstanding on the RCF for nuclear fuel financing purposes is anticipated to be paid in 2017.

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Income Taxes

12 Months Ended

Dec. 31, 2016

Income Taxes [Abstract]

Income Tax Disclosure

Income Taxes

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2016 and 2015 are presented below (in thousands):

	December 31,
	2016			2015
Deferred tax assets:
Benefit of tax loss carryforwards	$	60,749		$	35,153
Alternative minimum tax credit carryforward	16,620			16,620
Pensions and benefits	57,756			61,673
Asset retirement obligation	26,929			28,042
Deferred fuel	—			1,488
Other	(200		)	15,421
Total gross deferred tax assets	161,854			158,397
Deferred tax liabilities:
Plant, principally due to depreciation and basis differences	(668,303		)	(608,738		)
Decommissioning	(43,463		)	(41,100		)
Deferred fuel	(3,962		)	—
Other	(1,192		)	(3,796		)
Total gross deferred tax liabilities	(716,920		)	(653,634		)
Net accumulated deferred income taxes	$	(555,066	)	$	(495,237	)

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

The Company recognized income tax expense for 2016, 2015 and 2014 as follows (in thousands):

	Years Ended December 31,
	2016			2015			2014
Income tax expense:
Federal:
Current	$	2,642		$	2,319		$	(1,250	)
Deferred	47,909			32,819			38,810
Total federal income tax	50,551			35,138			37,560
State:
Current	766			1,730			3,209
Deferred	3,285			(1,650		)	641
Total state income tax	4,051			80			3,850
Generation (amortization) of accumulated investment tax credits	(684		)	(323		)	(322		)
Total income tax expense	$	53,918		$	34,895		$	41,088

As of December 31, 2016, the Company had $16.6 million of AMT credit carryforwards that have an unlimited life. As of December 31, 2016, the Company had $59.3 million of federal and $2.2 million of state tax loss carryforwards. If unused, both the federal and state tax loss carryforwards have lives of 20 years and 5 years respectively. As of December 31, 2016, the Company had $0.2 million of unrecognized tax benefits related to stock compensation which cannot be recognized until federal tax loss carryforwards are fully utilized.

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):

	Years Ended December 31,
	2016			2015			2014
Federal income tax expense computed on income at statutory rate	$	52,740		$	40,885		$	46,381
Difference due to:
State taxes, net of federal benefit	2,633			52			1,902
AEFUDC	(475		)	(2,345		)	(3,757		)
Permanent tax differences	(2,369		)	(2,898		)	(2,921		)
Other	1,389			(799		)	(517		)
Total income tax expense	$	53,918		$	34,895		$	41,088
Effective income tax rate	35.8		%	29.9		%	31.0		%

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

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 final orders from the PUCT and the NMPRC in its 2015 rate cases, effective January 1, 2016. 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 $5.1 million for the year ended December 31, 2016.

In November 2015, the FASB issued new guidance (ASU 2015-17, Balance Sheet Classification of Deferred Taxes) to simplify the presentation of deferred income taxes. ASU 2015-17 requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. ASU 2015-17 can be applied prospectively or retrospectively and is effective for financial statements issued for annual periods beginning after December 15, 2016 and interim periods within those annual periods and early adoption is permitted. The Company elected to implement ASU 2015-17 on a retrospective basis for financial statements issued beginning March 31, 2016. The implementation of ASU 2015-17 did not have a material impact on the Company's results of operations. The impact of ASU 2015-17 on the Company's Balance Sheet was to reclassify $21.6 million of current deferred tax assets to long-term deferred tax liabilities at December 31, 2015.

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 $0.4 million (net of an increase of $0.5 million), an unrecognized tax position of $0.8 million, and $2.1 million, in 2016, 2015, and 2014 respectively, related to transmission and distribution costs and other amounts deducted in current and prior year Texas franchise tax returns. The Company recorded a decrease of $0.3 million in 2016 and a decrease of $1.3 million (net of an increase of $0.4 million) in 2014 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, 2016, 2015 and 2014 amounts of unrecognized tax benefits are as follows (in thousands):

	2016			2015		2014
Balance at January 1	$	6,000		$	5,200	$	7,200
Additions for tax positions related to the current year	400			500		300
Reductions for tax positions related to the current year	—			—		—
Additions for tax positions of prior years	100			300		2,200
Reductions for tax positions of prior years	(1,200		)	—		(4,500		)
Balance at December 31	$	5,300		$	6,000	$	5,200

If recognized, $2.6 million of the unrecognized tax position at December 31, 2016, would reduce the effective tax rate. The Company recognized an income tax benefit for the decrease in unrecognized tax positions of $0.7 million for the year ended December 31, 2016.

The Company recognizes in tax expense interest and penalties related to tax benefits that have not been recognized. For the years ended December 31, 2016, 2015, and 2014 the Company recognized interest expense of $0.1 million, $0.2 million, and $0.1 million, respectively. The Company had approximately $0.8 million and $0.7 million accrued for the payment of interest and penalties at December 31, 2016 and 2015, respectively.

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Commitments, Contingencies and Uncertainties

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments, Contingencies And Uncertainties

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 June 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 April 2034	May 2014
Power Purchase Agreement	Newman Solar LLC		10	MW	December 2014 through November 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.

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.

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 millionfor environmental mitigation projects. At December 31, 2016, the Company has accrued its remaining unpaid share of approximately$0.2 millionrelated to this matter.

New Mexico Tax Matter Related to Coal Supplied to Four Corners

On May 23, 2013, the New Mexico Taxation and Revenue Department ("NMTRD") issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30.0 million related to coal supplied under the coal supply agreement for Four Corners (the "Assessment"). The Company's share of the Assessment is approximately $1.5 million. On behalf of the Four Corners participants, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with respect to that partial payment in August 2013. The NMTRD denied the refund claim. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed complaints with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial. On June 30, 2015, the court ruled that the Assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statute. The NMTRD filed a Notice of Appeal on August 31, 2015 with respect to the decision. Thereafter, APS and the coal supplier entered into a final settlement agreement with the NMTRD with respect to the Assessment. Pursuant to the final settlement agreement, the NMTRD agreed to release the Assessment, dismiss its filed appeal, and release its rights to any other surtax claims with respect to the coal supply agreement. APS and the other Four Corners participants agreed to forgo refund rights with respect to all the contested amounts previously paid under the applicable tax statute, in addition to a $1.0 million settlement payment. The Company paid its share of this settlement, approximately $47,000, in April 2016.

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 4 years. The Company has transmission and distribution lines which are operated under various property easement agreements. The majority of these easements include renewal options which the Company routinely exercises. These lease agreements 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 $1.7 million, $1.9 million, and $1.8 million for 2016, 2015 and 2014, respectively. As of December 31, 2016, the Company’s minimum future rental payments for the next five years are as follows (in thousands):

2017	$	808
2018	662
2019	666
2020	664
2021	562

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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Litigation

12 Months Ended

Dec. 31, 2016

Litigation [Abstract]

Legal Matters and Contingencies

Litigation

The Company is involved in various legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. The Company regularly analyzes current information and, as necessary, makes provisions in its financial statements for probable liabilities for the eventual disposition of these matters. While the outcome of these matters cannot be predicted with certainty, based upon a review of the matters and applicable insurance coverage, the Company believes that none of these matters will have a material adverse effect on the financial position, results of operations or cash flows of the Company. The Company expenses legal costs, including expenses related to loss contingencies, as they are incurred.

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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Employee Benefits

12 Months Ended

Dec. 31, 2016

Compensation and Retirement Disclosure [Abstract]

Pension and Other Postretirement Benefits Disclosure

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 collected from customers in the Company's Texas and New Mexico jurisdictions and the annual 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 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.

During the quarter ended March 31, 2014, the Company implemented certain amendments to the Retirement Plan and Excess Benefit Plan. In the first quarter of 2014, the Company offered a cash balance pension plan as an alternative to its current final average pay pension plan for employees hired prior to January 1, 2014. The cash balance pension plan also included an enhanced employer matching contribution to the employee’s respective 401(k) Defined Contribution Plan (discussed below). For employees that elected the new cash balance feature of the plans, the pension benefit earned under the existing final average pay feature of the plans was frozen as of March 31, 2014. Employees hired after January 1, 2014 were automatically enrolled in the cash balance pension plan. The amendments to the plans were effective April 1, 2014. As a result of these actions, the Company remeasured the assets and liabilities of the plans, based on actuarially determined estimates, using the close of the alternative choice election period of February 28, 2014, as the remeasurement date.

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 plan covers employees beginning on their employment commencement date or re-employment commencement date in any plan year in which the employee completes at least a minimum number of hours of service. Retirement benefits under the cash balance pension plan are based on the employee’s cash balance account, consisting of pay credits and interest credits.

The Company complies with the FASB guidance on disclosure for pension and other post-retirement plans that requires disclosure of investment policies and strategies, categories of investment and fair value measurements of plan assets, and significant concentrations of risk.

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

	December 31,
	2016						2015
	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	$	325,706		$	26,958		$	341,133		$	28,397
Service cost	7,705			296			8,530			262
Interest cost	12,161			878			13,477			1,018
Actuarial (gain) loss	7,988			1,267			(19,290		)	(810		)
Benefits paid	(15,792		)	(1,937		)	(18,144		)	(1,909		)
Benefit obligation at end of year	337,768			27,462			325,706			26,958
Change in plan assets:
Fair value of plan assets at end of prior year	260,035			—			272,939			—
Actual return (loss) on plan assets	18,223			—			(3,760		)	—
Employer contribution	7,300			1,937			9,000			1,909
Benefits paid	(15,792		)	(1,937		)	(18,144		)	(1,909		)
Fair value of plan assets at end of year	269,766			—			260,035			—
Funded status at end of year	$	(68,002	)	$	(27,462	)	$	(65,671	)	$	(26,958	)

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

	December 31,
	2016						2015
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Current liabilities	$	—		$	(2,696	)	$	—		$	(2,102	)
Noncurrent liabilities	(68,002		)	(24,766		)	(65,671		)	(24,856		)
Total	$	(68,002	)	$	(27,462	)	$	(65,671	)	$	(26,958	)

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

	December 31,
	2016						2015
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Projected benefit obligation	$	(337,768	)	$	(27,462	)	$	(325,706	)	$	(26,958	)
Accumulated benefit obligation	(314,071		)	(25,550		)	(302,446		)	(25,785		)
Fair value of plan assets	269,766			—			260,035			—

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

	Years Ended December 31,
	2016						2015
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Net loss	$	121,052		$	10,073		$	118,963		$	9,592
Prior service benefit	(23,877		)	(185		)	(27,344		)	(224		)
Total	$	97,175		$	9,888		$	91,619		$	9,368

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

	December 31,
	2016						2015
			Non-Qualified						Non-Qualified
	Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan		Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan
Discount rate	4.29	%	3.76	%	4.34	%	4.57	%	3.99	%	4.59	%
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 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, 2016 retirement plans' projected benefit obligation by 11.5%. A 1% decrease in the discount rate would increase the December 31, 2016 retirement plans' projected benefit obligation by 14.1%.

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

	Years Ended December 31,
	2016						2015						2014
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Service cost	$	7,705		$	296		$	8,530		$	262		$	8,284		$	303
Interest cost	12,161			878			13,477			1,018			14,001			1,041
Expected return on plan assets	(18,879		)	—			(19,795		)	—			(18,699		)	—
Amortization of:
Net loss	6,554			785			9,710			937			8,178			675
Prior service benefit	(3,467		)	(39		)	(3,467		)	(39		)	(2,889		)	(17		)
Net periodic benefit cost	$	4,074		$	1,920		$	8,455		$	2,178		$	8,875		$	2,002

In 2016,the Companychanged the method used to estimate the service and interest components of net periodic benefit cost forpensionbenefits. This change, compared to the previous method, resulted in a decrease in the service cost and interest cost components in 2016, and is expected to result in a decrease in the service cost and interest cost components in future periods. Historically,the Companyestimated 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 Companyelected 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 believesthe 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 Companyaccounted for this change as a change in accounting estimate and accordingly, accounted for this prospectively. The change in estimate decreased the service and interest components of net periodic benefit costin 2016 by approximately$2.9 million.

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

	Years Ended December 31,
	2016						2015						2014
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Net (gain) loss	$	8,644		$	1,266		$	4,266		$	(811	)	$	47,324		$	3,508
Prior service benefit	—			—			—			—			(33,700		)	(500		)
Amortization of:
Net loss	(6,554		)	(785		)	(9,710		)	(937		)	(8,178		)	(675		)
Prior service benefit	3,467			39			3,467			39			2,889			17
Total recognized in other comprehensive income	$	5,557		$	520		$	(1,977	)	$	(1,709	)	$	8,335		$	2,350

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

	Years Ended December 31,
	2016				2015				2014
	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	$	9,631	$	2,440	$	6,478	$	469	$	17,210	$	4,352

The following are amounts in accumulated other comprehensive income that are expected to be recognized as components of net periodic benefit cost during 2017 (in thousands):

	Retirement Income Plan			Non-Qualified Retirement Plans
Net loss	$	7,530		$	825
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 endedDecember 31:

	2016						2015						2014 (a)
			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	4.57	%	3.99	%	4.63	%	4.0	%	3.4	%	4.1	%	4.9	%	3.9	%	4.9	%
Service cost	4.83	%	N/A		4.87	%	4.0	%	N/A		4.1	%	4.9	%	N/A		4.9	%
Interest cost	3.86	%	3.04	%	3.9	%	4.0	%	3.4	%	4.1	%	4.9	%	3.9	%	4.9	%
Expected long-term return on plan assets	7.0	%	N/A		N/A		7.5	%	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	%	4.75	%	N/A		4.75	%

 _____________________

(a) The Retirement Plan and the Excess Benefit Plan were remeasured on February 28, 2014 due to the above mentioned plan amendment. The discount rate used to remeasure the benefit obligation was 4.6% for the Retirement Plan and 4.5% for the Excess Benefit Plan, compared to 4.9% for both plans as of January 1, 2014. All other assumptions remained consistent with assumptions used at January 1, 2014.

The Company’s overall expected long-term rate of return on assets is 7.0% effective January 1, 2016 and January 1, 2017, 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, 2016
Equity securities	50	%
Fixed income	40	%
Alternative investments	10	%
Total	100	%

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. 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.

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 NAV provided by the administrator of the fund. The NAV price is quoted on a restrictive market although the underlying investments are traded on active markets. During the third quarter of 2016, the Company concluded that the NAV used for determining the fair value of the investments in the Common Collective Trusts have readily determinable fair values. Accordingly, such fund values have been re-categorized from Level 2 to Level 1 hierarchy.

Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. 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.

The fair value of the Company’s Retirement Plan assets at December 31, 2016 and 2015, 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, 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	$	—	$	—

Description of Securities	Fair Value as of December 31, 2015		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Cash and Cash Equivalents	$	1,266	$	1,266	$	—	$	—
Common Collective Trusts (a)
Equity funds	144,279		144,279		—		—
Fixed income funds	103,877		103,877		—		—
Real Estate Funds	2,025		2,025		—		—
Total Common Collective Trusts	250,181		250,181		—		—
Limited Partnership Interest in Real Estate (b)(c)	8,588
Total Plan Investments	$	260,035	$	251,447	$	—	$	—

 _____________________

(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 guidance. 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. ASU 2015-07 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years.

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, 2014	$	8,748
Unrealized loss in fair value	(160		)
Balances at December 31, 2015	8,588
Sale of land	(775		)
Unrealized loss in fair value	(822		)
Balances at December 31, 2016	$	6,991

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, 2016 and 2015. 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, 2016 and 2015.

The Company adheres 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 seeks 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 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 Company expects to contribute at least $10.0 million to its retirement plans in 2017.

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
2017	$	16,113	$	2,698
2018	19,080		2,060
2019	18,771		2,025
2020	18,923		1,957
2021	19,755		1,907
2022-2026	107,916		8,949

401(k) Defined Contribution Plans

The Company sponsors 401(k) defined contribution plans covering substantially all employees. Annual matching contributions made to the savings plans for the years 2016, 2015 and 2014 were $4.1 million, $3.9 million, and $3.0 million, respectively. Historically, the Company had provided a 50 percent matching contribution up to 6 percent of the employee’s compensation subject to certain other limits and exclusions. Effective April 1, 2014, for employees who enrolled in the cash balance pension plan (discussed above), the Company provided a 100 percent matching contribution up to 6 percent of the employee's compensation subject to certain other limits and exclusions.

Other Post-retirement Benefits

The Company provides certain health care benefits for retired employees and their eligible dependents and life insurance benefits for retired employees only. Substantially all of the Company’s employees may become eligible for those benefits if they retire while working for the Company. Contributions from the Company are based on various factors such as the Plan's funded status, the IRS tax deductible limit, state and federal regulatory requirements, amounts collected from customers in the Company's Texas and New Mexico jurisdictions and the annual cost of the Plan, as actuarially calculated. The assets of the plan are primarily invested in institutional funds which hold equity securities, debt securities, and cash equivalents and are managed by a professional investment manager appointed by the Company.

The following table contains a reconciliation of the change in the benefit obligation, the fair value of plan assets, and the funded status of the plan (in thousands):

	December 31,
	2016			2015
Change in benefit obligation:
Benefit obligation at end of prior year	$	92,643		$	100,700
Service cost	2,769			3,454
Interest cost	3,167			4,035
Actuarial loss (gain)	10,751			(11,423		)
Amendment (a) (b)	(32,697		)	(824		)
Benefits paid	(4,428		)	(4,544		)
Retiree contributions	1,310			1,245
Benefit obligation at end of year	73,515			92,643
Change in plan assets:
Fair value of plan assets at end of prior year	38,090			41,358
Actual return (loss) on plan assets	2,443			(469		)
Employer contribution	1,700			500
Benefits paid	(4,428		)	(4,544		)
Retiree contributions	1,310			1,245
Fair value of plan assets at end of year	39,115			38,090
Funded status at end of year	$	(34,400	)	$	(54,553	)

_____________________

(a) During October 2016, the Company approved and communicated a plan amendment that resulted in a remeasurement of the Company's 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 were covered by a fully insured Medicare advantage plan.

(b) Amendment relates to modification of the Company's Other Post-retirement Benefit Plan which increased mail order co-payments for post age 65. The amendment was approved in 2015 and became effective January 1, 2016.

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

	December 31,
	2016			2015
Current liabilities	$	—		$	—
Noncurrent liabilities	(34,400		)	(54,553		)
Total	$	(34,400	)	$	(54,553	)

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

	December 31,
	2016			2015
Net gain	$	(26,285	)	$	(38,802	)
Prior service benefit	(41,009		)	(12,213		)
Total	$	(67,294	)	$	(51,015	)

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

	December 31,
	2016		2015
Discount rate at end of year	4.36	%	4.59	%
Health care cost trend rates:
Initial
Pre-65 medical	6.50	%	7.00	%
Post-65 medical	4.50	%	7.00	%
Pre-65 drug	7.50	%	7.00	%
Post-65 drug	10.50	%	7.00	%
Ultimate	4.50	%	4.50	%
Year ultimate reached (a)	2026		2026

_____________________ (a) Pre-65 medical reaches the ultimate trend rate in 2025. Additionally, the Post-65 medical trend is assumed to be 4.50% for all years into the future.

The discount rate is reviewed 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, 2016 accumulated post-retirement benefit obligation by 13.1%. A 1% decrease in the discount rate would increase the December 31, 2016 accumulated post-retirement benefit obligation by 16.7%.

Net periodic benefit cost is made up of the components listed below (in thousands):

	Years Ended December 31,
	2016			2015			2014
Service cost	$	2,769		$	3,454		$	2,845
Interest cost	3,167			4,035			4,463
Expected return on plan assets	(1,835		)	(2,070		)	(2,116		)
Amortization of:
Prior service benefit	(3,901		)	(3,068		)	(4,753		)
Net gain	(2,374		)	(2,025		)	(2,671		)
Net periodic benefit cost	$	(2,174	)	$	326		$	(2,232	)

In 2016,the Companychanged the method used to estimate the service and interest components of net periodic benefit cost forother post-retirementbenefits. This change, compared to the previous method, resulted in a decrease in the service cost and interest cost components in 2016, and is expected to result in a decrease in the service cost and interest cost components in future periods. Historically,the Companyestimated 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 Companyelected 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 believesthe 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 Companyaccounted for this change as a change in accounting estimate and accordingly, accounted for this prospectively. The change in estimate decreased the service and interest components of net periodic benefit costin 2016 by approximately$0.8 million.

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

	Years Ended December 31,
	2016			2015			2014
Net (gain) loss	$	10,143		$	(8,884	)	$	3,496
Prior service benefit	(32,697		)	(824		)	—
Amortization of:
Prior service benefit	3,901			3,068			4,753
Net gain	2,374			2,025			2,671
Total recognized in other comprehensive income	$	(16,279	)	$	(4,615	)	$	10,920

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

	Years Ended December 31,
	2016			2015			2014
Total recognized in net periodic benefit cost and other comprehensive income	$	(18,453	)	$	(4,289	)	$	8,688

The amount in accumulated other comprehensive income that is expected to be recognized as a component of net periodic benefit cost during 2017 is a prior service benefit of $6.2 million and a net gain of $1.6 million.

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

	2016 (a)				2015		2014
Discount rate:	January 1 - September 30		October 1 - December 31
Benefit obligation	4.59	%	3.75	%	4.1	%	4.9	%
Service cost	4.91	%	4.03	%	4.1	%	4.9	%
Interest cost	3.86	%	3.15	%	4.1	%	4.9	%
Expected long-term return on plan assets	4.875%				5.2	%	5.2	%
Health care cost trend rates:
Initial	7.00%				7.25	%	7.5	%
Ultimate	4.5%				4.5	%	4.5	%
Year ultimate reached	2026				2026		2026

_____________________

(a) The actuarial assumptions are evaluated by the Company at each measurement date. The Other Post-retirement Benefits Plan was remeasured at October 1, 2016 due to a plan amendment.

For measurement purposes, a 7.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2016. The rate was assumed to decrease gradually to 4.5% for 2026 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. The effect of a 1% change in these assumed health care cost trend rates would increase or decrease the December 31, 2016 benefit obligation by $11.2 million or $9.0 million, respectively. In addition, a 1% change in said rate would increase or decrease the aggregate 2016 service and interest cost components of the net periodic benefit cost by $1.3 million or $1.0 million, respectively.

The Company’s overall expected long-term rate of return on assets, on an after-tax basis, is 4.875% effective January 1, 2016 and January 1, 2017. The expected long-term rate of return is based on the after-tax weighted average of the expected returns on investments based upon the target asset allocation. The Company’s target allocations for the plan’s assets are presented below:

	December 31, 2016
Equity securities	65	%
Fixed income	30	%
Alternative investments	5	%
Total	100	%

The Other Post-retirement Benefit Plan invests the majority of its plan assets in institutional funds which includes a diversified portfolio of domestic and international equity securities and fixed income securities. The asset portfolio also includes cash equivalents and a real estate limited partnership. The expected rates of return 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 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.

The FASB guidance on disclosure for other post-retirement benefit 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 Other Post-retirement Benefits Plan are primarily obtained from independent pricing services. These prices are based on observable market data. The institutional funds are valued using the NAV provided by the administrator of the fund. The NAV price is quoted on a restrictive market although the underlying investments are traded on active markets. During the third quarter of 2016, the Company concluded that the NAV used for determining the fair value of the investments in the institutional funds have readily determinable fair values. Accordingly, such fund values have been re-categorized from Level 2 to Level 1 hierarchy.

• Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. 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.

The fair value of the Company’s Other Post-retirement Benefits Plan assets at December 31, 2016 and 2015, 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, 2016		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Institutional Funds (a)
Equity funds	$	26,133	$	26,133	$	—	$	—
Fixed income funds	11,671		11,671		—		—
Total Institutional Funds	37,804		37,804		—		—
Limited Partnership Interest in Real Estate (b) (c)	1,311
Total Plan Investments	$	39,115	$	37,804	$	—	$	—
Description of Securities	Fair Value as of December 31, 2015		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Institutional Funds (a)
Equity funds	$	24,881	$	24,881	$	—	$	—
Fixed income funds	11,599		11,599		—		—
Total Institutional Funds	36,480		36,480		—		—
Limited Partnership Interest in Real Estate (b) (c)	1,610
Total Plan Investments	$	38,090	$	36,480	$	—	$	—

 ___________________

(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.

(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 of 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 guidance. 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. ASU 2015-07 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years.

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

	Fair Value of Investments  in Real Estate
Balance at December 31, 2014	$	1,640
Unrealized loss in fair value	(30		)
Balance at December 31, 2015	1,610
Sale of land	(145		)
Unrealized loss in fair value	(154		)
Balance at December 31, 2016	$	1,311

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, 2016 and 2015. 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, 2016 and 2015.

The Company adheres 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 seeks 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 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 ERISA and DOL regulations.

The Company expects to contribute $1.5 million to its other post-retirement benefits plan in 2017. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):

2017	$	2,622
2018	2,880
2019	3,057
2020	3,320
2021	3,510
2022-2026	20,084

Annual Short-Term Incentive Plan

The Annual Short-Term Incentive Plan (the "Incentive Plan") provides for the payment of cash awards to eligible Company employees, including each of its named executive officers. Payment of awards is based on the achievement of performance measures reviewed and approved by the Company’s Board of Directors’ Compensation Committee. Generally, these performance measures are based on meeting certain financial, operational and individual performance criteria. The financial performance goals are based on earnings per share and the operational performance goals are based on compliance, customer satisfaction, and reliability. If a specified level of earnings per share is not attained, no amounts will be paid under the Incentive Plan, unless the Compensation Committee determines otherwise. In 2016, the Company reached the required levels of earnings per share, customer satisfaction, reliability, compliance, and safety goals for an incentive payment of $12.5 million. In 2015 and 2014, the Company reached the required levels of earnings per share, safety, compliance, and customer satisfaction goals for an incentive payment of $10.5 million and $7.4 million, respectively. The Company has renewed the Incentive Plan in 2017 with similar goals.

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Franchises and Significant Customers

12 Months Ended

Dec. 31, 2016

Franchises and Significant Customers [Abstract]

Franchises And Significant Customers

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 to4.00%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 at3.25%of gross revenues, but the 2010 amendment added an incremental fee equal to0.75%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 onJuly 31, 2030.

The Company does not have a written franchise agreement with the City of Las Cruces, the second largest city in its service territory. The Company provides electric distribution service to the City of Las Cruces under an implied franchise by satisfying all obligations under the franchise agreement that expired onApril 30, 2009. The Company pays the City of Las Cruces a franchise fee of2.00%of gross revenues the Company receives from services within the City of Las Cruces.

Military Installations

The Company serves HAFB, White Sands Missile Range ("White Sands") and Fort Bliss. These military installations represent approximately2.8% 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 provided under the applicable New Mexico tariffs.

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Financial Instruments and Investments (Notes)

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Financial Instruments and Investments

Financial Instruments and Investments

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

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

	December 31,
	2016				2015
	Carrying Amount (1)		Estimated Fair Value		Carrying Amount (1)		Estimated Fair Value
Pollution Control Bonds	$	190,775	$	206,818	$	190,499	$	212,624
Senior Notes	993,086		1,112,285		837,475		829,864
RGRT Senior Notes (2)	94,795		98,855		94,686		100,345
RCF (2)	81,574		81,574		141,738		141,738
Total	$	1,360,230	$	1,499,532	$	1,264,398	$	1,284,571

 __________________

(1) The Company implemented ASU 2015-03, Interest - Imputation of Interest, which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The impact of ASU 2015-03 on the Company's Balance Sheet was to reclassify $11.6 million of other deferred charges to long-term debt, net of current portion at December 31, 2015.

(2) Nuclear fuel financing, as of December 31, 2016 and December 31, 2015, is funded through the $95 million RGRT Senior Notes and $37.6 million and $33.7 million, respectively under the RCF. As of December 31, 2016, $44.0 million was outstanding under the RCF for working capital or general corporate purposes. As of December 31, 2015, $108.0 million amount was outstanding under the RCF for working capital or general corporate purposes. The interest rate on the Company’s borrowings under the RCF is reset throughout the period reflecting current market rates. Consequently, the carrying value approximates fair value.

Treasury Rate Locks. The Company entered into treasury rate lock agreements in 2005 to hedge against potential movements in the treasury reference interest rate pending the issuance of the 6% Senior Notes. The treasury rate lock agreements met the criteria for hedge accounting and were designated as a cash flow hedge. In accordance with cash flow hedge accounting, the Company recorded the loss associated with the fair value of the cash flow hedge, net of tax, as a component of accumulated other comprehensive loss and amortizes the accumulated comprehensive loss to earnings as interest expense over the life of the 6% Senior Notes. In 2017, approximately $0.5 million of this accumulated other comprehensive loss item will be reclassified to interest expense.

Contracts and Derivative Accounting. The Company uses commodity contracts to manage its exposure to price and availability risks for fuel purchases and power sales and purchases and these contracts generally have the characteristics of derivatives. The Company does not trade or use these instruments with the objective of earning financial gains on the commodity price fluctuations. The Company has determined that all such contracts outstanding at December 31, 2016, except for certain natural gas commodity contracts with optionality features, that had the characteristics of derivatives met the "normal purchases and normal sales" exception provided in the FASB guidance for accounting for derivative instruments and hedging activities, and, as such, were not required to be accounted for as derivatives.

Marketable Securities. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair value which was $255.7 million and $239.0 million at December 31, 2016 and 2015, respectively. These securities are classified as available for sale and recorded at their estimated fair value using the FASB guidance for certain investments in debt and equity securities. The reported fair values include gross unrealized losses on marketable securities whose impairment the Company has deemed to be temporary. The tables below present the gross unrealized losses and the fair value of these securities, aggregated by investment category and length of time that individual securities have been in a continuous unrealized loss position (in thousands):

	December 31, 2016
	Less than 12 Months					12 Months or Longer					Total
	Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses
Description of Securities (1):
Federal Agency Mortgage Backed Securities	$	11,582	$	(239	)	$	436	$	(22	)	$	12,018	$	(261	)
U.S. Government Bonds	31,655		(762		)	17,976		(835		)	49,631		(1,597		)
Municipal Obligations	9,596		(394		)	4,067		(372		)	13,663		(766		)
Corporate Obligations	7,971		(172		)	2,092		(172		)	10,063		(344		)
Total Debt Securities	60,804		(1,567		)	24,571		(1,401		)	85,375		(2,968		)
Common Stock	2,760		(167		)	—		—			2,760		(167		)
Institutional Funds-International Equity	22,945		(110		)	—		—			22,945		(110		)
Total Temporarily Impaired Securities	$	86,509	$	(1,844	)	$	24,571	$	(1,401	)	$	111,080	$	(3,245	)

 ____________________

(1) Includes approximately 152 securities.

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

 ______________________

(2) Includes approximately 133 securities.

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

For the twelve months ended December 31, 2016, 2015, and 2014, the Company recognized other than temporary impairment losses on its available-for-sale securities as follows (in thousands):

	2016			2015			2014
Unrealized holding losses included in pre-tax income	$	(352	)	$	(338	)	$	—

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

	December 31, 2016				December 31, 2015
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
Description of Securities:
Federal Agency Mortgage Backed Securities	$	7,430	$	319	$	9,589	$	438
U.S. Government Bonds	12,237		138		12,033		136
Municipal Obligations	2,481		144		8,671		332
Corporate Obligations	12,350		655		10,110		368
Total Debt Securities	34,498		1,256		40,403		1,274
Common Stock	61,884		34,066		72,636		37,001
Equity Mutual Funds	42,244		3,345		18,853		91
Cash and Cash Equivalents	6,002		—		8,204		—
Total	$	144,628	$	38,667	$	140,096	$	38,366

The Company’s marketable securities include investments in mortgage backed securities, municipal, corporate and federal debt obligations. The contractual year for maturity for these available-for-sale securities as of December 31, 2016 is as follows (in thousands):

	Total		2017		2018 through 2021		2022 through 2026		2027 and Beyond
Municipal Debt Obligations	$	16,144	$	990	$	6,253	$	8,139	$	762
Corporate Debt Obligations	22,413		—		8,664		6,090		7,659
U.S. Government Bonds	61,868		14,272		22,495		14,786		10,315
Federal Agency Mortgage Backed Securities	19,448		—		5		390		19,053

The Company’s marketable securities in its decommissioning trust funds are sold from time to time and the Company uses the specific identification basis to determine the amount to reclassify out of accumulated other comprehensive income and into net income. The proceeds from the sale of these securities during the twelve months ended December 31, 2016, 2015, and 2014 and the related effects on pre-tax income are as follows (in thousands):

	2016			2015			2014
Proceeds from sales of available-for-sale securities	$	91,268		$	102,567		$	108,311
Gross realized gains included in pre-tax income	$	9,212		$	12,379		$	7,858
Gross realized losses included in pre-tax income	(1,220		)	(927		)	(508		)
Gross unrealized losses included in pre-tax income	(352		)	(338		)	—
Net gains in pre-tax income	$	7,640		$	11,114		$	7,350
Net unrealized holding gains (losses) included in accumulated other comprehensive income	$	8,444		$	(2,906	)	$	10,827
Net (gains) losses reclassified out of accumulated other comprehensive income	(7,640		)	(11,114		)	(7,350		)
Net gains (losses) in other comprehensive income	$	804		$	(14,020	)	$	3,477

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

• Level 1 - Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Financial assets utilizing Level 1 inputs include the nuclear decommissioning trust investments in active exchange-traded equity securities, mutual funds and U.S. Treasury securities that are in a highly liquid and active market. The Institutional Funds are valued using the NAV provided by the administrator of the fund. The NAV price is quoted on a restrictive market although the underlying investments are traded on active markets. During the third quarter of 2016, the Company concluded that the NAV used for determining the fair value of the Institutional Funds- International Equity investments have readily determinable fair values. Accordingly, such fund values have been re-categorized from Level 2 to Level 1 hierarchy.

• Level 2 - Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. Financial assets utilizing Level 2 inputs include the nuclear decommissioning trust investments in fixed income securities. The fair value of these financial instruments is based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences.

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

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

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

Description of Securities	Fair Value as  of December 31, 2016		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Trading Securities:
Investments in Debt Securities	$	1,421	$	—	$	—	$	1,421
Available for sale:
U.S. Government Bonds	$	61,868	$	61,868	$	—	$	—
Federal Agency Mortgage Backed Securities	19,448		—		19,448		—
Municipal Obligations	16,144		—		16,144		—
Corporate Obligations	22,413		—		22,413		—
Subtotal, Debt Securities	119,873		61,868		58,005		—
Common Stock	64,644		64,644		—		—
Equity Mutual Funds	42,244		42,244		—		—
Institutional Funds-International Equity	22,945		22,945		—		—
Cash and Cash Equivalents	6,002		6,002		—		—
Total available for sale	$	255,708	$	197,703	$	58,005	$	—

Description of Securities	Fair Value as  of December 31, 2015		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Trading Securities:
Investments in Debt Securities	$	1,543	$	—	$	—	$	1,543
Available for sale:
U.S. Government Bonds	$	50,399	$	50,399	$	—	$	—
Federal Agency Mortgage Backed Securities	20,085		—		20,085		—
Municipal Obligations	24,345		—		24,345		—
Corporate Obligations	18,475		—		18,475		—
Subtotal, Debt Securities	113,304		50,399		62,905		—
Common Stock	76,220		76,220		—		—
Equity Mutual Funds	18,853		18,853		—		—
Institutional Funds-International Equity	22,454		22,454		—		—
Cash and Cash Equivalents	8,204		8,204		—		—
Total available for sale	$	239,035	$	176,130	$	62,905	$	—

Below is a reconciliation of the beginning and ending balance of the fair value of the investment in debt securities (in thousands):

	2016			2015
Balance at January 1	$	1,543		$	1,653
Net unrealized gains (losses) in fair value recognized in income (a)	(122		)	(110		)
Balance at December 31	$	1,421		$	1,543

_____________________

(a) These amounts are reflected in the Company's statements of operations as investment and interest income.

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, 2016 and 2015. There were no purchases, sales, issuances, and settlements related to the assets in the Level 3 fair value measurement category during the twelve month periods ending December 31, 2016 and 2015.

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Supplemental Statements of Cash Flows Disclosures

12 Months Ended

Dec. 31, 2016

Supplemental Cash Flow Information [Abstract]

Cash Flow, Supplemental Disclosures

Supplemental Statements of Cash Flows Disclosures

	Years Ended December 31,
	2016		2015			2014
	(In thousands)
Cash paid for:
Interest on long-term debt and borrowing under the revolving credit facility	$	69,990	$	62,297		$	54,792
Income taxes, net of refund	2,328		1,000			6,876
Non-cash investing and financing activities:
Sale of Interest in Four Corners Generating Station (a)	27,720		—			—
Changes in accrued plant additions	4,789		(6,660		)	7,314
Grants of restricted shares of common stock	1,236		1,567			3,025

(a) The Company sold its interest in Four Corners for approximately $32.0 million based on the book value as defined in the Purchase and Sale Agreement. The sales price was adjusted downward by $7.0 million and $19.5 million to reflect APS's affiliate assumption of the Company's obligation to pay for future plant decommissioning and mine reclamation expense, respectively. The sales price was also adjusted downward by approximately $1.3 million for closing adjustments and other assets and liabilities assumed by APS's affiliate. At the closing of the sale, the Company received approximately $4.2 million in cash, subject to post-closing adjustments.

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Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2016

Selected Quarterly Financial Data

Quarterly Financial Information

Selected Quarterly Financial Data (Unaudited)

The following table summarizes the Company’s unaudited results of operations on a quarterly basis. The quarterly earnings per share amounts for a year will not add to the earnings per share for that year due to the weighting of shares used in calculating per share data.

	2016 Quarters									2015 Quarters
	4th		3rd (2)		2nd		1st			4th		3rd		2nd		1st
					(In thousands except for share data)
Operating revenues (1)	$	188,037	$	323,225	$	217,865	$	157,809		$	176,902	$	289,713	$	219,508	$	163,746
Operating income (loss)	20,470		129,857		44,697		(163		)	8,312		88,047		41,872		7,960
Net income (loss)	5,656		74,636		22,284		(5,808		)	648		56,740		21,072		3,458
Basic earnings per share:
Net income (loss)	0.14		1.84		0.55		(0.14		)	0.02		1.40		0.52		0.09
Diluted earnings per share:
Net income (loss)	0.14		1.84		0.55		(0.14		)	0.02		1.40		0.52		0.09
Dividends declared per share of common stock	0.310		0.310		0.310		0.295			0.295		0.295		0.295		0.280

 ________________

(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.

(2) For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2015 Texas Retail Rate Case until it received the PUCT Final Order on August 25, 2016. Accordingly, it reported in the third quarter of 2016 the cumulative effect of the PUCT Final Order which related back to January 12, 2016. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.

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Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Basis of Accounting, Policy

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

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

Application of FASB Guidance for Regulated Operations

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

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. 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 2016, 2015 and 2014 was 2.28%, 2.64%, and 2.60%, 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 in the most recent final orders from the Public Utility Commission of Texas ("PUCT") and the New Mexico Public Regulation Commission ("NMPRC") and changes in the estimated life of certain intangible software assets. See Part II, Item 8, Financial Statements and Supplementary Data, Note C and Note E.

Previously, the Company recorded gains and losses on the disposition of vehicles in earnings when realized. However, beginning in 2016, the Company began crediting the proceeds (salvage) on the disposition of vehicles to accumulated depreciation.

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 Nuclear 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

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.

AFUDC and Capitalized Interest

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. AFUDC is compounded on a semi-annual basis. The average AFUDC rates used in 2016, 2015 and 2014 were 6.43%, 7.18% and 8.15%, respectively.

Asset Retirement Obligation

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

Cash and Cash Equivalents. All temporary cash investments with an original maturity of three months or less are considered cash equivalents.

Investments

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

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. 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

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 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 $21.0 million and $21.7 million as of December 31, 2016 and 2015, respectively. The Company presents revenues net of sales taxes in its statements of operations.

Allowance for Doubtful Accounts

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 2016, 2015 and 2014 are as follows (in thousands):

	2016		2015		2014
Balance at beginning of year	$	2,046	$	2,253	$	2,261
Additions:
Charged to costs and expense	2,427		2,057		2,755
Recovery of previous write-offs	1,395		1,613		1,516
Uncollectible receivables written off	3,712		3,877		4,279
Balance at end of year	$	2,156	$	2,046	$	2,253

Income Taxes

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. Historically, 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. 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.

Earnings per Share

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 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

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.

Reclassification

Reclassification. Certain amounts in the Company's financial statements for 2015 have been reclassified to conform to the 2016 presentation. The Company implemented Accounting Standards Update ("ASU") 2015-03 and ASU 2015-17 in the first quarter of 2016, retrospectively to all periods presented in the Company's financial statements. See Part II, Item 8, Financial Statements and Supplementary Data, Note I and Note O for impact of ASU 2015-03, and Note J for impact of ASU 2015-17

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Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Depreciation, Depletion, and Amortization

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).

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Employee Benefits Pension and Other Postretirement Benefit Plans Policies (Policies)

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Pension and Other Postretirement Plans, Pensions, Policy

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 collected from customers in the Company's Texas and New Mexico jurisdictions and the annual 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 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.

During the quarter ended March 31, 2014, the Company implemented certain amendments to the Retirement Plan and Excess Benefit Plan. In the first quarter of 2014, the Company offered a cash balance pension plan as an alternative to its current final average pay pension plan for employees hired prior to January 1, 2014. The cash balance pension plan also included an enhanced employer matching contribution to the employee’s respective 401(k) Defined Contribution Plan (discussed below). For employees that elected the new cash balance feature of the plans, the pension benefit earned under the existing final average pay feature of the plans was frozen as of March 31, 2014. Employees hired after January 1, 2014 were automatically enrolled in the cash balance pension plan. The amendments to the plans were effective April 1, 2014. As a result of these actions, the Company remeasured the assets and liabilities of the plans, based on actuarially determined estimates, using the close of the alternative choice election period of February 28, 2014, as the remeasurement date.

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 plan covers employees beginning on their employment commencement date or re-employment commencement date in any plan year in which the employee completes at least a minimum number of hours of service. Retirement benefits under the cash balance pension plan are based on the employee’s cash balance account, consisting of pay credits and interest credits.

Pension and Other Postretirement Plans, Nonpension Benefits, Policy

The Company provides certain health care benefits for retired employees and their eligible dependents and life insurance benefits for retired employees only. Substantially all of the Company’s employees may become eligible for those benefits if they retire while working for the Company.

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Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Allowance for Doubtful Accounts Receivable

Additions, deductions and balances for allowance for doubtful accounts for 2016, 2015 and 2014 are as follows (in thousands):

	2016		2015		2014
Balance at beginning of year	$	2,046	$	2,253	$	2,261
Additions:
Charged to costs and expense	2,427		2,057		2,755
Recovery of previous write-offs	1,395		1,613		1,516
Uncollectible receivables written off	3,712		3,877		4,279
Balance at end of year	$	2,156	$	2,046	$	2,253

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2016

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

Regulatory assets and liabilities reflected in the Company's balance sheet are presented below (in thousands):

	Amortization Period Ends	December 31, 2016		December 31, 2015
Regulatory assets
Regulatory tax assets (a)	(b)	$	66,670	$	69,359
Loss on reacquired debt (c)	May 2035	15,780		16,632
Final coal reclamation (d)	(e)	9,581		9,520
Nuclear fuel postload daily financing charge	(e)	3,831		4,195
Unrecovered issuance costs due to reissuance of PCBs (c)	August 2042	794		827
Texas energy efficiency	(f)	—		25
Texas 2015 rate case costs	September 2018	2,670		1,882
Texas 2017 rate case costs	(g)	246		—
Texas relate back surcharge	(h)	6,455		—
New Mexico renewable energy credits and related costs (i)	June 2022	6,937		6,397
New Mexico 2010 FPPCAC audit	June 2019	398		434
New Mexico Palo Verde deferred depreciation	(b)	4,415		4,568
New Mexico 2015 rate case costs	June 2019	1,074		1,288
New Mexico 2017 rate case costs	(g)	10		—
Total regulatory assets		$	118,861	$	115,127
Regulatory liabilities
Regulatory tax liabilities (a)	(b)	$	10,648	$	17,266
Accumulated deferred investment tax credit (j)	(b)	3,328		4,011
Texas energy efficiency	(f)	1,288		—
New Mexico energy efficiency	(f)	2,159		2,238
Texas military base discount and recovery factor	(k)	184		788
New Mexico gain on sale of assets (l)	June 2019	828		—
Total regulatory liabilities		$	18,435	$	24,303

______________________________

(a) We do not earn a return on these items since the related accumulated deferred income tax assets and liabilities offset.

(b) The amortization periods for these assets and liabilities are based upon the life of the associated assets or liabilities.

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

(d) This item relates to coal reclamation costs associated with Four Corners. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.

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

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

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

(h) This item relates to the recovery of revenues through a separate surcharge beginning October 1, 2016 and ending September 30, 2017. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.

(i) This item relates to renewable energy credits and procurement plan costs, components approved for recovery in the New Mexico 2015 rate case.

(j) This item is excluded from rate base.

(k) 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.

(l) 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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Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant (Tables)

12 Months Ended

Dec. 31, 2016

Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract]

Schedule of Property, Plant and Equipment and Finite-Lived Intangible Assets By Major Class

The table below presents the balance of each major class of depreciable assets at December 31, 2016 (in thousands):

	Gross Plant		Accumulated Depreciation			Net Plant
Nuclear production	$	948,382	$	(320,000	)	$	628,382
Steam and other	926,419		(186,539		)	739,880
Total production	1,874,801		(506,539		)	1,368,262
Transmission	498,660		(259,488		)	239,172
Distribution	1,127,897		(365,601		)	762,296
General	205,866		(57,240		)	148,626
Intangible	84,342		(55,464		)	28,878
Total	$	3,791,566	$	(1,244,332	)	$	2,547,234

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense

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):

2014	$	8,051
2015	6,482
2016	5,302
2017 (estimated)	5,148
2018 (estimated)	4,631
2019 (estimated)	4,242
2020 (estimated)	3,808
2021 (estimated)	3,227

Schedule of Jointly Owned Utility Plants

A summary of the Company’s investment in jointly-owned utility plant, excluding fuel inventories, at December 31, 2016 and 2015 is as follows (in thousands):

	December 31, 2016						December 31, 2015
	Palo Verde			Other (a)			Palo Verde			Other (a)
Electric plant in service	$	948,382		$	67,621		$	917,483		$	229,627
Accumulated depreciation	(320,000		)	(44,377		)	(304,060		)	(181,886		)
Construction work in progress	50,598			1,895			48,938			9,528
Total	$	678,980		$	25,139		$	662,361		$	57,269

_______________

(a) 2015 other jointly-owned utility plant includes a 7% interest in Units 4 and 5 at Four Corners and certain other transmission facilities which the Company sold on July 6, 2016.

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Accounting for Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2016

Accounting for Asset Retirement Obligations

Changes In Estimated Probabilities Assumptions

The assumptions used to calculate 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	3.60	%	6.20	%

Schedule of Asset Retirement Obligations

	2016			2015		2014
ARO liability at beginning of year	$	81,621		$	74,577	$	65,214
Liabilities incurred	—			189		—
Liabilities settled	(6,993		)	—		—
Revisions to estimate	—			—		3,561
Accretion expense	7,172			6,855		5,802
ARO liability at end of year	$	81,800		$	81,621	$	74,577

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Common Stock (Tables)

12 Months Ended

Dec. 31, 2016

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Treasury Stock by Class

Detail regarding the Company's stock repurchase program are presented below:

	Since 1999 (a)		Authorized Shares
Shares repurchased (b)	25,406,184
Cost, including commission (in thousands)	$	423,647
Total remaining shares available for repurchase at December 31, 2016			393,816

______________________

(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 188,005 shares out of treasury stock during 2016.

Schedule of Earnings Per Share, Basic and Diluted

The basic and diluted earnings per share are presented below:

	Years Ended December 31,
	2016			2015			2014
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	40,350,688			40,274,986			40,190,991
Dilutive effect of unvested performance awards	57,345			33,576			20,726
Diluted number of common shares outstanding	40,408,033			40,308,562			40,211,717
Basic net income per common share:
Net income	$	96,768		$	81,918		$	91,428
Income allocated to participating restricted stock	(321		)	(243		)	(301		)
Net income available to common shareholders	$	96,447		$	81,675		$	91,127
Diluted net income per common share:
Net income	$	96,768		$	81,918		$	91,428
Income reallocated to participating restricted stock	(321		)	(243		)	(301		)
Net income available to common shareholders	$	96,447		$	81,675		$	91,127
Basic net income per common share:
Distributed earnings	$	1.225		$	1.165		$	1.105
Undistributed earnings	1.165			0.865			1.165
Basic net income per common share	$	2.390		$	2.030		$	2.270
Diluted net income per common share:
Distributed earnings	$	1.225		$	1.165		$	1.105
Undistributed earnings	1.165			0.865			1.165
Diluted net income per common share	$	2.390		$	2.030		$	2.270

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share

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,
	2016	2015	2014
Restricted stock awards	53,703	56,375	60,455
Performance shares (a)	47,246	66,804	96,208

_____________________

(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.

Restricted Stock

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Expense, Deferred Tax Benefit, and Current Tax Expense Related to Restricted Stock Awards

The expense, deferred tax benefit, and current tax expense recognized related to restricted stock and other stock-based awards in 2016, 2015 and 2014 is presented below (in thousands):

	2016		2015		2014
Expense (a)	$	2,594	$	2,755	$	3,471
Deferred tax benefit	908		964		1,215
Current tax benefit recognized	183		43		39

_____________________

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

Schedule of Restricted Stock Activity

The unvested restricted stock transactions for 2016 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, 2015	91,210		$	36.61
Stock awards	74,181		40.95
Vested	(55,503	)	35.91
Forfeitures	(495	)	36.88
Restricted shares outstanding at December 31, 2016	109,393		39.90		$	1,767	$	5,087

_______________________

(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.

Schedule of Share-based Compensation Award, Restricted Stock, Grants in Period, Weighted Average Grant Date Fair Value

The weighted average fair value per share at grant date for restricted stock and other stock-base awards granted during 2016, 2015 and 2014 were:

	2016		2015		2014
Weighted average fair value per share	$	40.95	$	37.17	$	36.95

Schedule of Share-based Compensation, Activity

The aggregate intrinsic value and fair value at grant date of restricted stock and other stock-based awards which vested in 2016, 2015 and 2014 is presented below (in thousands):

	2016		2015		2014
Aggregated intrinsic value	$	2,515	$	3,451	$	3,441
Fair value at grant date	1,993		3,327		3,330

Performance Shares

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Share-based Compensation Award, Performance-Based Units, Vested and Expected to Vest

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 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	—
February 18, 2014	0	%	0	954		2011-2013	—

Schedule of Performance Stock Activity

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, 2015 (a)	130,136		$	32.72
Performance share awards	60,835		38.11
Performance shares expired	(24,527	)	34.69
Performance shares outstanding at December 31, 2016 (a)	166,444		34.40		$	2,189	$	7,740

_______________________

(a) On December 15, 2015, the Company issued a stock based retention grant to the Chief Executive Officer (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.

(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.

Schedule of Share-based Compensation, Activity

A summary of information related to performance shares for 2016, 2015 and 2014 is presented below:

	2016		2015		2014
Weighted average per share grant date fair value per share of performance shares awarded	$	38.11	$	35.72	$	26.36
Compensation expense (in thousands) (a) (b)	1,655		1,042		1,181
Deferred tax benefit related to compensation expense (in thousands) (b)	579		365		413

_____________________

(a) Includes adjustments for estimated forfeitures.

(b) Includes CEO retention grant.

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Accumulated Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2016

Accumulated Other Comprehensive Income (Loss) [Line Items]

Schedule of 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, 2013		$	(21,330	)	$	36,240		$	(12,298	)	$	2,612
	Other comprehensive income (loss) before reclassifications	(12,628		)	8,694			—			(3,934		)
	Amounts reclassified from accumulated other comprehensive income (loss)	(926		)	(5,977		)	224			(6,679		)
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	)

Reclassification out of Accumulated Other Comprehensive Income

Amounts reclassified from Accumulated Other Comprehensive Income (Loss) for the twelve months ended December 31, 2016, 2015 and 2014 are as follows (in thousands):

Details about Accumulated Other Comprehensive Income (Loss) Components		2016			2015			2014			Affected Line Item in the Statements of Operations
Amortization of pension and post-retirement benefit costs:
	Prior service benefit	$	7,407		$	6,574		$	7,659		(a)
	Net loss	(4,965		)	(8,622		)	(6,182		)	(a)
		2,442			(2,048		)	1,477			(a)
	Income tax effect	(1,020		)	810			(551		)	Income tax expense
		1,422			(1,238		)	926			Net income
Marketable securities:
	Net realized gain on sale of securities	7,640			11,114			7,350			Investment and interest income, net
		7,640			11,114			7,350			Income before income taxes
	Income tax effect	(1,434		)	(2,177		)	(1,373		)	Income tax expense
		6,206			8,937			5,977			Net income
Loss on cash flow hedge:
	Amortization of loss	(498		)	(467		)	(438		)	Interest on long-term debt and revolving credit facility
		(498		)	(467		)	(438		)	Income before income taxes
	Income tax effect	339			203			214			Income tax expense
		(159		)	(264		)	(224		)	Net income
	Total reclassifications	$	7,469		$	7,435		$	6,679

(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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Long-Term Debt and Financing Obligations (Tables)

12 Months Ended

Dec. 31, 2016

Long-Term Debt and Financing Obligations [Abstract]

Schedule of Debt

Outstanding long-term debt and financing obligations are as follows:

	December 31,
	2016			2015 (1)
	(In thousands)
Long-Term Debt:
Pollution Control Bonds (2):
7.25% 2009 Series A refunding bonds, due 2040 (7.46% effective interest rate)	$	62,619		$	62,582
4.50% 2012 Series A refunding bonds, due 2042 (4.63% effective interest rate)	58,471			58,441
7.25% 2009 Series B refunding bonds, due 2040 (7.49% effective interest rate)	36,492			36,465
1.875% 2012 Series A refunding bonds, due 2032 (2.35% effective interest rate)	33,193			33,011
Total Pollution Control Bonds	190,775			190,499
Senior Notes (3):
6.00% Senior Notes, net of discount, due 2035 (7.12% effective interest rate)	393,861			393,693
7.50% Senior Notes, net of discount, due 2038 (7.67% effective interest rate)	147,331			147,282
3.30% Senior Notes, net of discount, due 2022 (3.43% effective interest rate)	148,939			148,783
5.00% Senior Notes, net of discount, due 2044 (4.93% effective interest rate)	302,955			147,717
Total Senior Notes	993,086			837,475
RGRT Senior Notes (4):
4.47% Senior Notes, Series B, due 2017 (4.62% effective interest rate)	49,950			49,883
5.04% Senior Notes, Series C, due 2020 (5.16% effective interest rate)	44,845			44,803
Total RGRT Senior Notes	94,795			94,686
Total long-term debt	1,278,656			1,122,660
Financing Obligations:
Revolving Credit Facility ($81,574 due in 2017) (5)	81,574			141,738
Total long-term debt and financing obligations	1,360,230			1,264,398
Current Portion (amount due within one year):
Current maturities of long term debt	(83,143		)	—
Short-term borrowings under the revolving credit facility	(81,574		)	(141,738		)
	$	1,195,513		$	1,122,660

_____________________

(1) The Company implemented ASU 2015-03, Interest - Imputation of Interest, which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The impact of ASU 2015-03 on the Company's Balance Sheet was to reclassify $11.6 million of other deferred charges to long-term debt, net of current portion at December 31, 2015.

(2) Pollution Control Bonds ("PCBs")

The Company has four series of tax exempt unsecured PCBs in aggregate principal amount of $193.1 million. The 1.875% 2012 Series A (El Paso Electric Company Four Corners Project) Pollution Control Refunding Revenue Bonds with an aggregate principal amount of $33.3 million are subject to mandatory tender for purchase in September 2017 at which time the Company will either repay or remarket these bonds.

(3) 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.

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.

(4) 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 (the "Notes"). In August 2015, $15.0 million of these Notes matured and were paid with borrowings from the RCF. In August 2017, $50.0 million of these Senior Notes will mature. The Company will either repay or refinance this $50.0 million of Notes upon maturity. The Company guarantees the payment of principal and interest on the 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 Notes on February 15, and August 15 of each year until maturity. RGRT may redeem the 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 2016.

The sale of the 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 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 Notes and amounts borrowed from the RCF.

(5) 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 2016. In August 2015, $15.0 million aggregate principal amount of Series A 3.67% Senior Notes of RGRT matured and were paid utilizing borrowings under the RCF. As of December 31, 2016, the total amount borrowed by RGRT was $37.6 million for nuclear fuel under the RCF. As of December 31, 2016, $44.0 million of borrowings were outstanding under this facility for working capital and general corporate purposes. The weighted average interest rate on the RCF was 2.0% as of December 31, 2016.

Schedule of Maturities of Long-term Debt

As of December 31, 2016, the principal amount of scheduled maturities for the next five years of long-term debt are as follows (in thousands):

2017	$	83,300
2018	—
2019	—
2020	45,000
2021	—

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

Income Taxes [Abstract]

Schedule of Deferred Tax Assets and Liabilities

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2016 and 2015 are presented below (in thousands):

	December 31,
	2016			2015
Deferred tax assets:
Benefit of tax loss carryforwards	$	60,749		$	35,153
Alternative minimum tax credit carryforward	16,620			16,620
Pensions and benefits	57,756			61,673
Asset retirement obligation	26,929			28,042
Deferred fuel	—			1,488
Other	(200		)	15,421
Total gross deferred tax assets	161,854			158,397
Deferred tax liabilities:
Plant, principally due to depreciation and basis differences	(668,303		)	(608,738		)
Decommissioning	(43,463		)	(41,100		)
Deferred fuel	(3,962		)	—
Other	(1,192		)	(3,796		)
Total gross deferred tax liabilities	(716,920		)	(653,634		)
Net accumulated deferred income taxes	$	(555,066	)	$	(495,237	)

Schedule of Components of Income Tax Expense (Benefit)

The Company recognized income tax expense for 2016, 2015 and 2014 as follows (in thousands):

	Years Ended December 31,
	2016			2015			2014
Income tax expense:
Federal:
Current	$	2,642		$	2,319		$	(1,250	)
Deferred	47,909			32,819			38,810
Total federal income tax	50,551			35,138			37,560
State:
Current	766			1,730			3,209
Deferred	3,285			(1,650		)	641
Total state income tax	4,051			80			3,850
Generation (amortization) of accumulated investment tax credits	(684		)	(323		)	(322		)
Total income tax expense	$	53,918		$	34,895		$	41,088

Schedule of Effective Income Tax Rate Reconciliation

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):

	Years Ended December 31,
	2016			2015			2014
Federal income tax expense computed on income at statutory rate	$	52,740		$	40,885		$	46,381
Difference due to:
State taxes, net of federal benefit	2,633			52			1,902
AEFUDC	(475		)	(2,345		)	(3,757		)
Permanent tax differences	(2,369		)	(2,898		)	(2,921		)
Other	1,389			(799		)	(517		)
Total income tax expense	$	53,918		$	34,895		$	41,088
Effective income tax rate	35.8		%	29.9		%	31.0		%

Summary of Income Tax Contingencies

A reconciliation of the December 31, 2016, 2015 and 2014 amounts of unrecognized tax benefits are as follows (in thousands):

	2016			2015		2014
Balance at January 1	$	6,000		$	5,200	$	7,200
Additions for tax positions related to the current year	400			500		300
Reductions for tax positions related to the current year	—			—		—
Additions for tax positions of prior years	100			300		2,200
Reductions for tax positions of prior years	(1,200		)	—		(4,500		)
Balance at December 31	$	5,300		$	6,000	$	5,200

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Commitments, Contingencies and Uncertainties (Tables)

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Long-term Purchase and Sale Commitment

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 June 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 April 2034	May 2014
Power Purchase Agreement	Newman Solar LLC		10	MW	December 2014 through November 2044	December 2014

Schedule of Future Minimum Rental Payments for Operating Leases

As of December 31, 2016, the Company’s minimum future rental payments for the next five years are as follows (in thousands):

2017	$	808
2018	662
2019	666
2020	664
2021	562

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Employee Benefits (Tables)

12 Months Ended

Dec. 31, 2016

Defined Benefit Plan Disclosure [Line Items]

Schedule of Amount Recognized in 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, 2013		$	(21,330	)	$	36,240		$	(12,298	)	$	2,612
	Other comprehensive income (loss) before reclassifications	(12,628		)	8,694			—			(3,934		)
	Amounts reclassified from accumulated other comprehensive income (loss)	(926		)	(5,977		)	224			(6,679		)
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	)

Retirement Income Plan

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Funded Status

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

	December 31,
	2016						2015
	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	$	325,706		$	26,958		$	341,133		$	28,397
Service cost	7,705			296			8,530			262
Interest cost	12,161			878			13,477			1,018
Actuarial (gain) loss	7,988			1,267			(19,290		)	(810		)
Benefits paid	(15,792		)	(1,937		)	(18,144		)	(1,909		)
Benefit obligation at end of year	337,768			27,462			325,706			26,958
Change in plan assets:
Fair value of plan assets at end of prior year	260,035			—			272,939			—
Actual return (loss) on plan assets	18,223			—			(3,760		)	—
Employer contribution	7,300			1,937			9,000			1,909
Benefits paid	(15,792		)	(1,937		)	(18,144		)	(1,909		)
Fair value of plan assets at end of year	269,766			—			260,035			—
Funded status at end of year	$	(68,002	)	$	(27,462	)	$	(65,671	)	$	(26,958	)

Schedule of Amounts Recognized in Balance Sheet

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

	December 31,
	2016						2015
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Current liabilities	$	—		$	(2,696	)	$	—		$	(2,102	)
Noncurrent liabilities	(68,002		)	(24,766		)	(65,671		)	(24,856		)
Total	$	(68,002	)	$	(27,462	)	$	(65,671	)	$	(26,958	)

Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets

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

	December 31,
	2016						2015
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Projected benefit obligation	$	(337,768	)	$	(27,462	)	$	(325,706	)	$	(26,958	)
Accumulated benefit obligation	(314,071		)	(25,550		)	(302,446		)	(25,785		)
Fair value of plan assets	269,766			—			260,035			—

Schedule of Amounts Recognized in Accumulated Other Comprehensive Income (Loss)

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

	Years Ended December 31,
	2016						2015
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Net loss	$	121,052		$	10,073		$	118,963		$	9,592
Prior service benefit	(23,877		)	(185		)	(27,344		)	(224		)
Total	$	97,175		$	9,888		$	91,619		$	9,368

Schedule of Net Periodic Benefit Costs

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

	Years Ended December 31,
	2016						2015						2014
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Service cost	$	7,705		$	296		$	8,530		$	262		$	8,284		$	303
Interest cost	12,161			878			13,477			1,018			14,001			1,041
Expected return on plan assets	(18,879		)	—			(19,795		)	—			(18,699		)	—
Amortization of:
Net loss	6,554			785			9,710			937			8,178			675
Prior service benefit	(3,467		)	(39		)	(3,467		)	(39		)	(2,889		)	(17		)
Net periodic benefit cost	$	4,074		$	1,920		$	8,455		$	2,178		$	8,875		$	2,002

Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss)

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

	Years Ended December 31,
	2016						2015						2014
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Net (gain) loss	$	8,644		$	1,266		$	4,266		$	(811	)	$	47,324		$	3,508
Prior service benefit	—			—			—			—			(33,700		)	(500		)
Amortization of:
Net loss	(6,554		)	(785		)	(9,710		)	(937		)	(8,178		)	(675		)
Prior service benefit	3,467			39			3,467			39			2,889			17
Total recognized in other comprehensive income	$	5,557		$	520		$	(1,977	)	$	(1,709	)	$	8,335		$	2,350

Schedule of Recognized Net Periodic Benefit Obligation and Other Comprehensive Income

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

	Years Ended December 31,
	2016				2015				2014
	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	$	9,631	$	2,440	$	6,478	$	469	$	17,210	$	4,352

Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year

The following are amounts in accumulated other comprehensive income that are expected to be recognized as components of net periodic benefit cost during 2017 (in thousands):

	Retirement Income Plan			Non-Qualified Retirement Plans
Net loss	$	7,530		$	825
Prior service benefit	(3,470		)	(40		)

Schedule of Allocation of Plan Assets

The Company’s target allocations for the plan’s assets are presented below:

	December 31, 2016
Equity securities	50	%
Fixed income	40	%
Alternative investments	10	%
Total	100	%

Fair Value, Measurement Inputs, Disclosure

The fair value of the Company’s Retirement Plan assets at December 31, 2016 and 2015, 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, 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	$	—	$	—

Description of Securities	Fair Value as of December 31, 2015		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Cash and Cash Equivalents	$	1,266	$	1,266	$	—	$	—
Common Collective Trusts (a)
Equity funds	144,279		144,279		—		—
Fixed income funds	103,877		103,877		—		—
Real Estate Funds	2,025		2,025		—		—
Total Common Collective Trusts	250,181		250,181		—		—
Limited Partnership Interest in Real Estate (b)(c)	8,588
Total Plan Investments	$	260,035	$	251,447	$	—	$	—

 _____________________

(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 guidance. 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. ASU 2015-07 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years.

Changes in Fair Value of Investments in Real Estate

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, 2014	$	8,748
Unrealized loss in fair value	(160		)
Balances at December 31, 2015	8,588
Sale of land	(775		)
Unrealized loss in fair value	(822		)
Balances at December 31, 2016	$	6,991

Schedule of Expected Benefit Payments

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
2017	$	16,113	$	2,698
2018	19,080		2,060
2019	18,771		2,025
2020	18,923		1,957
2021	19,755		1,907
2022-2026	107,916		8,949

Retirement Income Plan | Benefit Obligations

Defined Benefit Plan Disclosure [Line Items]

Schedule of Assumptions Used

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

	December 31,
	2016						2015
			Non-Qualified						Non-Qualified
	Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan		Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan
Discount rate	4.29	%	3.76	%	4.34	%	4.57	%	3.99	%	4.59	%
Rate of compensation increase	4.5	%	N/A		4.5	%	4.5	%	N/A		4.5	%

Retirement Income Plan | Net Periodic Benefit Costs

Defined Benefit Plan Disclosure [Line Items]

Schedule of Assumptions Used

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

	2016						2015						2014 (a)
			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	4.57	%	3.99	%	4.63	%	4.0	%	3.4	%	4.1	%	4.9	%	3.9	%	4.9	%
Service cost	4.83	%	N/A		4.87	%	4.0	%	N/A		4.1	%	4.9	%	N/A		4.9	%
Interest cost	3.86	%	3.04	%	3.9	%	4.0	%	3.4	%	4.1	%	4.9	%	3.9	%	4.9	%
Expected long-term return on plan assets	7.0	%	N/A		N/A		7.5	%	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	%	4.75	%	N/A		4.75	%

 _____________________

(a) The Retirement Plan and the Excess Benefit Plan were remeasured on February 28, 2014 due to the above mentioned plan amendment. The discount rate used to remeasure the benefit obligation was 4.6% for the Retirement Plan and 4.5% for the Excess Benefit Plan, compared to 4.9% for both plans as of January 1, 2014. All other assumptions remained consistent with assumptions used at January 1, 2014.

Other Postretirement Benefit Plan

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Funded Status

The following table contains a reconciliation of the change in the benefit obligation, the fair value of plan assets, and the funded status of the plan (in thousands):

	December 31,
	2016			2015
Change in benefit obligation:
Benefit obligation at end of prior year	$	92,643		$	100,700
Service cost	2,769			3,454
Interest cost	3,167			4,035
Actuarial loss (gain)	10,751			(11,423		)
Amendment (a) (b)	(32,697		)	(824		)
Benefits paid	(4,428		)	(4,544		)
Retiree contributions	1,310			1,245
Benefit obligation at end of year	73,515			92,643
Change in plan assets:
Fair value of plan assets at end of prior year	38,090			41,358
Actual return (loss) on plan assets	2,443			(469		)
Employer contribution	1,700			500
Benefits paid	(4,428		)	(4,544		)
Retiree contributions	1,310			1,245
Fair value of plan assets at end of year	39,115			38,090
Funded status at end of year	$	(34,400	)	$	(54,553	)

_____________________

(a) During October 2016, the Company approved and communicated a plan amendment that resulted in a remeasurement of the Company's 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 were covered by a fully insured Medicare advantage plan.

(b) Amendment relates to modification of the Company's Other Post-retirement Benefit Plan which increased mail order co-payments for post age 65. The amendment was approved in 2015 and became effective January 1, 2016.

Schedule of Amounts Recognized in Balance Sheet

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

	December 31,
	2016			2015
Current liabilities	$	—		$	—
Noncurrent liabilities	(34,400		)	(54,553		)
Total	$	(34,400	)	$	(54,553	)

Schedule of Amount Recognized in Accumulated Other Comprehensive Income (Loss)

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

	December 31,
	2016			2015
Net gain	$	(26,285	)	$	(38,802	)
Prior service benefit	(41,009		)	(12,213		)
Total	$	(67,294	)	$	(51,015	)

Schedule of Net Periodic Benefit Costs

Net periodic benefit cost is made up of the components listed below (in thousands):

	Years Ended December 31,
	2016			2015			2014
Service cost	$	2,769		$	3,454		$	2,845
Interest cost	3,167			4,035			4,463
Expected return on plan assets	(1,835		)	(2,070		)	(2,116		)
Amortization of:
Prior service benefit	(3,901		)	(3,068		)	(4,753		)
Net gain	(2,374		)	(2,025		)	(2,671		)
Net periodic benefit cost	$	(2,174	)	$	326		$	(2,232	)

Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss)

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

	Years Ended December 31,
	2016			2015			2014
Net (gain) loss	$	10,143		$	(8,884	)	$	3,496
Prior service benefit	(32,697		)	(824		)	—
Amortization of:
Prior service benefit	3,901			3,068			4,753
Net gain	2,374			2,025			2,671
Total recognized in other comprehensive income	$	(16,279	)	$	(4,615	)	$	10,920

Schedule of Recognized Net Periodic Benefit Obligation and Other Comprehensive Income

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

	Years Ended December 31,
	2016			2015			2014
Total recognized in net periodic benefit cost and other comprehensive income	$	(18,453	)	$	(4,289	)	$	8,688

Schedule of Allocation of Plan Assets

The Company’s target allocations for the plan’s assets are presented below:

	December 31, 2016
Equity securities	65	%
Fixed income	30	%
Alternative investments	5	%
Total	100	%

Fair Value, Measurement Inputs, Disclosure

The fair value of the Company’s Other Post-retirement Benefits Plan assets at December 31, 2016 and 2015, 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, 2016		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Institutional Funds (a)
Equity funds	$	26,133	$	26,133	$	—	$	—
Fixed income funds	11,671		11,671		—		—
Total Institutional Funds	37,804		37,804		—		—
Limited Partnership Interest in Real Estate (b) (c)	1,311
Total Plan Investments	$	39,115	$	37,804	$	—	$	—
Description of Securities	Fair Value as of December 31, 2015		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Institutional Funds (a)
Equity funds	$	24,881	$	24,881	$	—	$	—
Fixed income funds	11,599		11,599		—		—
Total Institutional Funds	36,480		36,480		—		—
Limited Partnership Interest in Real Estate (b) (c)	1,610
Total Plan Investments	$	38,090	$	36,480	$	—	$	—

 ___________________

(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.

(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 of 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 guidance. 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. ASU 2015-07 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years.

Changes in Fair Value of Investments in Real Estate

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

	Fair Value of Investments  in Real Estate
Balance at December 31, 2014	$	1,640
Unrealized loss in fair value	(30		)
Balance at December 31, 2015	1,610
Sale of land	(145		)
Unrealized loss in fair value	(154		)
Balance at December 31, 2016	$	1,311

Schedule of Expected Benefit Payments

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

2017	$	2,622
2018	2,880
2019	3,057
2020	3,320
2021	3,510
2022-2026	20,084

Other Postretirement Benefit Plan | Accrued Postretirement Benefit

Defined Benefit Plan Disclosure [Line Items]

Schedule of Assumptions Used

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

	December 31,
	2016		2015
Discount rate at end of year	4.36	%	4.59	%
Health care cost trend rates:
Initial
Pre-65 medical	6.50	%	7.00	%
Post-65 medical	4.50	%	7.00	%
Pre-65 drug	7.50	%	7.00	%
Post-65 drug	10.50	%	7.00	%
Ultimate	4.50	%	4.50	%
Year ultimate reached (a)	2026		2026

_____________________ (a) Pre-65 medical reaches the ultimate trend rate in 2025. Additionally, the Post-65 medical trend is assumed to be 4.50% for all years into the future.

Other Postretirement Benefit Plan | Net Periodic Benefit Costs

Defined Benefit Plan Disclosure [Line Items]

Schedule of Assumptions Used

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

	2016 (a)				2015		2014
Discount rate:	January 1 - September 30		October 1 - December 31
Benefit obligation	4.59	%	3.75	%	4.1	%	4.9	%
Service cost	4.91	%	4.03	%	4.1	%	4.9	%
Interest cost	3.86	%	3.15	%	4.1	%	4.9	%
Expected long-term return on plan assets	4.875%				5.2	%	5.2	%
Health care cost trend rates:
Initial	7.00%				7.25	%	7.5	%
Ultimate	4.5%				4.5	%	4.5	%
Year ultimate reached	2026				2026		2026

_____________________

(a) The actuarial assumptions are evaluated by the Company at each measurement date. The Other Post-retirement Benefits Plan was remeasured at October 1, 2016 due to a plan amendment.

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Financial Instruments And Investments (Tables)

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Fair Values Of Long-Term Debt And Short-Term Borrowings Under the RCF

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

	December 31,
	2016				2015
	Carrying Amount (1)		Estimated Fair Value		Carrying Amount (1)		Estimated Fair Value
Pollution Control Bonds	$	190,775	$	206,818	$	190,499	$	212,624
Senior Notes	993,086		1,112,285		837,475		829,864
RGRT Senior Notes (2)	94,795		98,855		94,686		100,345
RCF (2)	81,574		81,574		141,738		141,738
Total	$	1,360,230	$	1,499,532	$	1,264,398	$	1,284,571

 __________________

(1) The Company implemented ASU 2015-03, Interest - Imputation of Interest, which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The impact of ASU 2015-03 on the Company's Balance Sheet was to reclassify $11.6 million of other deferred charges to long-term debt, net of current portion at December 31, 2015.

(2) Nuclear fuel financing, as of December 31, 2016 and December 31, 2015, is funded through the $95 million RGRT Senior Notes and $37.6 million and $33.7 million, respectively under the RCF. As of December 31, 2016, $44.0 million was outstanding under the RCF for working capital or general corporate purposes. As of December 31, 2015, $108.0 million amount was outstanding under the RCF for working capital or general corporate purposes. The interest rate on the Company’s borrowings under the RCF is reset throughout the period reflecting current market rates. Consequently, the carrying value approximates fair value.

Unrecognized Gross Unrealized Gains (Losses) And the Fair Value

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

	December 31, 2016
	Less than 12 Months					12 Months or Longer					Total
	Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses
Description of Securities (1):
Federal Agency Mortgage Backed Securities	$	11,582	$	(239	)	$	436	$	(22	)	$	12,018	$	(261	)
U.S. Government Bonds	31,655		(762		)	17,976		(835		)	49,631		(1,597		)
Municipal Obligations	9,596		(394		)	4,067		(372		)	13,663		(766		)
Corporate Obligations	7,971		(172		)	2,092		(172		)	10,063		(344		)
Total Debt Securities	60,804		(1,567		)	24,571		(1,401		)	85,375		(2,968		)
Common Stock	2,760		(167		)	—		—			2,760		(167		)
Institutional Funds-International Equity	22,945		(110		)	—		—			22,945		(110		)
Total Temporarily Impaired Securities	$	86,509	$	(1,844	)	$	24,571	$	(1,401	)	$	111,080	$	(3,245	)

 ____________________

(1) Includes approximately 152 securities.

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

 ______________________

(2) Includes approximately 133 securities.

Unrealized Holding Losses Included In Pre-Tax Income

For the twelve months ended December 31, 2016, 2015, and 2014, the Company recognized other than temporary impairment losses on its available-for-sale securities as follows (in thousands):

	2016			2015			2014
Unrealized holding losses included in pre-tax income	$	(352	)	$	(338	)	$	—

Marketable Securities Fair Value and Unrecognized Gross Unrealized Gain

The table below presents the unrecognized gross unrealized gains and the fair value of these securities, aggregated by investment category (in thousands):

	December 31, 2016				December 31, 2015
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
Description of Securities:
Federal Agency Mortgage Backed Securities	$	7,430	$	319	$	9,589	$	438
U.S. Government Bonds	12,237		138		12,033		136
Municipal Obligations	2,481		144		8,671		332
Corporate Obligations	12,350		655		10,110		368
Total Debt Securities	34,498		1,256		40,403		1,274
Common Stock	61,884		34,066		72,636		37,001
Equity Mutual Funds	42,244		3,345		18,853		91
Cash and Cash Equivalents	6,002		—		8,204		—
Total	$	144,628	$	38,667	$	140,096	$	38,366

Contractual Year For Maturity Of Available-For-Sale Securities

The contractual year for maturity for these available-for-sale securities as of December 31, 2016 is as follows (in thousands):

	Total		2017		2018 through 2021		2022 through 2026		2027 and Beyond
Municipal Debt Obligations	$	16,144	$	990	$	6,253	$	8,139	$	762
Corporate Debt Obligations	22,413		—		8,664		6,090		7,659
U.S. Government Bonds	61,868		14,272		22,495		14,786		10,315
Federal Agency Mortgage Backed Securities	19,448		—		5		390		19,053

Sale of Securities And The Related Effects On Pre-Tax Income

The proceeds from the sale of these securities during the twelve months ended December 31, 2016, 2015, and 2014 and the related effects on pre-tax income are as follows (in thousands):

	2016			2015			2014
Proceeds from sales of available-for-sale securities	$	91,268		$	102,567		$	108,311
Gross realized gains included in pre-tax income	$	9,212		$	12,379		$	7,858
Gross realized losses included in pre-tax income	(1,220		)	(927		)	(508		)
Gross unrealized losses included in pre-tax income	(352		)	(338		)	—
Net gains in pre-tax income	$	7,640		$	11,114		$	7,350
Net unrealized holding gains (losses) included in accumulated other comprehensive income	$	8,444		$	(2,906	)	$	10,827
Net (gains) losses reclassified out of accumulated other comprehensive income	(7,640		)	(11,114		)	(7,350		)
Net gains (losses) in other comprehensive income	$	804		$	(14,020	)	$	3,477

Fair Value, Measurement Inputs, Disclosure

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

Description of Securities	Fair Value as  of December 31, 2016		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Trading Securities:
Investments in Debt Securities	$	1,421	$	—	$	—	$	1,421
Available for sale:
U.S. Government Bonds	$	61,868	$	61,868	$	—	$	—
Federal Agency Mortgage Backed Securities	19,448		—		19,448		—
Municipal Obligations	16,144		—		16,144		—
Corporate Obligations	22,413		—		22,413		—
Subtotal, Debt Securities	119,873		61,868		58,005		—
Common Stock	64,644		64,644		—		—
Equity Mutual Funds	42,244		42,244		—		—
Institutional Funds-International Equity	22,945		22,945		—		—
Cash and Cash Equivalents	6,002		6,002		—		—
Total available for sale	$	255,708	$	197,703	$	58,005	$	—

Description of Securities	Fair Value as  of December 31, 2015		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Trading Securities:
Investments in Debt Securities	$	1,543	$	—	$	—	$	1,543
Available for sale:
U.S. Government Bonds	$	50,399	$	50,399	$	—	$	—
Federal Agency Mortgage Backed Securities	20,085		—		20,085		—
Municipal Obligations	24,345		—		24,345		—
Corporate Obligations	18,475		—		18,475		—
Subtotal, Debt Securities	113,304		50,399		62,905		—
Common Stock	76,220		76,220		—		—
Equity Mutual Funds	18,853		18,853		—		—
Institutional Funds-International Equity	22,454		22,454		—		—
Cash and Cash Equivalents	8,204		8,204		—		—
Total available for sale	$	239,035	$	176,130	$	62,905	$	—

Trading Securities (and Certain Trading Assets)

Below is a reconciliation of the beginning and ending balance of the fair value of the investment in debt securities (in thousands):

	2016			2015
Balance at January 1	$	1,543		$	1,653
Net unrealized gains (losses) in fair value recognized in income (a)	(122		)	(110		)
Balance at December 31	$	1,421		$	1,543

_____________________

(a) These amounts are reflected in the Company's statements of operations as investment and interest income.

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Supplemental Statements of Cash Flows Disclosures (Tables)

12 Months Ended

Dec. 31, 2016

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

	Years Ended December 31,
	2016		2015			2014
	(In thousands)
Cash paid for:
Interest on long-term debt and borrowing under the revolving credit facility	$	69,990	$	62,297		$	54,792
Income taxes, net of refund	2,328		1,000			6,876
Non-cash investing and financing activities:
Sale of Interest in Four Corners Generating Station (a)	27,720		—			—
Changes in accrued plant additions	4,789		(6,660		)	7,314
Grants of restricted shares of common stock	1,236		1,567			3,025

(a) The Company sold its interest in Four Corners for approximately $32.0 million based on the book value as defined in the Purchase and Sale Agreement. The sales price was adjusted downward by $7.0 million and $19.5 million to reflect APS's affiliate assumption of the Company's obligation to pay for future plant decommissioning and mine reclamation expense, respectively. The sales price was also adjusted downward by approximately $1.3 million for closing adjustments and other assets and liabilities assumed by APS's affiliate. At the closing of the sale, the Company received approximately $4.2 million in cash, subject to post-closing adjustments.

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Selected Quarterly Financial Data (Unaudited) Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

The quarterly earnings per share amounts for a year will not add to the earnings per share for that year due to the weighting of shares used in calculating per share data.

	2016 Quarters									2015 Quarters
	4th		3rd (2)		2nd		1st			4th		3rd		2nd		1st
					(In thousands except for share data)
Operating revenues (1)	$	188,037	$	323,225	$	217,865	$	157,809		$	176,902	$	289,713	$	219,508	$	163,746
Operating income (loss)	20,470		129,857		44,697		(163		)	8,312		88,047		41,872		7,960
Net income (loss)	5,656		74,636		22,284		(5,808		)	648		56,740		21,072		3,458
Basic earnings per share:
Net income (loss)	0.14		1.84		0.55		(0.14		)	0.02		1.40		0.52		0.09
Diluted earnings per share:
Net income (loss)	0.14		1.84		0.55		(0.14		)	0.02		1.40		0.52		0.09
Dividends declared per share of common stock	0.310		0.310		0.310		0.295			0.295		0.295		0.295		0.280

 ________________

(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.

(2) For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2015 Texas Retail Rate Case until it received the PUCT Final Order on August 25, 2016. Accordingly, it reported in the third quarter of 2016 the cumulative effect of the PUCT Final Order which related back to January 12, 2016. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.

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Summary of Significant Accounting Policies (General) (Details)	Dec. 31, 2016 mi²
General [Abstract]
Area of Services, in Square Miles	10,000

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Summary of Significant Accounting Policies (Utility Plant) (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Significant Accounting Policies [Line Items]
Average composite depreciation rate	2.28%	2.64%	2.60%
AFUDC rate	6.43%	7.18%	8.15%
Minimum
Significant Accounting Policies [Line Items]
Public Utilities Property, Plant and Equipment, Useful Life	5 years
Maximum
Significant Accounting Policies [Line Items]
Public Utilities Property, Plant and Equipment, Useful Life	48 years

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Summary of Significant Accounting Policies (Revenues) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Accrued unbilled revenues	$ 21.0	$ 21.7

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Summary of Significant Accounting Policies (Allowance For Doubtful Accounts) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accounts Receivable, Net [Abstract]
Balance at beginning of year	$ 2,046	$ 2,253	$ 2,261
Additions:
Charged to costs and expense	2,427	2,057	2,755
Recovery of previous write-offs	1,395	1,613	1,516
Uncollectible receivables written off	3,712	3,877	4,279
Balance at end of year	$ 2,156	$ 2,046	$ 2,253

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New Accounting Standards Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jan. 01, 2017	Jan. 01, 2016
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Decrease in accumulated other comprehensive income	$ 7,116	$ 13,914
Increase in income tax expense	53,918	34,895	$ 41,088
Decrease in other comprehensive income	(6,798)	5,913	$ 10,613
Increase in operating loss carryforward deferred tax assets	60,749	$ 35,153
Potential Impact of Accounting Standards Update 2016-01
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Increase in retained earnings					$ 28,800
Decrease in accumulated other comprehensive income					$ 28,800
Increase in investment income	1,200
Increase in income tax expense	200
Decrease in other comprehensive income	$ 1,000
Subsequent Event | Potential Impact of Accounting Standards Update 2016-09
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Increase in retained earnings				$ 200
Increase in operating loss carryforward deferred tax assets				$ 200

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Regulation (Narrative) (Details) $ in Thousands															12 Months Ended
	Feb. 13, 2017 USD ($)	Jan. 10, 2017	Jan. 09, 2017 USD ($)	Oct. 28, 2016 USD ($)	Sep. 27, 2016 USD ($)	Aug. 25, 2016 USD ($)	Jul. 06, 2016 USD ($)	Jun. 08, 2016 USD ($)	Apr. 29, 2016 USD ($)	Mar. 24, 2016 USD ($)	Nov. 05, 2015 USD ($)	May 20, 2015	May 01, 2015 USD ($)	Dec. 01, 2014 USD ($)	Dec. 31, 2016 USD ($) MW	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Jan. 08, 2017 USD ($)	Sep. 30, 2016 USD ($)	Oct. 19, 2015 USD ($)	Oct. 07, 2015 USD ($)
Under-collection of fuel revenues															$ 11,123	$ 0
Over-collection of fuel revenues															255	4,023
Proceeds from issuance of senior notes															157,052	0	$ 149,468
Interest Payable, Current															$ 13,287	$ 12,649
Number of Presidential Permit(s)															2
Contract Termination Provision, Period															2 years
PUCT Docket No. 44633 | Fixed Fuel Factor
Increase (Decrease) in Fixed Fuel Factor, Percentage												(24.00%)
PUCT Docket No. 46308
Reconcilable Fuel Expense					$ 436,600
Fuel Reconciliation Period					36 months
NMPRC Case No. 15-00127-UT
Fuel Reconciliation Period								24 months
Four Corners Generating Station
Closing Date For Sale							Jul. 06, 2016
Mine Reclamation and Closing Liability, Noncurrent							$ 19,500
PUCT
Period To Relate Back New Rates															155 days
Public Utilities Requested Performance Incentive Bonus Related To Energy Efficiency Program									$ 700				$ 1,000
Public Utilities Approved Performance Incentive Bonus Related To Energy Efficiency Program				$ 500							$ 1,000
Public Utilities Requested Performance Incentive Bonus Related To Energy Efficiency Program Decrease, Amount				$ 200
Fuel Over And Under Materiality Threshold Percentage															4.00%
Under-collection of fuel revenues															$ 11,100
Reconcilable Fuel Expense															$ 114,400
PUCT | Montana Power Station Units 1 And 2
Property, Plant and Equipment, Operational Date															Mar. 20, 2015
PUCT | Montana Power Station Unit 3
Property, Plant and Equipment, Operational Date															May 03, 2016
PUCT | Montana Power Station Unit 4
Property, Plant and Equipment, Operational Date															Sep. 15, 2016
PUCT | Community Solar At Montana Power Station
Electric capacity | MW															3
PUCT | Four Corners Generating Station
Purchase and Sale Agreement, Execution Date															Feb. 17, 2015
PUCT | Minimum
Fixed Fuel Factor Revision Period, in Months															4 months
PUCT | Maximum
Surcharge Or Refund Period															18 months
PUCT | Public Utilities, Regulatory Rate Making Impact
Recovery of Rate Case Expenses, Amount						$ 3,100
Period To Relate Back New Rates						80 days
PUCT | Four Corners Generating Station
Closing Date For Sale															Jul. 06, 2016
Mine Reclamation and Closing Liability, Noncurrent															$ 7,300
PUCT | Four Corners Generating Station | Public Utilities, Regulatory Rate Making Impact | Non-Fuel Base Rate
Public Utilities, Approved Rate Increase (Decrease), Amount						$ 3,700
Regulatory Current Asset, End Date for Recovery						Jul. 12, 2017
NMPRC
Reconcilable Fuel Expense															$ 114,600
Fuel Reconciliation Period															24 months
Over-collection of fuel revenues															$ 200
Debt Instrument, Face Amount																					$ 310,000
NMPRC | Montana Power Station Units 1 And 2
Property, Plant and Equipment, Operational Date															Mar. 20, 2015
NMPRC | Montana Power Station Unit 3
Property, Plant and Equipment, Operational Date															May 03, 2016
NMPRC | Montana Power Station Unit 4
Property, Plant and Equipment, Operational Date															Sep. 15, 2016
NMPRC | Four Corners Generating Station
Purchase and Sale Agreement, Execution Date															Feb. 17, 2015
NMPRC | Holloman
Electric capacity | MW															5
NMPRC | Public Utilities, Regulatory Rate Making Impact
Public Utilities, Approved Return on Equity, Percentage								9.48%
NMPRC | Public Utilities, Regulatory Rate Making Impact | Non-Fuel Base Rate
Public Utilities, Approved Rate Increase (Decrease), Amount								$ 600
NMPRC | Public Utilities, Regulatory Rate Making Impact | Service cost
Public Utilities, Approved Rate Increase (Decrease), Amount								$ 500
FERC
Debt Instrument, Face Amount																				$ 310,000
Line of Credit Facility, Maximum Borrowing Capacity																				400,000
Debt Issuance Authorization Date Range Start															Nov. 15, 2015
Debt Issuance Authorization Date Range End															Nov. 15, 2017
FERC | Four Corners Generating Station
Closing Date For Sale															Jul. 06, 2016
Jointly Owned Utility Plant, Entire Ownership of Proportionate Interest, Percentage															100.00%
Subsequent Event
Line of Credit renewal term, year		1 year
Line of Credit Facility, Expiration Date		Jan. 14, 2021
Subsequent Event | PUCT Docket No. 46610 | Fixed Fuel Factor
Increase (Decrease) in Fixed Fuel Factor, Percentage		28.80%
Subsequent Event | PUCT | Non-Fuel Base Rate
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 42,500
Subsequent Event | FERC
Line of Credit renewal term, year		1 year
Line of Credit Facility, Expiration Date		Jan. 14, 2021
RGRT | NMPRC
Debt Instrument, Face Amount																					$ 65,000
RGRT | FERC
Debt Instrument, Face Amount																				$ 65,000
Revolving Credit Facility Expiring January 2020 | Subsequent Event
Line of Credit Facility, Maximum Borrowing Capacity			$ 400,000
Line of Credit renewal term, year			1 year
Line of Credit Facility, Expiration Date			Jan. 14, 2020
Line of Credit Facility, Increase (Decrease), Net			$ 50,000
Line of Credit Facility, Current Borrowing Capacity			350,000
Line of Credit Facility, Remaining Borrowing Capacity			50,000
Revolving Credit Facility Expiring January 2020 | Subsequent Event | FERC
Line of Credit Facility, Maximum Borrowing Capacity			$ 400,000
Line of Credit renewal term, year			1 year
Line of Credit Facility, Expiration Date			Jan. 14, 2020
Line of Credit Facility, Increase (Decrease), Net			$ 50,000
Line of Credit Facility, Current Borrowing Capacity			350,000
Line of Credit Facility, Remaining Borrowing Capacity			50,000
5.00% Senior Notes, Plus Premium, Due 2044 | NMPRC
Debt Instrument, Face Amount										$ 150,000
Debt Instrument, Issuance Date										Mar. 24, 2016
Debt Instrument, Interest Rate, Stated Percentage										5.00%
Debt Instrument, Maturity Date										Dec. 01, 2044
Proceeds from issuance of senior notes										$ 158,100
Interest Payable, Current										2,400
Debt Instrument, Unamortized Premium										7,100
5.00% Senior Notes, Plus Premium, Due 2044 | FERC
Debt Instrument, Face Amount										$ 150,000
Debt Instrument, Issuance Date										Mar. 24, 2016
Debt Instrument, Interest Rate, Stated Percentage										5.00%
Debt Instrument, Maturity Date										Dec. 01, 2044
5.00% Senior Notes, Net of Discount, due 2044 | NMPRC
Debt Instrument, Face Amount														$ 150,000
Debt Instrument, Issuance Date														Dec. 01, 2014
Debt Instrument, Interest Rate, Stated Percentage														5.00%
Debt Instrument, Maturity Date														Dec. 01, 2044
5.00% Senior Notes, Combined, Due 2044 | NMPRC
Debt Instrument, Face Amount																			$ 300,000
Letter of Credit | Revolving Credit Facility Expiring January 2020 | Subsequent Event | FERC | Maximum
Line of Credit Facility, Current Borrowing Capacity			$ 50,000															$ 350,000
Electric Generation Equipment | PUCT | Montana Power Station
Number of power generation units authorized to be constructed															4
Electric Generation Equipment | NMPRC | Montana Power Station
Number of power generation units authorized to be constructed															4

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Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets		$ 118,861	$ 115,127
Total regulatory liabilities		18,435	24,303
Regulatory tax assets or liabilities
Regulatory Assets and Liabilities [Line Items]
Total regulatory liabilities	[1],[2]	10,648	17,266
Accumulated deferred investment tax credit
Regulatory Assets and Liabilities [Line Items]
Total regulatory liabilities	[1],[3]	3,328	4,011
Texas energy efficiency
Regulatory Assets and Liabilities [Line Items]
Total regulatory liabilities	[4]	1,288	0
New Mexico energy efficiency
Regulatory Assets and Liabilities [Line Items]
Total regulatory liabilities	[4]	2,159	2,238
Texas military base discount and recovery factor
Regulatory Assets and Liabilities [Line Items]
Total regulatory liabilities	[5]	$ 184	788
New Mexico gain on sale of assets
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Amortization Period		3 years
Total regulatory liabilities	[6]	$ 828	0
Regulatory tax assets or liabilities
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	[1],[2]	66,670	69,359
Loss on reacquired debt
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	[7]	15,780	16,632
Final coal reclamation
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	[8],[9]	9,581	9,520
Nuclear fuel postload daily financing charge
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	[8]	3,831	4,195
Unrecovered issuance costs due to reissuance of PCBs
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	[7]	794	827
Texas energy efficiency
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	[4]	0	25
Texas 2015 rate case costs
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets		2,670	1,882
Texas 2017 rate case costs
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	[10]	246	0
Texas relate back surcharge
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	[11]	6,455	0
New Mexico renewable energy credits and related costs
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	[12]	6,937	6,397
New Mexico 2010 FPPCAC audit
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets		398	434
New Mexico Palo Verde deferred depreciation
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	[1]	4,415	4,568
New Mexico 2015 rate case costs
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets		1,074	1,288
New Mexico 2017 rate case costs
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	[10]	$ 10	$ 0

[1] The amortization periods for these assets and liabilities are based upon the life of the associated assets or liabilities.

[2] We do not earn a return on these items since the related accumulated deferred income tax assets and liabilities offset.

[3] This item is excluded from rate base.

[4] This item is recovered or credited through a recovery factor that is set annually.

[5] 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.

[6] This item relates to the gains on the sales of assets the Company shares with its New Mexico customers over a three year period.

[7] This item is recovered as a component of the weighted cost of debt and amortized over the life of the related debt issuance.

[8] This item is recovered through fuel recovery mechanisms established by tariffs.

[9] This item relates to coal reclamation costs associated with Four Corners. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.

[10] Amortization period is anticipated to be established in next general rate case.

[11] This item relates to the recovery of revenues through a separate surcharge beginning October 1, 2016 and ending September 30, 2017. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.

[12] This item relates to renewable energy credits and procurement plan costs, components approved for recovery in the New Mexico 2015 rate case.

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Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant (Depreciable Assets By Each Major Class) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment and Finite-Lived Intangible Assets [Line Items]
Gross Plant	$ 3,791,566	$ 3,616,301
Accumulated Depreciation	(1,244,332)	(1,329,843)
Property, Plant and Equipment, Net	2,547,234	$ 2,286,458
Intangible
Property, Plant and Equipment and Finite-Lived Intangible Assets [Line Items]
Gross Plant	84,342
Accumulated Depreciation	(55,464)
Property, Plant and Equipment, Net	28,878
Nuclear production | Energy Equipment
Property, Plant and Equipment and Finite-Lived Intangible Assets [Line Items]
Gross Plant	948,382
Accumulated Depreciation	(320,000)
Property, Plant and Equipment, Net	628,382
Steam and other | Energy Equipment
Property, Plant and Equipment and Finite-Lived Intangible Assets [Line Items]
Gross Plant	926,419
Accumulated Depreciation	(186,539)
Property, Plant and Equipment, Net	739,880
Total production | Energy Equipment
Property, Plant and Equipment and Finite-Lived Intangible Assets [Line Items]
Gross Plant	1,874,801
Accumulated Depreciation	(506,539)
Property, Plant and Equipment, Net	1,368,262
Transmission | Energy Equipment
Property, Plant and Equipment and Finite-Lived Intangible Assets [Line Items]
Gross Plant	498,660
Accumulated Depreciation	(259,488)
Property, Plant and Equipment, Net	239,172
Distribution | Energy Equipment
Property, Plant and Equipment and Finite-Lived Intangible Assets [Line Items]
Gross Plant	1,127,897
Accumulated Depreciation	(365,601)
Property, Plant and Equipment, Net	762,296
General | Energy Equipment
Property, Plant and Equipment and Finite-Lived Intangible Assets [Line Items]
Gross Plant	205,866
Accumulated Depreciation	(57,240)
Property, Plant and Equipment, Net	$ 148,626

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Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant (Amortization of Intangible Plant Assets - Software) (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment and Finite-Lived Intangible Assets [Line Items]
Number of years amortization expense prior reporting year		3 years
Number of years amortization expense after reporting year		5 years
Intangible Plant Software
Property, Plant and Equipment and Finite-Lived Intangible Assets [Line Items]
Decrease in depreciation expense	$ 1,800
Finite-Lived Intangible Assets, Amortization Expense		$ 5,302	$ 6,482	$ 8,051
Future Amortization Expense, 2017 (estimated)		5,148
Future Amortization Expense, 2018 (estimated)		4,631
Future Amortization Expense, 2019 (estimated)		4,242
Future Amortization Expense, 2020 (estimated)		3,808
Future Amortization Expense, 2021 (estimated)		$ 3,227
Intangible Plant Software | Minimum
Property, Plant and Equipment and Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Useful Life		3 years
Intangible Plant Software | Maximum
Property, Plant and Equipment and Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Useful Life		15 years

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Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant (Summary of Jointly Owned Utility Plants) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016 USD ($) utilityplantunit	Jul. 06, 2016	Dec. 31, 2015 USD ($)
Palo Verde Generating Station
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	15.80%
Jointly Owned Utility Plant, Number of Units | utilityplantunit	3
Palo Verde Participants
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Plant, Number of Participants	6
Four Corners Generating Station
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share		7.00%
Other Jointly Owned Utlity Plant
Jointly Owned Utility Plant Interests [Line Items]
Electric plant in service	$ 67,621		$ 229,627
Accumulated depreciation	(44,377)		(181,886)
Construction work in progress	1,895		9,528
Total	25,139		57,269
Palo Verde | Jointly Owned Nuclear Power Plant
Jointly Owned Utility Plant Interests [Line Items]
Electric plant in service	948,382		917,483
Accumulated depreciation	(320,000)		(304,060)
Construction work in progress	50,598		48,938
Total	$ 678,980		$ 662,361

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Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant (Narrative) (Details) $ in Thousands											12 Months Ended
	Oct. 31, 2016 USD ($)	Jul. 06, 2016 USD ($)	Mar. 31, 2016 USD ($)	Nov. 02, 2015 USD ($)	Jun. 01, 2015 USD ($)	Oct. 31, 2014 USD ($)	Oct. 08, 2014 USD ($)	Aug. 18, 2014 USD ($)	Mar. 31, 2013 USD ($)	Dec. 19, 2012	Dec. 31, 2016 USD ($) utilityplantunit	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Apr. 21, 2011
Jointly Owned Utility Plant Interests [Line Items]
Proceeds from sale of property, plant, and equipment											$ 4,841	$ 721	$ 2,395
Decommissioning Fund Investments											$ 255,708	239,035
Third Party Decommission Cost Estimates Study Period, in Years											3 years
Estimated Decommissioning Costs									$ 380,700
Decommission cost increase									$ 23,300
Asset Retirement Obligation, Revision of Estimate											$ 0	0	3,561
Required period in years participants need a new decommissioning study											3 years
Retrospective Premium Adjustments Due to Nuclear Facility Losses											$ 12,900
Asset Retirement Obligation											81,800	81,621	74,577	$ 65,214
Refund passed through to customers											$ (14,891)	$ 13,344	$ (3,121)
Four Corners Generating Station
Jointly Owned Utility Plant Interests [Line Items]
Proceeds from sale of property, plant, and equipment		$ 4,200
Jointly Owned Utility Plant, Proportionate Ownership Share		7.00%
Property, Plant and Equipment, Disposals		$ 32,000
Disposal Date		Jul. 06, 2016
Asset Retirement Obligation		$ 7,000
Mine Reclamation and Closing Liability, Noncurrent		19,500
Public Utilities, Property, Plant and Equipment, Amount of Disposal Adjustments		$ 1,300
Palo Verde Generating Station
Jointly Owned Utility Plant Interests [Line Items]
Number Of Power Generation Units											3
Number of Units With Renewed Operating Licenses															3
Asset Retirement Obligation, Revision of Estimate														$ 1,900
Maximum Assesment Per Reactor Nuclear Energy Incident											$ 60,400
Maximum Assesment Per Reactor Nuclear Energy Incident Annual Limit											$ 9,000
Jointly Owned Utility Plant, Proportionate Ownership Share											15.80%
Jointly Owned Utility Plant, Number of Units | utilityplantunit											3
Palo Verde Participants
Jointly Owned Utility Plant Interests [Line Items]
Nuclear Energy Hazards Full Limit Of Liability Under Federal Law											$ 13,400,000
Nuclear Energy Hazards Potential Liability											450,000
Maximum Assesment Per Reactor Nuclear Energy Incident											127,300
Maximum Assesment Per Reactor Nuclear Energy Incident Annual Limit											19,000
Aggregate Amount of Insurance for Decontamination and Property Damage											2,750,000
Suit Against Department of Energy for Spent Fuel
Jointly Owned Utility Plant Interests [Line Items]
Settlement Agreement, Counterparty's Name										United States Department of Energy
Lawsuit Filing Date	October 31, 2016			November 2, 2015		October 31, 2014				December 19, 2012
Loss Contingency, Settlement Agreement, Date								August 18, 2014
Suit Against Department of Energy for Spent Fuel | Palo Verde Generating Station
Jointly Owned Utility Plant Interests [Line Items]
Settlement Agreement Award Received, Date					Jun. 01, 2015		Oct. 08, 2014
Settlement, Amount			$ 1,900		$ 6,600		$ 9,100
Litigation, Claim Amount	$ 1,800
Refund passed through to customers			$ 1,600		$ 5,800		$ 7,900
Suit Against Department of Energy for Spent Fuel | Palo Verde Participants
Jointly Owned Utility Plant Interests [Line Items]
Settlement, Amount	$ 11,300			$ 12,000		$ 42,000		$ 57,400
Minimum | Suit Against Department of Energy for Spent Fuel
Jointly Owned Utility Plant Interests [Line Items]
Litigation, Period Covered	July 1, 2015			Jul. 01, 2014		Jul. 01, 2011				Jan. 01, 2007
Maximum | Suit Against Department of Energy for Spent Fuel
Jointly Owned Utility Plant Interests [Line Items]
Litigation, Period Covered	June 30, 2016			Jun. 30, 2015		Jun. 30, 2014				Jun. 30, 2011
Limited amount of coverage | Palo Verde Participants
Jointly Owned Utility Plant Interests [Line Items]
Aggregate Amount of Insurance for Decontamination and Property Damage											$ 2,250,000
PUCT | Four Corners Generating Station
Jointly Owned Utility Plant Interests [Line Items]
Disposal Date											Jul. 06, 2016
Mine Reclamation and Closing Liability, Noncurrent											$ 7,300
Public Utilities, Regulatory Rate Making Impact
Jointly Owned Utility Plant Interests [Line Items]
Decrease in depreciation expense											$ 10,900

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Accounting for Asset Retirement Obligations (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Accounting For Asset Retirement Obligations [Line Items]
Number of External Trust Funds with Independent Trustee with Legal Restrictions To Settling ARO	6
Decommissioning Fund Investments	$ 255,708	$ 239,035

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Accounting for Asset Retirement Obligations (Changes in Estimated Probabilities Assumptions) (Details)	12 Months Ended
	Dec. 31, 2016
Original ARO Liability [Member]
Accounting For Asset Retirement Obligations [Line Items]
Escalation Rate	3.60%
Credit-Risk Adjusted Discount Rate	9.50%
Incremental ARO Liability [Member]
Accounting For Asset Retirement Obligations [Line Items]
Escalation Rate	3.60%
Credit-Risk Adjusted Discount Rate	6.20%

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Accounting for Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis
ARO liability at beginning of year	$ 81,621	$ 74,577	$ 65,214
Liabilities incurred	0	189	0
Liabilities settled	(6,993)	0	0
Revisions to estimate	0	0	3,561
Accretion expense	7,172	6,855	5,802
ARO liability at end of year	$ 81,800	$ 81,621	$ 74,577

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Common Stock (Details) - USD ($) $ / shares in Units, $ in Thousands					3 Months Ended									12 Months Ended
	Mar. 31, 2017	Mar. 17, 2017	Jan. 26, 2017	Dec. 30, 2016	Dec. 31, 2016	Sep. 30, 2016	[1]	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	May 29, 2014
Common Stock [Line Items]
Dividends, Common Stock, Cash				$ 12,600										$ 49,603	$ 47,059	$ 44,556
Common Stock, Dividends, Per Share, Declared					$ 0.310	$ 0.310		$ 0.310	$ 0.295	$ 0.295	$ 0.295	$ 0.295	$ 0.280	$ 1.225	$ 1.165	$ 1.105
Common Stock, Par or Stated Value Per Share					$ 1					$ 1				$ 1	$ 1
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized																	1,700,000.0
Restricted Stock | Minimum
Common Stock [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Requisite Service Period														1 year
Restricted Stock | Maximum
Common Stock [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Requisite Service Period														3 years
Scenario, Forecast
Common Stock [Line Items]
Dividends Payable, Date to be Paid	Mar. 31, 2017
Dividends Payable, Date of Record		Mar. 17, 2017
Subsequent Event
Common Stock [Line Items]
Dividends Payable, Date Declared			Jan. 26, 2017
Common Stock, Dividends, Per Share, Declared			$ 0.31

[1] For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2015 Texas Retail Rate Case until it received the PUCT Final Order on August 25, 2016. Accordingly, it reported in the third quarter of 2016 the cumulative effect of the PUCT Final Order which related back to January 12, 2016. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.

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Common Stock (Schedule of Restricted Stock Tax Expense and Deferred Tax) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Capitalized costs related to restricted stock award expense		$ 300	$ 300	$ 300
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expense	[1]	2,594	2,755	3,471
Deferred tax benefit		908	964	1,215
Current tax benefit recognized		$ 183	$ 43	$ 39

[1] Any capitalized costs related to these expenses is less than $0.3 million for all years.

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Common Stock (Vested Restricted Stock Aggregate Intrinsic Value And Grant Date Fair Value) (Details) - Restricted Stock - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted shares vested - aggregated intrinsic value	$ 2,515	$ 3,451	$ 3,441
Fair value at grant date	$ 1,993	$ 3,327	$ 3,330

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Common Stock (Schedule of Restricted Stock) (Details) - USD ($) $ / shares in Units, $ in Thousands			12 Months Ended
		May 29, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Share Price		$ 37.81
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Share based compensation, outstanding at beginning of period, in shares		13,863	91,210
Shares awards, number of shares awarded in period		13,863	74,181
Total vested, in shares		(13,863)	(55,503)
Total forfeitures, in shares		(13,863)	(495)
Share based compensation, outstanding at end of period, in shares			109,393	91,210
Shares outstanding, weighted average grant date fair value,beginning of period			$ 36.61
Weighted average fair value per share			40.95	$ 37.17	$ 36.95
Weighted average fair value vested			35.91
Weighted average fair value forfeitures			36.88
Shares outstanding, weighted average grant date fair value, end of period			$ 39.90	$ 36.61
Unrecognized Compensation Expense at end of period	[1]		$ 1,767
Aggregated intrinsic value for shares outstanding at end of period			$ 5,087
Unrecognized compensation expense, period for recognition			1 year

[1] 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.

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Common Stock (Weighted Average Fair Value Per Share) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average fair value per share	$ 40.95	$ 37.17	$ 36.95

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Common Stock (Performance Shares) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016 USD ($) shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
The Number of Simulations on Fair Value of Average Payout	1,000,000
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Shares Payout Level	0.00%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Shares Payout Level	200.00%
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based payment award on performance, performance evaluation period	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Method Used	Monte Carlo simulation
Performance Shares Payout Level	100.00%
Performance Shares | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares vested - Performance Shares Awarded | shares	206,898
January 25, 2017 | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares vested - Payout Ratio	32.00%
Performance shares vested - Performance Shares Awarded | shares	11,314
Performance shares vested - Compensation Costs Expensed	$ 932
Performance shares vested - aggregated intrinsic value	$ 512
January 27, 2016 | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares vested - Payout Ratio	0.00%
Performance shares vested - Performance Shares Awarded | shares	0
Performance shares vested - Compensation Costs Expensed	$ 851
Performance shares vested - aggregated intrinsic value	$ 0
February 20, 2015 | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares vested - Payout Ratio	0.00%
Performance shares vested - Performance Shares Awarded | shares	0
Performance shares vested - Compensation Costs Expensed	$ 1,502
Performance shares vested - aggregated intrinsic value	$ 0
February 18, 2014 | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares vested - Payout Ratio	0.00%
Performance shares vested - Performance Shares Awarded | shares	0
Performance shares vested - Compensation Costs Expensed	$ 954
Performance shares vested - aggregated intrinsic value	$ 0

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Common Stock (Outstanding Performance Share Awards) (Details) - USD ($) $ / shares in Units, $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Shares Payout Level		100.00%
Share based compensation, outstanding at beginning of period, in shares	[1]	130,136
Shares awards, number of shares awarded in period		60,835
Performance shares awards, number of shares expired in period		(24,527)
Share based compensation, outstanding at end of period, in shares	[1]	166,444	130,136
Shares outstanding, weighted average grant date fair value,beginning of period	[1]	$ 32.72
Performance shares awards, Weighted Average Grant Date Fair Value		38.11	$ 35.72	$ 26.36
Performance shares expired, weighted average grant date fair value		34.69
Shares outstanding, weighted average grant date fair value, end of period	[1]	$ 34.40	$ 32.72
Unrecognized Compensation Expense at end of period	[1],[2]	$ 2,189
Aggregated intrinsic value for shares outstanding at end of period	[1]	$ 7,740
Unrecognized compensation expense, period for recognition		1 year
Restricted Stock with a Performance Condition [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awards, number of shares awarded in period			27,624
Share-based Compensation Arrangement by Share-based Payment Award, Award Requisite Service Period			5 years

[1] On December 15, 2015, the Company issued a stock based retention grant to the Chief Executive Officer (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.

[2] 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.

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Common Stock (Performance Share Summary) (Details) - Performance Shares - USD ($) $ / shares in Units, $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average per share grant date fair value per share of performance shares awarded		$ 38.11	$ 35.72	$ 26.36
Compensation expense	[1],[2]	$ 1,655	$ 1,042	$ 1,181
Deferred tax benefit related to compensation expense	[1]	$ 579	$ 365	$ 413

[1] Includes CEO retention grant.

[2] Includes adjustments for estimated forfeitures.

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Common Stock (Common Stock Repurchase Program) (Details) $ in Thousands	12 Months Ended	216 Months Ended
	Dec. 31, 2016 shares	Dec. 31, 2016 USD ($) shares
Equity, Class of Treasury Stock [Line Items]
Shares repurchased	0	25,406,184	[1],[2]
Cost, including commission | $		$ 423,647	[1]
Total remaining shares available for repurchase at December 31, 2016	393,816	393,816
Treasury shares acquired outside of repurchase programs		86,735
Stock Issued During Period, Shares, Treasury Stock Reissued	188,005

[1] Represents repurchased shares and cost since inception of the stock repurchase program in 1999.

[2] 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 188,005 shares out of treasury stock during 2016.

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Common Stock (Basic and Diluted Earnings Per Share) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended									12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	[1]	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Class of Stock Disclosures [Abstract]
Basic number of common shares outstanding										40,350,688	40,274,986	40,190,991
Dilutive effect of unvested performance awards										57,345	33,576	20,726
Diluted number of common shares outstanding										40,408,033	40,308,562	40,211,717
Net income	$ 5,656	$ 74,636		$ 22,284	$ (5,808)	$ 648	$ 56,740	$ 21,072	$ 3,458	$ 96,768	$ 81,918	$ 91,428
Income allocated to participating restricted stock										(321)	(243)	(301)
Net income available to common shareholders basic										96,447	81,675	91,127
Income reallocated to participating restricted stock										(321)	(243)	(301)
Net income available to common shareholders diluted										$ 96,447	$ 81,675	$ 91,127
Earnings Per Share, Basic, Distributed										$ 1.225	$ 1.165	$ 1.105
Earnings Per Share, Basic, Undistributed										1.165	0.865	1.165
Basic net income per common share	$ 0.14	$ 1.84		$ 0.55	$ (0.14)	$ 0.02	$ 1.40	$ 0.52	$ 0.09	2.390	2.030	2.270
Earnings Per Share, Diluted, Distributed										1.225	1.165	1.105
Earnings Per Share, Diluted, Undistributed										1.165	0.865	1.165
Diluted net income per common share	$ 0.14	$ 1.84		$ 0.55	$ (0.14)	$ 0.02	$ 1.40	$ 0.52	$ 0.09	$ 2.390	$ 2.030	$ 2.270

[1] For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2015 Texas Retail Rate Case until it received the PUCT Final Order on August 25, 2016. Accordingly, it reported in the third quarter of 2016 the cumulative effect of the PUCT Final Order which related back to January 12, 2016. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.

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Common Stock (Antidilutive Shares) (Details) - shares		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Restricted Stock
Common Stock [Line Items]
Antidilutive Securities Excluded from Computation of Diluted Earnings Per Share, Amount		53,703	56,375	60,455
Performance Shares
Common Stock [Line Items]
Performance Shares Payout Level		100.00%	100.00%	100.00%
Antidilutive Securities Excluded from Computation of Diluted Earnings Per Share, Amount	[1]	47,246	66,804	96,208
Performance shares payout based upon performance		0	0	0

[1] 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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Accumulated Other Comprehensive Income by Component (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), beginning balance	$ (13,914)
Accumulated Other Comprehensive Income (Loss), ending balance	(7,116)	$ (13,914)
Accumulated Defined Benefit Plans Adjustment
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), beginning balance	(29,869)	(34,884)	$ (21,330)
Other Comprehensive Income (Loss) before Reclassifications	7,363	3,777	(12,628)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(1,422)	1,238	(926)
Accumulated Other Comprehensive Income (Loss), ending balance	(23,928)	(29,869)	(34,884)
Accumulated Net Unrealized Investment Gain (Loss)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), beginning balance	27,765	38,957	36,240
Other Comprehensive Income (Loss) before Reclassifications	6,904	(2,255)	8,694
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(6,206)	(8,937)	(5,977)
Accumulated Other Comprehensive Income (Loss), ending balance	28,463	27,765	38,957
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), beginning balance	(11,810)	(12,074)	(12,298)
Other Comprehensive Income (Loss) before Reclassifications	0	0	0
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	159	264	224
Accumulated Other Comprehensive Income (Loss), ending balance	(11,651)	(11,810)	(12,074)
Accumulated Other Comprehensive Income (Loss), Net of Tax
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), beginning balance	(13,914)	(8,001)	2,612
Other Comprehensive Income (Loss) before Reclassifications	14,267	1,522	(3,934)
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss)	(7,469)	(7,435)	(6,679)
Accumulated Other Comprehensive Income (Loss), ending balance	$ (7,116)	$ (13,914)	$ (8,001)

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Accumulated Other Comprehensive Income Amounts Reclassified (Details) - USD ($) $ in Thousands		3 Months Ended									12 Months Ended
		Dec. 31, 2016	Sep. 30, 2016	[1]	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss) [Line Items]
Income (Loss) before income tax											$ 150,686	$ 116,813	$ 132,516
Income tax expense											(53,918)	(34,895)	(41,088)
Net (Income) Loss		$ 5,656	$ 74,636		$ 22,284	$ (5,808)	$ 648	$ 56,740	$ 21,072	$ 3,458	96,768	81,918	91,428
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Attributable to Parent
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	[2]										7,407	6,574	7,659
Accumulated Defined Benefit Plans Adjustment, Net Gain (Loss) Attributable to Parent
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	[2]										(4,965)	(8,622)	(6,182)
Accumulated Defined Benefit Plans Adjustment
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax	[2]										2,442	(2,048)	1,477
Reclassification from AOCI, Current Period, Tax											(1,020)	810	(551)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax											1,422	(1,238)	926
Accumulated Net Unrealized Investment Gain (Loss)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax											6,206	8,937	5,977
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax											(159)	(264)	(224)
Reclassification out of Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax											(7,469)	(7,435)	(6,679)
Reclassification out of Accumulated Other Comprehensive Income | Accumulated Net Unrealized Investment Gain (Loss)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Net realized gain on sale of securities											7,640	11,114	7,350
Income (Loss) before income tax											7,640	11,114	7,350
Income tax expense											(1,434)	(2,177)	(1,373)
Net (Income) Loss											6,206	8,937	5,977
Reclassification out of Accumulated Other Comprehensive Income | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Income (Loss) before income tax											(498)	(467)	(438)
Income tax expense											339	203	214
Net (Income) Loss											(159)	(264)	(224)
Interest Rate Contract | Reclassification out of Accumulated Other Comprehensive Income | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Interest on long-term debt and revolving credit facility											$ (498)	$ (467)	$ (438)

[1] For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2015 Texas Retail Rate Case until it received the PUCT Final Order on August 25, 2016. Accordingly, it reported in the third quarter of 2016 the cumulative effect of the PUCT Final Order which related back to January 12, 2016. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.

[2] 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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Long-Term Debt and Financing Obligations Outstanding Balance (Details) $ in Thousands															1 Months Ended	12 Months Ended
		Jan. 10, 2017	Jan. 09, 2017 USD ($)	Dec. 31, 2016 USD ($)	Mar. 24, 2016 USD ($)	Dec. 31, 2015 USD ($)		Aug. 15, 2015 USD ($)	Dec. 01, 2014 USD ($)	Dec. 06, 2012 USD ($)	Aug. 31, 2010 USD ($)	Aug. 18, 2010 USD ($)	Jun. 02, 2008	May 02, 2005	Jun. 29, 2008 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)		Dec. 31, 2014 USD ($)	Aug. 28, 2012	Jun. 01, 2008 USD ($)	May 01, 2005 USD ($)
Debt Instrument [Line Items]
Long-term Debt				$ 1,360,230		$ 1,264,398	[1]									$ 1,360,230	$ 1,264,398	[1]
Long-term Debt, Current Maturities				(83,143)		0	[1]									(83,143)	0	[1]
Line of Credit, Current				(81,574)		(141,738)	[1]									(81,574)	(141,738)	[1]
Long-term debt, net of current portion				1,195,513		1,122,660	[1]									1,195,513	1,122,660	[1]
Proceeds from issuance of senior notes																157,052	0		$ 149,468
Interest accrued				13,287		12,649										13,287	12,649
Nuclear Fuel Financing
Debt Instrument [Line Items]
Long-term Line of Credit				37,600		33,700										37,600	33,700
Working Capital and General Purpose
Debt Instrument [Line Items]
Long-term Line of Credit				44,000		108,000										44,000	108,000
Short Term Borrowing
Debt Instrument [Line Items]
Repayments of Short-term Debt															$ 44,000
Revolving Credit Facility
Debt Instrument [Line Items]
Long-term Line of Credit				$ 81,574												$ 81,574
Line of Credit Weighted Average Interest Rate				2.00%												2.00%
Revolving Credit Facility | Nuclear Fuel Financing
Debt Instrument [Line Items]
Long-term Line of Credit				$ 37,600												$ 37,600
Revolving Credit Facility | Working Capital and General Purpose
Debt Instrument [Line Items]
Long-term Line of Credit				$ 44,000												44,000
Revolving Credit Facility Expiring January 2019
Debt Instrument [Line Items]
Line of Credit Facility, Expiration Date				Jan. 14, 2019
Line of Credit Facility, Current Borrowing Capacity				$ 300,000												300,000
Line of Credit Facility, Remaining Borrowing Capacity				100,000												100,000
Bonds and Notes
Debt Instrument [Line Items]
Long-term Debt				1,278,656		1,122,660	[1]									1,278,656	1,122,660	[1]
Pollution Control Bonds
Debt Instrument [Line Items]
Long-term Debt	[2]			$ 190,775		190,499	[1]									$ 190,775	190,499	[1]
Number of tax exempt bond series				4												4
Debt Instrument, Face Amount				$ 193,100												$ 193,100
Pollution Control Bonds | 7.25% 2009 Series A Refunding Bonds, due 2040
Debt Instrument [Line Items]
Long-term Debt	[2]			$ 62,619		$ 62,582	[1]									$ 62,619	$ 62,582	[1]
Debt Instrument, Interest Rate, Stated Percentage				7.25%		7.25%										7.25%	7.25%
Debt Instrument, Interest Rate, Effective Percentage				7.46%		7.46%										7.46%	7.46%
Debt Instrument, Maturity Date				Feb. 01, 2040		Feb. 01, 2040
Pollution Control Bonds | 4.50% 2012 Series A Refunding Bonds, due 2042
Debt Instrument [Line Items]
Long-term Debt	[2]			$ 58,471		$ 58,441	[1]									$ 58,471	$ 58,441	[1]
Debt Instrument, Interest Rate, Stated Percentage				4.50%		4.50%										4.50%	4.50%
Debt Instrument, Interest Rate, Effective Percentage				4.63%		4.63%										4.63%	4.63%
Debt Instrument, Maturity Date				Aug. 01, 2042		Aug. 01, 2042
Pollution Control Bonds | 7.25% 2009 Series B Refunding Bonds, due 2040
Debt Instrument [Line Items]
Long-term Debt	[2]			$ 36,492		$ 36,465	[1]									$ 36,492	$ 36,465	[1]
Debt Instrument, Interest Rate, Stated Percentage				7.25%		7.25%										7.25%	7.25%
Debt Instrument, Interest Rate, Effective Percentage				7.49%		7.49%										7.49%	7.49%
Debt Instrument, Maturity Date				Apr. 01, 2040		Apr. 01, 2040
Pollution Control Bonds | 1.875% 2012 Series A Refunding Bonds, due 2032
Debt Instrument [Line Items]
Long-term Debt	[2]			$ 33,193		$ 33,011	[1]									$ 33,193	$ 33,011	[1]
Debt Instrument, Interest Rate, Stated Percentage				1.875%		1.875%										1.875%	1.875%			1.875%
Debt Instrument, Interest Rate, Effective Percentage				2.35%		2.35%										2.35%	2.35%
Debt Instrument, Maturity Date				Jun. 01, 2032		Jun. 01, 2032
Debt Instrument Remarketed Date, Year				Sep. 30, 2017
Debt Instrument, Face Amount				$ 33,300												$ 33,300
Senior Notes
Debt Instrument [Line Items]
Long-term Debt	[3]			993,086		$ 837,475	[1]									993,086	$ 837,475	[1]
Senior Notes | 6.00% Senior Notes, Net of Discount, due 2035
Debt Instrument [Line Items]
Long-term Debt	[3]			$ 393,861		$ 393,693	[1]									$ 393,861	$ 393,693	[1]
Debt Instrument, Interest Rate, Stated Percentage				6.00%		6.00%										6.00%	6.00%					6.00%
Debt Instrument, Interest Rate, Effective Percentage				7.12%		7.12%										7.12%	7.12%
Debt Instrument, Maturity Date				May 15, 2035		May 15, 2035
Debt Instrument, Face Amount																						$ 400,000
Debt Instrument, Issuance Date														May 01, 2005
Debt Instrument, Unamortized Discount																						$ 2,300
Senior Notes | 7.50% Senior Notes, Net of Discount, due 2038
Debt Instrument [Line Items]
Long-term Debt	[3]			$ 147,331		$ 147,282	[1]									$ 147,331	$ 147,282	[1]
Debt Instrument, Interest Rate, Stated Percentage				7.50%		7.50%										7.50%	7.50%				7.50%
Debt Instrument, Interest Rate, Effective Percentage				7.67%		7.67%										7.67%	7.67%
Debt Instrument, Maturity Date				Mar. 15, 2038		Mar. 15, 2038
Debt Instrument, Face Amount																					$ 150,000
Debt Instrument, Issuance Date													Jun. 01, 2008
Debt Instrument, Unamortized Discount																					$ 1,300
Senior Notes | 3.30% Senior Notes, Net of Discount, due 2022
Debt Instrument [Line Items]
Long-term Debt	[3]			$ 148,939		$ 148,783	[1]									$ 148,939	$ 148,783	[1]
Debt Instrument, Interest Rate, Stated Percentage				3.30%		3.30%				3.30%						3.30%	3.30%
Debt Instrument, Interest Rate, Effective Percentage				3.43%		3.43%										3.43%	3.43%
Debt Instrument, Maturity Date				Dec. 15, 2022		Dec. 15, 2022
Debt Instrument, Face Amount										$ 150,000
Debt Instrument, Issuance Date										Dec. 01, 2012
Debt Instrument, Unamortized Discount										$ 300
Senior Notes | 5.00% Senior Notes, Net of Discount, due 2044
Debt Instrument [Line Items]
Long-term Debt	[3]			$ 302,955		$ 147,717	[1]									$ 302,955	$ 147,717	[1]
Debt Instrument, Interest Rate, Stated Percentage				5.00%	5.00%	5.00%										5.00%	5.00%
Debt Instrument, Interest Rate, Effective Percentage				4.93%		4.93%										4.93%	4.93%
Debt Instrument, Maturity Date				Dec. 01, 2044	Dec. 01, 2044	Dec. 01, 2044
Debt Instrument, Face Amount				$ 300,000	$ 150,000				$ 150,000							$ 300,000
Proceeds from issuance of senior notes					158,100
Interest accrued					2,400
Debt Instrument, Unamortized Premium					$ 7,100
Debt Instrument, Issuance Date					Mar. 24, 2016				Dec. 01, 2014
Debt Instrument, Unamortized Discount									$ 500
RGRT Senior Notes
Debt Instrument [Line Items]
Long-term Debt	[4]			94,795		$ 94,686	[1]									94,795	$ 94,686	[1]
Debt Instrument, Face Amount												$ 110,000
Redemption Price of Notes Equal to Principal Amount, Percentage												100.00%
Proceeds from Issuance of Long-term Debt											$ 109,400
RGRT Senior Notes | 3.67% Senior Notes, Series A, due 2015
Debt Instrument [Line Items]
Long-term Debt, Current Maturities								$ (15,000)
Debt Instrument, Interest Rate, Stated Percentage								3.67%
Debt Instrument, Maturity Date								Aug. 15, 2015
RGRT Senior Notes | 4.47% Senior Notes, Series B, due 2017
Debt Instrument [Line Items]
Long-term Debt	[4]			49,950		$ 49,883	[1]									49,950	$ 49,883	[1]
Long-term Debt, Current Maturities				$ (50,000)												$ (50,000)
Debt Instrument, Interest Rate, Stated Percentage				4.47%		4.47%										4.47%	4.47%
Debt Instrument, Interest Rate, Effective Percentage				4.62%		4.62%										4.62%	4.62%
Debt Instrument, Maturity Date				Aug. 15, 2017		Aug. 15, 2017
RGRT Senior Notes | 5.04% Senior Notes, Series C, due 2020
Debt Instrument [Line Items]
Long-term Debt	[4]			$ 44,845		$ 44,803	[1]									$ 44,845	$ 44,803	[1]
Debt Instrument, Interest Rate, Stated Percentage				5.04%		5.04%										5.04%	5.04%
Debt Instrument, Interest Rate, Effective Percentage				5.16%		5.16%										5.16%	5.16%
Debt Instrument, Maturity Date				Aug. 15, 2020		Aug. 15, 2020
Financing Obligations | Revolving Credit Facility
Debt Instrument [Line Items]
Long-term Line of Credit	[5]			$ 81,574		$ 141,738	[1]									$ 81,574	$ 141,738	[1]
Subsequent Event
Debt Instrument [Line Items]
Line of Credit Facility, Expiration Date		Jan. 14, 2021
Line of Credit renewal term, year		1 year
Subsequent Event | Revolving Credit Facility Expiring January 2020
Debt Instrument [Line Items]
Line of Credit Facility, Expiration Date			Jan. 14, 2020
Line of Credit renewal term, year			1 year
Line of Credit Facility, Current Borrowing Capacity			$ 350,000
Line of Credit Facility, Remaining Borrowing Capacity			50,000
Line of Credit Facility, Maximum Borrowing Capacity			400,000
Line of Credit Facility, Increase (Decrease), Net			$ 50,000

[1] The Company implemented ASU 2015-03, Interest - Imputation of Interest, which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The impact of ASU 2015-03 on the Company's Balance Sheet was to reclassify $11.6 million of other deferred charges to long-term debt, net of current portion at December 31, 2015.

[2] Pollution Control Bonds ("PCBs")The Company has four series of tax exempt unsecured PCBs in aggregate principal amount of $193.1 million. The 1.875% 2012 Series A (El Paso Electric Company Four Corners Project) Pollution Control Refunding Revenue Bonds with an aggregate principal amount of $33.3 million are subject to mandatory tender for purchase in September 2017 at which time the Company will either repay or remarket these bonds.

[3] Senior NotesThe 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. 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.

[4] RGRT Senior NotesIn 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 (the "Notes"). In August 2015, $15.0 million of these Notes matured and were paid with borrowings from the RCF. In August 2017, $50.0 million of these Senior Notes will mature. The Company will either repay or refinance this $50.0 million of Notes upon maturity. The Company guarantees the payment of principal and interest on the 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 Notes on February 15, and August 15 of each year until maturity. RGRT may redeem the 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 2016.The sale of the 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 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 Notes and amounts borrowed from the RCF.

[5] Revolving Credit FacilityOn 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 2016. In August 2015, $15.0 million aggregate principal amount of Series A 3.67% Senior Notes of RGRT matured and were paid utilizing borrowings under the RCF. As of December 31, 2016, the total amount borrowed by RGRT was $37.6 million for nuclear fuel under the RCF. As of December 31, 2016, $44.0 million of borrowings were outstanding under this facility for working capital and general corporate purposes. The weighted average interest rate on the RCF was 2.0% as of December 31, 2016.

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Long-Term Debt and Financing Obligations Long-term Debt Maturities (Details) $ in Thousands	Dec. 31, 2016 USD ($)
Debt Instrument [Line Items]
Long-term Debt, Maturities, Repayments of Principal in Year One	$ 83,300
Long-term Debt, Maturities, Repayments of Principal in Year Two	0
Long-term Debt, Maturities, Repayments of Principal in Year Three	0
Long-term Debt, Maturities, Repayments of Principal in Year Four	45,000
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Nuclear Fuel Financing | Revolving Credit Facility
Debt Instrument [Line Items]
Long-term Debt, Maturities, Repayments of Principal in Year One	$ 37,600

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Long-Term Debt and Financing Obligations Reclassification (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Accounting Standards Update 2015-03 [Member]
Debt Instrument [Line Items]
Amounts previously reported, reclassified	$ 11.6

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Income Taxes (Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Deferred tax assets:
Benefit of tax loss carryforwards	$ 60,749	$ 35,153
Alternative minimum tax credit carryforward	16,620	16,620
Pensions and benefits	57,756	61,673
Asset retirement obligation	26,929	28,042
Deferred fuel	0	1,488
Other	(200)	15,421
Total gross deferred tax assets	161,854	158,397
Deferred tax liabilities:
Plant, principally due to depreciation and basis differences	(668,303)	(608,738)
Decommissioning	(43,463)	(41,100)
Deferred fuel	3,962	0
Other	(1,192)	(3,796)
Total gross deferred tax liabilities	(716,920)	(653,634)
Net accumulated deferred income taxes	$ (555,066)	$ (495,237)

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Income Taxes (Recognized Income Tax Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Federal:
Current	$ 2,642	$ 2,319	$ (1,250)
Deferred	47,909	32,819	38,810
Total federal income tax	50,551	35,138	37,560
State:
Current	766	1,730	3,209
Deferred	3,285	(1,650)	641
Total state income tax	4,051	80	3,850
Generation (amortization) of accumulated investment tax credits	(684)	(323)	(322)
Total income tax expense	$ 53,918	$ 34,895	$ 41,088

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Income Taxes (Income Tax Provisions) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Examination [Line Items]
Federal income tax expense computed on income at statutory rate	$ 52,740	$ 40,885	$ 46,381
Difference due to:
State taxes, net of federal benefit	2,633	52	1,902
AEFUDC	(475)	(2,345)	(3,757)
Permanent tax differences	(2,369)	(2,898)	(2,921)
Other	1,389	(799)	(517)
Total income tax expense	$ 53,918	$ 34,895	$ 41,088
Effective income tax rate	35.80%	29.90%	31.00%

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Income Taxes (Unrecognized Tax Benefits)[Roll Forward] (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of period	$ 6,000	$ 5,200	$ 7,200
Additions for tax positions related to the current year	400	500	300
Reductions for tax positions related to the current year	0	0	0
Additions for tax positions of prior years	100	300	2,200
Reductions for tax positions of prior years	(1,200)	0	(4,500)
Balance at end of period	$ 5,300	$ 6,000	$ 5,200

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Income Taxes (Details) - USD ($) $ in Thousands		12 Months Ended
	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax [Line Items]
Period of Average Annual Book Income Before Taxes		3 years
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax		$ 16,620	$ 16,620
Federal statutory tax rate		35.00%	35.00%	35.00%
Deferred Income Tax Expense (Benefit)		$ 50,510	$ 30,846	$ 39,129
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions		0	0	0
Unrecognized tax benefits, Increase (Decrease) resulting from tax positions taken in prior and current period tax returns.		(400)	(800)	(2,100)
Unrecognized Tax Benefits, Increase Resulting from Settlements with Taxing Authorities		500
Unrecognized tax benefits that would impact effective tax rate		2,600
Unrecognized tax benefits, interest on income taxes expense (benefit)		100	200	100
Unrecognized tax benefits, income tax penalties and interest accrued		800	700
Unrecognized Tax Benefits		5,300	$ 6,000	5,200	$ 7,200
Internal Revenue Service (IRS)
Income Tax [Line Items]
Tax Credit Carryforward, Amount		$ 59,300
Live Of Tax Loss Carrforwards		20 years
State and Local Jurisdiction
Income Tax [Line Items]
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions		$ 700
Tax Credit Carryforward, Amount		$ 2,200
Live Of Tax Loss Carrforwards		5 years
Tax credit taken | ARIZONA
Income Tax [Line Items]
Increase (Decrease) in Unrecognized Tax Position of Prior Years Recorded, net		$ (300)		(1,300)
Unrecognized Tax Benefits, Increase Resulting from Settlements with Taxing Authorities				$ 400
Earliest Tax Year | TEXAS
Income Tax [Line Items]
Income Tax Examination, Year under Examination		2007
Earliest Tax Year | ARIZONA
Income Tax [Line Items]
Tax Year Closed	2009
Latest Tax Year | Internal Revenue Service (IRS)
Income Tax [Line Items]
Tax Year Closed		2011
Latest Tax Year | NEW MEXICO
Income Tax [Line Items]
Tax Year Closed		2011
Latest Tax Year | TEXAS
Income Tax [Line Items]
Income Tax Examination, Year under Examination		2011
Latest Tax Year | ARIZONA
Income Tax [Line Items]
Tax Year Closed	2012
Change in Accounting Method Accounted for as Change in Estimate [Member]
Income Tax [Line Items]
Deferred Income Tax Expense (Benefit)		$ 5,100
Stock Compensation Plan
Income Tax [Line Items]
Unrecognized Tax Benefits		200
Accounting Standards Update 2015-17 [Member]
Income Tax [Line Items]
Prior Period Reclassification Adjustment		$ 21,600

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Commitments, Contingencies and Uncertainties (Power Purchase and Sale Agreement) (Details)	12 Months Ended
	Dec. 31, 2016 MW
Freeport Agreement 3 - 25 MW
Long-term Purchase Commitment [Line Items]
Long-Term Purchase commitment, Maximum Quantity	25
Long-term Purchase Commitment, Time Period	10 years 1 month
Long-Term Sale Commitment, Maximum Quantity	25
Long-Term Sale Commitment, Time Period	10 years 1 month
Freeport Agreement 2 - 100 MW
Long-term Purchase Commitment [Line Items]
Long-Term Purchase commitment, Maximum Quantity	100
Long-term Purchase Commitment, Time Period	15 years 7 months
Long-Term Sale Commitment, Maximum Quantity	100
Long-Term Sale Commitment, Time Period	15 years 7 months
Hatch Solar Energy Center I
Long-term Purchase Commitment [Line Items]
Long-Term Purchase commitment, Maximum Quantity	5
Long-term Purchase Commitment, Time Period	25 years
Plant Commercial Operation Date	Jul. 01, 2011
NRG
Long-term Purchase Commitment [Line Items]
Long-Term Purchase commitment, Maximum Quantity	20
Long-term Purchase Commitment, Time Period	20 years 1 month
Plant Commercial Operation Date	Aug. 01, 2011
Sun Edison 1
Long-term Purchase Commitment [Line Items]
Long-Term Purchase commitment, Maximum Quantity	10
Long-term Purchase Commitment, Time Period	25 years 1 month
Plant Commercial Operation Date	Jun. 25, 2012
Sun Edison 2
Long-term Purchase Commitment [Line Items]
Long-Term Purchase commitment, Maximum Quantity	12
Long-term Purchase Commitment, Time Period	25 years 1 month
Plant Commercial Operation Date	May 02, 2012
Macho Springs Solar
Long-term Purchase Commitment [Line Items]
Long-Term Purchase commitment, Maximum Quantity	50
Long-term Purchase Commitment, Time Period	20 years
Plant Commercial Operation Date	May 23, 2014
Plant Capacity	50
Newman Solar
Long-term Purchase Commitment [Line Items]
Long-Term Purchase commitment, Maximum Quantity	10
Long-term Purchase Commitment, Time Period	30 years
Plant Commercial Operation Date	Dec. 30, 2014
Freeport Agreement 1 - 125 MW
Long-term Purchase Commitment [Line Items]
Long-Term Purchase commitment, Maximum Quantity	125
Long-term Purchase Commitment, Time Period	2 years
Long-Term Sale Commitment, Maximum Quantity	125
Long-Term Sale Commitment, Time Period	2 years
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2018
Long-Term Contract For Sale Of Electric Power Date Of Contract Expiration	Dec. 31, 2018
Sun Edison 1 and Sun Edison 2
Long-term Purchase Commitment [Line Items]
Solar Photovoltaic Projects, Number of Units	2
FERC | Freeport Agreement 1 - 125 MW
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2021
Long-Term Contract For Sale Of Electric Power Date Of Contract Expiration	Dec. 31, 2021

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Commitments, Contingencies and Uncertainties (Narrative) (Details) - USD ($) $ in Thousands			12 Months Ended
	Mar. 16, 2016	Aug. 17, 2015	Dec. 31, 2016
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies			$ 200
Four Corners Coal Plant Participants
Loss Contingencies [Line Items]
Civil Penalty Amount		$ 1,500
Public Utilities, Assessed Coal Severance Surtax Penalty and Interest			30,000
Litigation Settlement, Amount	$ 1,000
Environmental Mitigation Project Cost		$ 6,700
Four Corners Generating Station
Loss Contingencies [Line Items]
Public Utilities, Assessed Coal Severance Surtax Penalty and Interest			$ 1,500
Litigation Settlement, Amount	$ 47

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Commitments, Contingencies and Uncertainties (Future Minimum Payments For Operating Leases) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Leased Assets [Line Items]
Operating Leases, Rent Expense	$ 1,700	$ 1,900	$ 1,800
2017	808
2018	662
2019	666
2020	664
2021	$ 562
Newman Land Lease
Operating Leased Assets [Line Items]
Lease Expiration Date	Jun. 30, 2033
Lessee Leasing Arrangements, Operating Leases, Renewal Term	25 years
Other Property
Operating Leased Assets [Line Items]
Lessee Leasing Arrangements, Operating Leases, Term of Contract	P4Y

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Commitments, Contingencies and Uncertainties (Union Matters) (Details)	12 Months Ended
	Dec. 31, 2016	Sep. 03, 2018	Sep. 03, 2017	Sep. 03, 2016
Commitments and Contingencies Disclosure [Abstract]
Entity Number of Employees	1,100
Number of Employees Cover by Collective Bargaining Agreements, Percentage	38.00%
Collective Bargaining Agreement Effective Date	Sep. 03, 2016
Term of Collective Bargaining Agreement, Year	P3Y
Collective Bargaining Agreement Expiration Date	Sep. 03, 2019
Subsequent Event [Line Items]
Pay increase, percentage				3.00%
Scenario, Forecast
Subsequent Event [Line Items]
Pay increase, percentage		3.00%	3.00%

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Employee Benefits (Obligations and Funded Status of the Plan) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Retirement Income Plan
Change in projected benefit obligation:
Benefit obligation at end of prior year	$ 325,706	$ 341,133
Service cost	7,705	8,530	$ 8,284
Interest cost	12,161	13,477	14,001
Actuarial (gain) loss	7,988	(19,290)
Benefits paid	(15,792)	(18,144)
Benefit obligation at end of year	337,768	325,706	341,133
Change in plan assets:
Fair value of plan assets at end of prior year	260,035	272,939
Actual return (loss) on plan assets	18,223	(3,760)
Employer contribution	7,300	9,000
Benefits paid	(15,792)	(18,144)
Fair value of plan assets at end of year	269,766	260,035	272,939
Funded status at end of year	(68,002)	(65,671)
Other Pension Plans
Change in projected benefit obligation:
Benefit obligation at end of prior year	26,958	28,397
Service cost	296	262	303
Interest cost	878	1,018	1,041
Actuarial (gain) loss	1,267	(810)
Benefits paid	(1,937)	(1,909)
Benefit obligation at end of year	27,462	26,958	28,397
Change in plan assets:
Fair value of plan assets at end of prior year	0	0
Actual return (loss) on plan assets	0	0
Employer contribution	1,937	1,909
Benefits paid	(1,937)	(1,909)
Fair value of plan assets at end of year	0	0	$ 0
Funded status at end of year	$ (27,462)	$ (26,958)

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Employee Benefits (Defined Benefit Plan, Amounts Recognized in Balance Sheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Current liabilities	$ 0	$ 0
Noncurrent liabilities	(68,002)	(65,671)
Total	(68,002)	(65,671)
Other Pension Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Current liabilities	(2,696)	(2,102)
Noncurrent liabilities	(24,766)	(24,856)
Total	(27,462)	(26,958)
Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Current liabilities	0	0
Noncurrent liabilities	(34,400)	(54,553)
Total	$ (34,400)	$ (54,553)

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Employee Benefits (Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Projected benefit obligation	$ (337,768)	$ (325,706)
Accumulated benefit obligation	(314,071)	(302,446)
Fair value of plan assets	269,766	260,035
Other Pension Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Projected benefit obligation	(27,462)	(26,958)
Accumulated benefit obligation	(25,550)	(25,785)
Fair value of plan assets	$ 0	$ 0

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Employee Benefits (Amounts Recognized in Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss	$ 121,052	$ 118,963
Prior service benefit	(23,877)	(27,344)
Total	97,175	91,619
Other Pension Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss	10,073	9,592
Prior service benefit	(185)	(224)
Total	$ 9,888	$ 9,368

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Employee Benefits (Weighted-Average Actuarial Assumptions for Benefit Obligations - Retirement Plans) (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Effect of One Percentage Point Increase on Discount Rate	1.00%
Defined Benefit Plan, Decrease in Projected Benefit Obiligation, Percentage	11.50%
Defined Benefit Plan, Effect of One Percentage Point Decrease on Discount Rate	1.00%
Defined Benefit Plan, Increase in Projected Benefit Obiligation, Percentage	14.10%
Retirement Income Plan | Benefit Obligations
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount rate	4.29%	4.57%
Rate of compensation increase	4.50%	4.50%
Supplemental Employee Retirement Plan | Benefit Obligations
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount rate	3.76%	3.99%
Excess Benefit Plan | Benefit Obligations
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount rate	4.34%	4.59%
Rate of compensation increase	4.50%	4.50%

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Employee Benefits (Net Periodic Benefit Costs) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	$ 7,705	$ 8,530	$ 8,284
Interest cost	12,161	13,477	14,001
Expected return on plan assets	(18,879)	(19,795)	(18,699)
Decrease In Service and Interest Component of Net Periodic Benefit Cost	2,900
Amortization of:
Net loss	6,554	9,710	8,178
Prior service cost (benefit)	(3,467)	(3,467)	(2,889)
Net periodic benefit cost	4,074	8,455	8,875
Other Pension Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	296	262	303
Interest cost	878	1,018	1,041
Expected return on plan assets	0	0	0
Amortization of:
Net loss	785	937	675
Prior service cost (benefit)	(39)	(39)	(17)
Net periodic benefit cost	$ 1,920	$ 2,178	$ 2,002

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Employee Benefits (Other Comprehensive Income - Retirement Plans) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net (gain) loss	$ 20,053	$ (5,429)	$ 54,328
Prior service benefit	(32,697)	(824)	(34,200)
Amortization of:
Net loss	(4,965)	(8,622)	(6,182)
Prior service (cost) benefit	7,407	6,574	7,659
Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net (gain) loss	8,644	4,266	47,324
Prior service benefit	0	0	(33,700)
Amortization of:
Net loss	(6,554)	(9,710)	(8,178)
Prior service (cost) benefit	3,467	3,467	2,889
Total recognized in other comprehensive income	5,557	(1,977)	8,335
Other Pension Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net (gain) loss	1,266	(811)	3,508
Prior service benefit	0	0	(500)
Amortization of:
Net loss	(785)	(937)	(675)
Prior service (cost) benefit	39	39	17
Total recognized in other comprehensive income	$ 520	$ (1,709)	$ 2,350

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Employee Benefits (Recognized in Other Comprehensive Income and Net Periodic Benefit Costs - Retirement Plans) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total recognized in net periodic benefit cost and other comprehensive income	$ 9,631	$ 6,478	$ 17,210
Other Pension Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total recognized in net periodic benefit cost and other comprehensive income	$ 2,440	$ 469	$ 4,352

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Employee Benefits (Accumulated Other Comprehensive Income Recognized in Net Periodic Benefit Cost in Next Fiscal Year) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016 USD ($)
Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss/gain	$ 7,530
Prior service benefit	(3,470)
Other Pension Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss/gain	825
Prior service benefit	(40)
Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss/gain	(1,600)
Prior service benefit	$ (6,200)

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Employee Benefits (Weighted Average Assumptions Used to Calculate Net Period Benefit Costs- Retirement Plans) (Details)		12 Months Ended
	Jan. 01, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	[1]	Feb. 28, 2014	Dec. 31, 2013
Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected long-term return on plan assets		7.00%
Net Periodic Benefit Costs | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected long-term return on plan assets		7.00%	7.50%	7.50%
Rate of compensation increase		4.50%	4.50%	4.75%
Net Periodic Benefit Costs | Excess Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Rate of compensation increase		4.50%	4.50%	4.75%
Subsequent Event | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected long-term return on plan assets	7.00%
Remeasurement | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount rate - Benefit Obligations						4.60%	4.90%
Remeasurement | Excess Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount rate - Benefit Obligations						4.50%	4.90%
Benefit Obligation | Net Periodic Benefit Costs | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount Rate		4.57%	4.00%	4.90%
Benefit Obligation | Net Periodic Benefit Costs | Supplemental Employee Retirement Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount Rate		3.99%	3.40%	3.90%
Benefit Obligation | Net Periodic Benefit Costs | Excess Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount Rate		4.63%	4.10%	4.90%
Service cost | Net Periodic Benefit Costs | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount Rate		4.83%	4.00%	4.90%
Service cost | Net Periodic Benefit Costs | Excess Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount Rate		4.87%	4.10%	4.90%
Interest cost | Net Periodic Benefit Costs | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount Rate		3.86%	4.00%	4.90%
Interest cost | Net Periodic Benefit Costs | Supplemental Employee Retirement Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount Rate		3.04%	3.40%	3.90%
Interest cost | Net Periodic Benefit Costs | Excess Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount Rate		3.90%	4.10%	4.90%

[1] The Retirement Plan and the Excess Benefit Plan were remeasured on February 28, 2014 due to the above mentioned plan amendment. The discount rate used to remeasure the benefit obligation was 4.6% for the Retirement Plan and 4.5% for the Excess Benefit Plan, compared to 4.9% for both plans as of January 1, 2014. All other assumptions remained consistent with assumptions used at January 1, 2014.

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Employee Benefits (Target Asset Allocation of Pension Fund) (Details) - Retirement Income Plan	12 Months Ended
	Dec. 31, 2016
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Assets, Target Allocations Total	100.00%
Equity Securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Assets, Target Allocations	50.00%
Fixed Income
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Assets, Target Allocations	40.00%
Alternative Investments
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Assets, Target Allocations	10.00%

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Employee Benefits (Fair Value Measurement Inputs) (Details) - USD ($)			12 Months Ended
		Jun. 30, 2016	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair Value, Assets, Level 1 to Level 2 Transfers, Description			no		no
Fair Value, Assets, Level 2 to Level 1 Transfers, Description			no		no
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases, Sales, Issuances, Settlements			$ 0		$ 0
Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Restriction Period To Sell Partnership Interest Maximum			7 years
Fair value of plan assets at end of year			$ 269,766,000		$ 260,035,000		$ 272,939,000
Fair Value, Assets, Level 1 to Level 2 Transfers, Description			no		no
Fair Value, Assets, Level 2 to Level 1 Transfers, Description			no		no
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases, Sales, Issuances, Settlements			$ 0		$ 0
Limited Partnership expiration date		Jun. 30, 2016
Cash and Cash Equivalents | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year			932,000		1,266,000
Common Collective Trusts | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		261,843,000		250,181,000
Limited Partnership Interest in Real Estate | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year			6,991,000	[2],[3]	8,588,000	[2],[3]	$ 8,748,000
Fair Value, Inputs, Level 1 | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year			262,775,000		251,447,000
Fair Value, Inputs, Level 1 | Cash and Cash Equivalents | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year			932,000		1,266,000
Fair Value, Inputs, Level 1 | Common Collective Trusts | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		261,843,000		250,181,000
Fair Value, Inputs, Level 2 | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year			0		0
Fair Value, Inputs, Level 2 | Cash and Cash Equivalents | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year			0		0
Fair Value, Inputs, Level 2 | Common Collective Trusts | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		0		0
Fair Value, Inputs, Level 3 | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year			0		0
Fair Value, Inputs, Level 3 | Cash and Cash Equivalents | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year			0		0
Fair Value, Inputs, Level 3 | Common Collective Trusts | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		0		0
Common Collective Trusts | Equity Funds | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		144,081,000		144,279,000
Common Collective Trusts | Fixed Income Funds | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		109,356,000		103,877,000
Common Collective Trusts | Real Estate Funds | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		8,406,000		2,025,000
Common Collective Trusts | Fair Value, Inputs, Level 1 | Equity Funds | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		144,081,000		144,279,000
Common Collective Trusts | Fair Value, Inputs, Level 1 | Fixed Income Funds | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		109,356,000		103,877,000
Common Collective Trusts | Fair Value, Inputs, Level 1 | Real Estate Funds | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		8,406,000		2,025,000
Common Collective Trusts | Fair Value, Inputs, Level 2 | Equity Funds | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		0		0
Common Collective Trusts | Fair Value, Inputs, Level 2 | Fixed Income Funds | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		0		0
Common Collective Trusts | Fair Value, Inputs, Level 2 | Real Estate Funds | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		0		0
Common Collective Trusts | Fair Value, Inputs, Level 3 | Equity Funds | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		0		0
Common Collective Trusts | Fair Value, Inputs, Level 3 | Fixed Income Funds | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		0		0
Common Collective Trusts | Fair Value, Inputs, Level 3 | Real Estate Funds | Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		$ 0		$ 0

[1] 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.

[2] 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 guidance. 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. ASU 2015-07 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years.

[3] 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.

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Employee Benefits (Fair Value Change in Investment in Real Estate) (Details) - Retirement Income Plan - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016		Dec. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of prior year		$ 260,035		$ 272,939
Fair value of plan assets at end of year		269,766		260,035
Limited Partnership Interest in Real Estate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of prior year		8,588	[1],[2]	8,748
Unrealized gain (loss) in fair value		(822)		(160)
Sale of Land		(775)
Fair value of plan assets at end of year	[1],[2]	$ 6,991		$ 8,588

[1] 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 guidance. 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. ASU 2015-07 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years.

[2] 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.

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Employee Benefits (Expected Future Benefit Payments) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016 USD ($)
Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	$ 10,000
2017	16,113
2018	19,080
2019	18,771
2020	18,923
2021	19,755
2022-2026	107,916
Other Pension Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2017	2,698
2018	2,060
2019	2,025
2020	1,957
2021	1,907
2022-2026	$ 8,949

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Employee Benefits 401(k) Defined Contribution Plans (Details) - USD ($) $ in Millions			12 Months Ended
	Apr. 02, 2014	Mar. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Contribution Plan Disclosure [Line Items]
Defined benefit plans revisions effective date	Apr. 01, 2014
Defined Contribution Plan, Employer Discretionary Contribution Amount			$ 4.1	$ 3.9	$ 3.0
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	100.00%	50.00%
Maximum
Defined Contribution Plan Disclosure [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent	6.00%	6.00%

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Employee Benefits (Changes in Funded Status of Plan - Other Postretirment Benefit Plans) (Details) - Other Postretirement Benefit Plan $ in Thousands		12 Months Ended
		Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Jan. 01, 2017
Change in projected benefit obligation:
Benefit obligation at end of prior year		$ 92,643	$ 100,700
Service cost		2,769	3,454	$ 2,845
Interest cost		3,167	4,035	4,463
Actuarial loss (gain)		10,751	(11,423)
Amendment	[1],[2]	(32,697)	(824)
Benefits paid		(4,428)	(4,544)
Retiree contributions		1,310	1,245
Benefit obligation at end of year		73,515	92,643	100,700
Change in plan assets:
Fair value of plan assets at end of prior year		38,090	41,358
Actual return (loss) on plan assets		2,443	(469)
Employer contribution		1,700	500
Benefits paid		(4,428)	(4,544)
Retiree contributions		1,310	1,245
Fair value of plan assets at end of year		39,115	38,090	$ 41,358
Funded status at end of year		$ (34,400)	$ (54,553)
$1,000 or $2,250 deductible plan options | Scenario, Forecast | Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Age Eligible for Benefit					65
Medicare advantage plan | Scenario, Forecast | Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Age Eligible for Benefit					65

[1] Amendment relates to modification of the Company's Other Post-retirement Benefit Plan which increased mail order co-payments for post age 65. The amendment was approved in 2015 and became effective January 1, 2016.

[2] During October 2016, the Company approved and communicated a plan amendment that resulted in a remeasurement of the Company's 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 were covered by a fully insured Medicare advantage plan.

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Employee Benefits (Components of Accumulated Other Comprehensive Income) (Details) - Other Postretirement Benefit Plan - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net gain	$ (26,285)	$ (38,802)
Prior service benefit	(41,009)	(12,213)
Total	$ (67,294)	$ (51,015)

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Employee Benefits (Weighted Average Assumptions- Accrued Postretirement Benefits - Other Postretirment Benefit Plans) (Details) - Other Postretirement Benefit Plan		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation, Percentage		13.10%
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation, Percentage		16.70%
Accrued Postretirement Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount rate		4.36%	4.59%
Ultimate		4.50%	4.50%
Year ultimate reached	[1]	2026	2026
Defined Benefit Plan, Effect of One Percentage Point Increase on Discount Rate		1.00%
Defined Benefit Plan, Effect of One Percentage Point Decrease on Discount Rate		1.00%
Pre-65 medical | Accrued Postretirement Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Initial		6.50%	7.00%
Post-65 medical | Accrued Postretirement Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Initial		4.50%	7.00%
Pre-65 drug | Accrued Postretirement Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Initial		7.50%	7.00%
Post-65 drug | Accrued Postretirement Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Initial		10.50%	7.00%

[1] Pre-65 medical reaches the ultimate trend rate in 2025. Additionally, the Post-65 medical trend is assumed to be 4.50% for all years into the future.

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Employee Benefits (Net Periodic Benefit Cost) (Details) - Other Postretirement Benefit Plan - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Decrease In Service and Interest Component of Net Periodic Benefit Cost	$ 800
Service cost	2,769	$ 3,454	$ 2,845
Interest cost	3,167	4,035	4,463
Expected return on plan assets	(1,835)	(2,070)	(2,116)
Amortization of:
Prior service benefit	(3,901)	(3,068)	(4,753)
Net gain	(2,374)	(2,025)	(2,671)
Net periodic benefit cost	$ (2,174)	$ 326	$ (2,232)

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Employee Benefits (Other Comprehensive Income, Other Postretirement Benefit Plans) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net (gain) loss	$ 20,053	$ (5,429)	$ 54,328
Prior service benefit	(32,697)	(824)	(34,200)
Amortization of:
Prior service benefit	7,407	6,574	7,659
Net gain	(4,965)	(8,622)	(6,182)
Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net (gain) loss	10,143	(8,884)	3,496
Prior service benefit	(32,697)	(824)	0
Amortization of:
Prior service benefit	3,901	3,068	4,753
Net gain	2,374	2,025	2,671
Total recognized in other comprehensive income	$ (16,279)	$ (4,615)	$ 10,920

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Employee Benefits (Recognized Net Periodic Benefit Costs and Other Comprehensive Income -Other Postretirement Benefit Plans) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total recognized in net periodic benefit cost and other comprehensive income	$ (18,453)	$ (4,289)	$ 8,688

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Employee Benefits (Weighted Average Assumptions - Net Periodic Benefit Cost) (Details) - Other Postretirement Benefit Plan - USD ($) $ in Millions		3 Months Ended		9 Months Ended		12 Months Ended
	Jan. 01, 2017	Dec. 31, 2016		Sep. 30, 2016	[1]	Dec. 31, 2016		Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, One Percentage Point Change, Increase or Decrease						1.00%
Defined Benefit Plan, Effect of One Percentage Point Increase on Benefit Obligations		$ 11.2				$ 11.2
Defined Benefit Plan, Effect of One Percentage Point Decrease on Benefit Obligations		$ 9.0				9.0
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components						1.3
Defined Benefit Plan, Effect of One Percentage Point Decrease on Service and Interest Cost Components						$ 1.0
Net Periodic Benefit Costs
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected long-term return on plan assets						4.875%	[1]	5.20%	5.20%
Initial						7.00%	[1]	7.25%	7.50%
Ultimate						4.50%	[1]	4.50%	4.50%
Year ultimate reached		2026	[1]			2026	[1]	2026	2026
Subsequent Event
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected long-term return on plan assets	4.875%
Benefit Obligation | Net Periodic Benefit Costs
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount Rate		3.75%	[1]	4.59%				4.10%	4.90%
Service cost | Net Periodic Benefit Costs
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount Rate		4.03%	[1]	4.91%				4.10%	4.90%
Interest cost | Net Periodic Benefit Costs
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount Rate		3.15%	[1]	3.86%				4.10%	4.90%

[1] The actuarial assumptions are evaluated by the Company at each measurement date. The Other Post-retirement Benefits Plan was remeasured at October 1, 2016 due to a plan amendment.

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Employee Benefits (Target Allocations - Other Postretirment Benefit Plans) (Details) - Other Postretirement Benefit Plan	12 Months Ended
	Dec. 31, 2016
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Assets, Target Allocations Total	100.00%
Equity Securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Assets, Target Allocations	65.00%
Fixed Income
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Assets, Target Allocations	30.00%
Alternative Investments
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Assets, Target Allocations	5.00%

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Employee Benefits (Fair Value Measurements- Other Postretirement Benefits) (Details) - USD ($)			12 Months Ended
		Jun. 30, 2016	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair Value, Assets, Level 1 to Level 2 Transfers, Description			no		no
Fair Value, Assets, Level 2 to Level 1 Transfers, Description			no		no
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases, Sales, Issuances, Settlements			$ 0		$ 0
Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Restriction Period To Sell Partnership Interest Maximum			7 years
Fair Value, Assets, Level 1 to Level 2 Transfers, Description			no		no
Fair Value, Assets, Level 2 to Level 1 Transfers, Description			no		no
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases, Sales, Issuances, Settlements			$ 0		$ 0
Fair value of plan assets at end of year			39,115,000		38,090,000		$ 41,358,000
Limited Partnership expiration date		Jun. 30, 2016
Institutional Funds | Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		37,804,000		36,480,000
Limited Partnership Interest in Real Estate | Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year			1,311,000	[2],[3]	1,610,000	[2],[3]	$ 1,640,000
Fair Value, Inputs, Level 1 | Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year			37,804,000		36,480,000
Fair Value, Inputs, Level 1 | Institutional Funds | Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		37,804,000		36,480,000
Fair Value, Inputs, Level 2 | Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year			0		0
Fair Value, Inputs, Level 2 | Institutional Funds | Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		0		0
Fair Value, Inputs, Level 3 | Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year			0		0
Fair Value, Inputs, Level 3 | Institutional Funds | Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		0		0
Institutional Funds | Equity Funds | Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		26,133,000		24,881,000
Institutional Funds | Fixed Income Funds | Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		11,671,000		11,599,000
Institutional Funds | Fair Value, Inputs, Level 1 | Equity Funds | Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		26,133,000		24,881,000
Institutional Funds | Fair Value, Inputs, Level 1 | Fixed Income Funds | Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		11,671,000		11,599,000
Institutional Funds | Fair Value, Inputs, Level 2 | Equity Funds | Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		0		0
Institutional Funds | Fair Value, Inputs, Level 2 | Fixed Income Funds | Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		0		0
Institutional Funds | Fair Value, Inputs, Level 3 | Equity Funds | Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		0		0
Institutional Funds | Fair Value, Inputs, Level 3 | Fixed Income Funds | Other Postretirement Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	[1]		$ 0		$ 0

[1] 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.

[2] 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 guidance. 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. ASU 2015-07 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years.

[3] 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 of 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.

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Employee Benefits (Changes in Fair Value Investment Real Estate - Other Postretirement Benefit Plans) (Details) - Other Postretirement Benefit Plan - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016		Dec. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of prior year		$ 38,090		$ 41,358
Fair value of plan assets at end of year		39,115		38,090
Limited Partnership Interest in Real Estate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of prior year		1,610	[1],[2]	1,640
Unrealized gain (loss) in fair value		(154)		(30)
Sale of Land		(145)
Fair value of plan assets at end of year	[1],[2]	$ 1,311		$ 1,610

[1] 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 guidance. 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. ASU 2015-07 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years.

[2] 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 of 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.

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Employee Benefits (Expected Future Benefit Payments - Other Postretirement Benefit Plans) (Details) - Other Postretirement Benefit Plan $ in Thousands	12 Months Ended
	Dec. 31, 2016 USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	$ 1,500
2017	2,622
2018	2,880
2019	3,057
2020	3,320
2021	3,510
2022-2026	$ 20,084

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Employee Benefits (Details) $ in Millions			12 Months Ended
	Apr. 02, 2014	Mar. 31, 2014	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Employee Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Number of Non-Qualified Retirement Plans			2
Defined benefit plans revisions effective date	Apr. 01, 2014
Short Term Incentive Plan Payout			$ 12.5	$ 10.5	$ 7.4
Retirement Income Plan
Employee Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined benefit plans revisions effective date	Apr. 01, 2014
Pension benefit earned by employee is frozen, date.		Mar. 31, 2014
Retirement Income Plan | Years Of Service
Employee Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Years of Service Requisite			1

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Franchises and Significant Customers (Details)	12 Months Ended
	Dec. 31, 2016 MW
El Paso
Franchises and Significant Customers [Line Items]
Preceded Franchise Fee Percent	3.25%
Percentage of Revenue Additional Franchise Fees, Restricted	0.75%
Retail Electric Service Contract, Expiration Date	Jul. 31, 2030
Las Cruces
Franchises and Significant Customers [Line Items]
Retail Electric Service Contract, Expiration Date	Apr. 30, 2009
August 1, 2010 through Present | El Paso
Franchises and Significant Customers [Line Items]
Franchise Fee, Percent	4.00%
February 1, 2000 through Present | Las Cruces
Franchises and Significant Customers [Line Items]
Franchise Fee, Percent	2.00%
Sales Revenue, Services, Net | Military Bases
Franchises and Significant Customers [Line Items]
Concentration Risk, Percentage	2.80%
Holloman Air Force Base Solar Facility
Franchises and Significant Customers [Line Items]
Electric capacity	5

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Financial Instruments and Investments (Carrying Amount and Fair Value Amounts) (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Carrying (Reported) Amount, Fair Value Disclosure
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure	[1]	$ 1,360,230	$ 1,264,398
Carrying (Reported) Amount, Fair Value Disclosure | Pollution Control Bonds
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure	[1]	190,775	190,499
Carrying (Reported) Amount, Fair Value Disclosure | Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure	[1]	993,086	837,475
Carrying (Reported) Amount, Fair Value Disclosure | RGRT Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure	[1],[2]	94,795	94,686
Carrying (Reported) Amount, Fair Value Disclosure | Revolving Credit Facility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure	[1],[2]	81,574	141,738
Estimate of Fair Value Measurement
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure		1,499,532	1,284,571
Estimate of Fair Value Measurement | Pollution Control Bonds
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure		206,818	212,624
Estimate of Fair Value Measurement | Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure		1,112,285	829,864
Estimate of Fair Value Measurement | RGRT Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure	[2]	98,855	100,345
Estimate of Fair Value Measurement | Revolving Credit Facility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure	[2]	$ 81,574	$ 141,738

[1] The Company implemented ASU 2015-03, Interest - Imputation of Interest, which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The impact of ASU 2015-03 on the Company's Balance Sheet was to reclassify $11.6 million of other deferred charges to long-term debt, net of current portion at December 31, 2015.

[2] Nuclear fuel financing, as of December 31, 2016 and December 31, 2015, is funded through the $95 million RGRT Senior Notes and $37.6 million and $33.7 million, respectively under the RCF. As of December 31, 2016, $44.0 million was outstanding under the RCF for working capital or general corporate purposes. As of December 31, 2015, $108.0 million amount was outstanding under the RCF for working capital or general corporate purposes. The interest rate on the Company’s borrowings under the RCF is reset throughout the period reflecting current market rates. Consequently, the carrying value approximates fair value.

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Financial Instruments And Investments (Long-Term Debt And Short-Term Borrowings - Narratives) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	May 01, 2005
Financial Instruments and Investments [Line Items]
Interest Rate Cash Flow Hedge Loss to be Reclassified During Next 12 Months, Net	$ 500
Decommissioning Fund Investments	255,708	$ 239,035
Accounting Standards Update 2015-03 [Member]
Financial Instruments and Investments [Line Items]
Amounts previously reported, reclassified	11,600
Nuclear Fuel Financing
Financial Instruments and Investments [Line Items]
Line of Credit Facility, Amount Outstanding	37,600	33,700
Working Capital and General Purpose
Financial Instruments and Investments [Line Items]
Line of Credit Facility, Amount Outstanding	$ 44,000	$ 108,000
Senior Notes | 6.00% Senior Notes, Net of Discount, due 2035
Financial Instruments and Investments [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.00%	6.00%	6.00%
RGRT Senior Notes
Financial Instruments and Investments [Line Items]
Long-term Debt, Gross	$ 95,000	$ 95,000

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Financial Instruments And Investments (Marketable Securities Fair Value And Unrealized Losses) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016 USD ($) securities		Dec. 31, 2015 USD ($) securities
Financial Instruments and Investments [Line Items]
Marketable Securities Fair Value, Less than 12 Months	$ 86,509	[1]	$ 73,859	[2]
Marketable Securities Unrealized Losses Less Than 12 Months	(1,844)	[1]	(2,401)	[2]
Marketable Securities Fair Value 12 Months or Longer	24,571	[1]	25,080	[2]
Marketable Securities Unrealized Losses 12 Months or Longer	(1,401)	[1]	(1,344)	[2]
Marketable Securities Fair Value, Total	111,080	[1]	98,939	[2]
Marketable Securities Unrealized Losses, Total	$ (3,245)	[1]	$ (3,745)	[2]
Number of securities | securities	152		133
Debt Securities
Financial Instruments and Investments [Line Items]
Marketable Securities Fair Value, Less than 12 Months	$ 60,804	[1]	$ 47,821	[2]
Marketable Securities Unrealized Losses Less Than 12 Months	(1,567)	[1]	(1,289)	[2]
Marketable Securities Fair Value 12 Months or Longer	24,571	[1]	25,080	[2]
Marketable Securities Unrealized Losses 12 Months or Longer	(1,401)	[1]	(1,344)	[2]
Marketable Securities Fair Value, Total	85,375	[1]	72,901	[2]
Marketable Securities Unrealized Losses, Total	(2,968)	[1]	(2,633)	[2]
Collateralized Mortgage Backed Securities
Financial Instruments and Investments [Line Items]
Marketable Securities Fair Value, Less than 12 Months	11,582	[1]	9,383	[2]
Marketable Securities Unrealized Losses Less Than 12 Months	(239)	[1]	(97)	[2]
Marketable Securities Fair Value 12 Months or Longer	436	[1]	1,113	[2]
Marketable Securities Unrealized Losses 12 Months or Longer	(22)	[1]	(47)	[2]
Marketable Securities Fair Value, Total	12,018	[1]	10,496	[2]
Marketable Securities Unrealized Losses, Total	(261)	[1]	(144)	[2]
U.S. Government Bonds
Financial Instruments and Investments [Line Items]
Marketable Securities Fair Value, Less than 12 Months	31,655	[1]	24,094	[2]
Marketable Securities Unrealized Losses Less Than 12 Months	(762)	[1]	(310)	[2]
Marketable Securities Fair Value 12 Months or Longer	17,976	[1]	14,272	[2]
Marketable Securities Unrealized Losses 12 Months or Longer	(835)	[1]	(623)	[2]
Marketable Securities Fair Value, Total	49,631	[1]	38,366	[2]
Marketable Securities Unrealized Losses, Total	(1,597)	[1]	(933)	[2]
Municipal Bonds
Financial Instruments and Investments [Line Items]
Marketable Securities Fair Value, Less than 12 Months	9,596	[1]	8,286	[2]
Marketable Securities Unrealized Losses Less Than 12 Months	(394)	[1]	(160)	[2]
Marketable Securities Fair Value 12 Months or Longer	4,067	[1]	7,388	[2]
Marketable Securities Unrealized Losses 12 Months or Longer	(372)	[1]	(446)	[2]
Marketable Securities Fair Value, Total	13,663	[1]	15,674	[2]
Marketable Securities Unrealized Losses, Total	(766)	[1]	(606)	[2]
Corporate Debt Securities
Financial Instruments and Investments [Line Items]
Marketable Securities Fair Value, Less than 12 Months	7,971	[1]	6,058	[2]
Marketable Securities Unrealized Losses Less Than 12 Months	(172)	[1]	(722)	[2]
Marketable Securities Fair Value 12 Months or Longer	2,092	[1]	2,307	[2]
Marketable Securities Unrealized Losses 12 Months or Longer	(172)	[1]	(228)	[2]
Marketable Securities Fair Value, Total	10,063	[1]	8,365	[2]
Marketable Securities Unrealized Losses, Total	(344)	[1]	(950)	[2]
Equity Securities
Financial Instruments and Investments [Line Items]
Marketable Securities Fair Value, Less than 12 Months	2,760	[1]	3,584	[2]
Marketable Securities Unrealized Losses Less Than 12 Months	(167)	[1]	(344)	[2]
Marketable Securities Fair Value 12 Months or Longer	0	[1]	0	[2]
Marketable Securities Unrealized Losses 12 Months or Longer	0	[1]	0	[2]
Marketable Securities Fair Value, Total	2,760	[1]	3,584	[2]
Marketable Securities Unrealized Losses, Total	(167)	[1]	(344)	[2]
Institutional Funds-International Equity
Financial Instruments and Investments [Line Items]
Marketable Securities Fair Value, Less than 12 Months	22,945	[1]	22,454	[2]
Marketable Securities Unrealized Losses Less Than 12 Months	(110)	[1]	(768)	[2]
Marketable Securities Fair Value 12 Months or Longer	0	[1]	0	[2]
Marketable Securities Unrealized Losses 12 Months or Longer	0	[1]	0	[2]
Marketable Securities Fair Value, Total	22,945	[1]	22,454	[2]
Marketable Securities Unrealized Losses, Total	$ (110)	[1]	$ (768)	[2]

[1] Includes approximately 152 securities.

[2] Includes approximately 133 securities.

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Financial Instruments And Investments (Unrealized Holding Losses Included In Pre-Tax Income) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Financial Instruments And Investments [Abstract]
Unrealized losses included in pre-tax income	$ (352)	$ (338)	$ 0

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Financial Instruments And Investments (Marketable Securities Fair Value and Unrecognized Gross Unrealized Gains) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Gross Unrealized Gain	$ 38,667	$ 38,366
Marketable Securities Fair Value, Total	144,628	140,096
Debt Securities
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Unrealized Gain Position, Fair Value	34,498	40,403
Available-for-sale Securities, Gross Unrealized Gain	1,256	1,274
Collateralized Mortgage Backed Securities
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Unrealized Gain Position, Fair Value	7,430	9,589
Available-for-sale Securities, Gross Unrealized Gain	319	438
U.S. Government Bonds
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Unrealized Gain Position, Fair Value	12,237	12,033
Available-for-sale Securities, Gross Unrealized Gain	138	136
Municipal Bonds
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Unrealized Gain Position, Fair Value	2,481	8,671
Available-for-sale Securities, Gross Unrealized Gain	144	332
Corporate Debt Securities
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Unrealized Gain Position, Fair Value	12,350	10,110
Available-for-sale Securities, Gross Unrealized Gain	655	368
Equity Securities
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Unrealized Gain Position, Fair Value	61,884	72,636
Available-for-sale Securities, Gross Unrealized Gain	34,066	37,001
Equity Mutual Funds
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Unrealized Gain Position, Fair Value	42,244	18,853
Available-for-sale Securities, Gross Unrealized Gain	3,345	91
Cash
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Gross Unrealized Gain	0	0
Cash | Held in trust Decommissioning Fund Investment
Financial Instruments and Investments [Line Items]
Cash	$ 6,002	$ 8,204

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Financial Instruments And Investments (Contractual Year For Maturity Of Available-For-Sale Securities ) (Details) $ in Thousands	Dec. 31, 2016 USD ($)
Municipal Bonds
Schedule of Available-for-sale Securities [Line Items]
Total	$ 16,144
2017	990
2018 through 2021	6,253
2022 through 2026	8,139
2027 and Beyond	762
Corporate Debt Securities
Schedule of Available-for-sale Securities [Line Items]
Total	22,413
2017	0
2018 through 2021	8,664
2022 through 2026	6,090
2027 and Beyond	7,659
U.S. Government Bonds
Schedule of Available-for-sale Securities [Line Items]
Total	61,868
2017	14,272
2018 through 2021	22,495
2022 through 2026	14,786
2027 and Beyond	10,315
Collateralized Mortgage Backed Securities
Schedule of Available-for-sale Securities [Line Items]
Total	19,448
2017	0
2018 through 2021	5
2022 through 2026	390
2027 and Beyond	$ 19,053

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Financial Instruments And Investments (Sale Of Securities And The Related Effects On Pre-Tax Income ) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Investment [Line Items]
Proceeds from sales of available-for-sale securities	$ 91,268	$ 102,567	$ 108,311
Gross realized gains included in pre-tax income	9,212	12,379	7,858
Gross realized losses included in pre-tax income	(1,220)	(927)	(508)
Gross unrealized losses included in pre-tax income	(352)	(338)	0
Net gains (losses) in pre-tax income	7,640	11,114	7,350
Net unrealized holding gains (losses) included in accumulated other comprehensive income	8,444	(2,906)	10,827
Net (gains) losses reclassified out of accumulated other comprehensive income	(7,640)	(11,114)	(7,350)
Net gains (losses) in other comprehensive income	$ 804	$ (14,020)	$ 3,477

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Financial Instruments And Investments (Company's Decommissioning Trust Funds And Investments In Debt Securities) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Decommisioning Fund Investments
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	$ 255,708	$ 239,035
Decommisioning Fund Investments | Quoted Prices In Active Markets For Identical Assets (Level 1)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	197,703	176,130
Decommisioning Fund Investments | Significant Other Observable Inputs (Level 2)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	58,005	62,905
Decommisioning Fund Investments | Significant Unobservable Inputs (Level 3)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	0	0
Debt Securities
Financial Instruments and Investments [Line Items]
Trading Securities	1,421	1,543	$ 1,653
Debt Securities | Quoted Prices In Active Markets For Identical Assets (Level 1)
Financial Instruments and Investments [Line Items]
Trading Securities	0	0
Debt Securities | Significant Other Observable Inputs (Level 2)
Financial Instruments and Investments [Line Items]
Trading Securities	0	0
Debt Securities | Significant Unobservable Inputs (Level 3)
Financial Instruments and Investments [Line Items]
Trading Securities	1,421	1,543
Debt Securities | Decommisioning Fund Investments
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	119,873	113,304
Debt Securities | Decommisioning Fund Investments | Quoted Prices In Active Markets For Identical Assets (Level 1)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	61,868	50,399
Debt Securities | Decommisioning Fund Investments | Significant Other Observable Inputs (Level 2)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	58,005	62,905
Debt Securities | Decommisioning Fund Investments | Significant Unobservable Inputs (Level 3)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	0	0
U.S. Government Bonds | Decommisioning Fund Investments
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	61,868	50,399
U.S. Government Bonds | Decommisioning Fund Investments | Quoted Prices In Active Markets For Identical Assets (Level 1)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	61,868	50,399
U.S. Government Bonds | Decommisioning Fund Investments | Significant Other Observable Inputs (Level 2)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	0	0
U.S. Government Bonds | Decommisioning Fund Investments | Significant Unobservable Inputs (Level 3)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	0	0
Collateralized Mortgage Backed Securities | Decommisioning Fund Investments
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	19,448	20,085
Collateralized Mortgage Backed Securities | Decommisioning Fund Investments | Quoted Prices In Active Markets For Identical Assets (Level 1)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	0	0
Collateralized Mortgage Backed Securities | Decommisioning Fund Investments | Significant Other Observable Inputs (Level 2)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	19,448	20,085
Collateralized Mortgage Backed Securities | Decommisioning Fund Investments | Significant Unobservable Inputs (Level 3)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	0	0
Municipal Bonds | Decommisioning Fund Investments
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	16,144	24,345
Municipal Bonds | Decommisioning Fund Investments | Quoted Prices In Active Markets For Identical Assets (Level 1)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	0	0
Municipal Bonds | Decommisioning Fund Investments | Significant Other Observable Inputs (Level 2)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	16,144	24,345
Municipal Bonds | Decommisioning Fund Investments | Significant Unobservable Inputs (Level 3)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	0	0
Corporate Debt Securities | Decommisioning Fund Investments
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	22,413	18,475
Corporate Debt Securities | Decommisioning Fund Investments | Quoted Prices In Active Markets For Identical Assets (Level 1)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	0	0
Corporate Debt Securities | Decommisioning Fund Investments | Significant Other Observable Inputs (Level 2)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	22,413	18,475
Corporate Debt Securities | Decommisioning Fund Investments | Significant Unobservable Inputs (Level 3)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	0	0
Equity Securities | Decommisioning Fund Investments
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	64,644	76,220
Equity Securities | Decommisioning Fund Investments | Quoted Prices In Active Markets For Identical Assets (Level 1)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	64,644	76,220
Equity Securities | Decommisioning Fund Investments | Significant Other Observable Inputs (Level 2)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	0	0
Equity Securities | Decommisioning Fund Investments | Significant Unobservable Inputs (Level 3)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	0	0
Equity Funds | Decommisioning Fund Investments
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	42,244	18,853
Equity Funds | Decommisioning Fund Investments | Quoted Prices In Active Markets For Identical Assets (Level 1)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	42,244	18,853
Equity Funds | Decommisioning Fund Investments | Significant Other Observable Inputs (Level 2)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	0	0
Equity Funds | Decommisioning Fund Investments | Significant Unobservable Inputs (Level 3)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	0	0
Institutional Funds-International Equity | Decommisioning Fund Investments
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	22,945	22,454
Institutional Funds-International Equity | Decommisioning Fund Investments | Quoted Prices In Active Markets For Identical Assets (Level 1)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	22,945	22,454
Institutional Funds-International Equity | Decommisioning Fund Investments | Significant Other Observable Inputs (Level 2)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	0	0
Institutional Funds-International Equity | Decommisioning Fund Investments | Significant Unobservable Inputs (Level 3)
Financial Instruments and Investments [Line Items]
Available-for-sale Securities	0	0
Cash | Held in trust Decommissioning Fund Investment
Financial Instruments and Investments [Line Items]
Cash	6,002	8,204
Cash | Held in trust Decommissioning Fund Investment | Quoted Prices In Active Markets For Identical Assets (Level 1)
Financial Instruments and Investments [Line Items]
Cash	6,002	8,204
Cash | Held in trust Decommissioning Fund Investment | Significant Other Observable Inputs (Level 2)
Financial Instruments and Investments [Line Items]
Cash	0	0
Cash | Held in trust Decommissioning Fund Investment | Significant Unobservable Inputs (Level 3)
Financial Instruments and Investments [Line Items]
Cash	$ 0	$ 0

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Financial Instruments and Investments (Reconciliation) (Details) - Debt Securities - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Fair Value in Investment in Debt Securities [Roll Forward]
Balance at January 1		$ 1,543	$ 1,653
Net unrealized gains (losses) in fair value recognized in income on debt securities still held	[1]	(122)	(110)
Balance at December 31		$ 1,421	$ 1,543

[1] These amounts are reflected in the Company's statements of operations as investment and interest income.

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Financial Instruments and Investments Transfers Between Levels (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value, Assets, Level 1 to Level 2 Transfers, Description	no	no
Fair Value, Assets, Level 2 to Level 1 Transfers, Description	no	no
Fair Value, Assets, Level 3 Purchases, (Sales), Issuances, (Settlements)	$ 0	$ 0

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Supplemental Statements of Cash Flows Disclosures Supplemental Statements of Cash Flows Disclosures (Details) - USD ($) $ in Thousands			12 Months Ended
		Jul. 06, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]
Interest on long-term debt and borrowing under the revolving credit facility			$ 69,990	$ 62,297	$ 54,792
Income taxes, net of refund			2,328	1,000	6,876
Sale of Interest in Four Corners Generating Station	[1]		27,720	0	0
Changes in accrued plant additions			4,789	(6,660)	7,314
Site Contingency [Line Items]
Asset Retirement Obligation			81,800	81,621	74,577	$ 65,214
Proceeds from sale of property, plant, and equipment			4,841	721	2,395
Four Corners Generating Station
Site Contingency [Line Items]
Property, Plant and Equipment, Disposals		$ 32,000
Asset Retirement Obligation		7,000
Mine Reclamation and Closing Liability, Noncurrent		19,500
Public Utilities, Property, Plant and Equipment, Amount of Disposal Adjustments		1,300
Proceeds from sale of property, plant, and equipment		$ 4,200
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grants of restricted shares of common stock			$ 1,236	$ 1,567	$ 3,025

[1] The Company sold its interest in Four Corners for approximately $32.0 million based on the book value as defined in the Purchase and Sale Agreement. The sales price was adjusted downward by $7.0 million and $19.5 million to reflect APS's affiliate assumption of the Company's obligation to pay for future plant decommissioning and mine reclamation expense, respectively. The sales price was also adjusted downward by approximately $1.3 million for closing adjustments and other assets and liabilities assumed by APS's affiliate. At the closing of the sale, the Company received approximately $4.2 million in cash, subject to post-closing adjustments.

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Selected Quarterly Financial Data (Unaudited) Selected Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2016		Sep. 30, 2016	[2]	Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Selected Quarterly Financial Data
Operating revenues	$ 188,037	[1]	$ 323,225	[1]	$ 217,865	[1]	$ 157,809	[1]	$ 176,902	[1]	$ 289,713	[1]	$ 219,508	[1]	$ 163,746	[1]	$ 886,936	$ 849,869	$ 917,525
Operating income (loss)	20,470		129,857		44,697		(163)		8,312		88,047		41,872		7,960		194,861	146,191	151,163
Net income	$ 5,656		$ 74,636		$ 22,284		$ (5,808)		$ 648		$ 56,740		$ 21,072		$ 3,458		$ 96,768	$ 81,918	$ 91,428
Basic earnings per share:
Net income (loss)	$ 0.14		$ 1.84		$ 0.55		$ (0.14)		$ 0.02		$ 1.40		$ 0.52		$ 0.09		$ 2.390	$ 2.030	$ 2.270
Diluted earnings per share:
Net income (loss)	0.14		1.84		0.55		(0.14)		0.02		1.40		0.52		0.09		2.390	2.030	2.270
Dividends declared per share of common stock	$ 0.310		$ 0.310		$ 0.310		$ 0.295		$ 0.295		$ 0.295		$ 0.295		$ 0.280		$ 1.225	$ 1.165	$ 1.105

[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.(2)For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2015 Texas Retail Rate Case until it received the PUCT Final Order on August 25, 2016. Accordingly, it reported in the third quarter of 2016 the cumulative effect of the PUCT Final Order which related back to January 12, 2016. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.

[2] For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2015 Texas Retail Rate Case until it received the PUCT Final Order on August 25, 2016. Accordingly, it reported in the third quarter of 2016 the cumulative effect of the PUCT Final Order which related back to January 12, 2016. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.